Energy facility siting in the Great Lakes coastal zone analysis and policy options : final report, January 14, 1977

[From the U.S. Government Printing Office, www.gpo.gov]

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January 14, 1977 HEENTER
Energy Facility Siting In
The Great Lakes Coastal Zone.
Analysis.And Policy Options

Great Lakes Basin Commission for
The Office Of Coastal Zone Management
National Oceanic And Atmospheric Administration
U. S. DEPARTMENT OF COMMERCE

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COASTAL ZONE
Final Report INFORMATION CENTER,
January 14, 1977

Energy Facility Siting In
The Great Lakes Coastal Zone:
Analysis And Policy Options

Prepared for
The Office of Coastal Zone Management
National Oceanic and Atmospheric Administration
U.S. DEPARTMENT OF COMMERCE

(Under Contract No. 6-35350)

And The Standing Committee on Coastal Zone Management,
Great Lakes Basin Commission

By The Staff of The Great Lakes Basin Commission:
Charles A. Job, Project Manager, Reed M. Bohne,
Robert H. Clemens, Thomas Gross, John R. Hall,
John A. Johansen, Williarn E. Skimin, David M. Staples,

(With the assistance of:
Gerald Kotas, Jonathan Mayer, and Timothy Monteith)

COASTAL ZONE
INFO&VATION CENTER

TABLE OF CONTENTS

Page

LIST OF TABLES . . . . ... . . . . . . . . . . . . . . . . . . . . . . . . xi

.LIST OF FIGURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xv

PREFACE . . . . . . . . . . . . . ... . . . . . . . . . . . . . . . . . . xvii
ACKNOWLEDGEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xix
EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

INTRODUCTION . . . . . ... . . . . . . . . . . . . . . . . . . . . ... . . 13
A. State and Federal Activities Affecting Energy Facility Siting 14
B.- Concern of the Great Lakes States Coastal Zone Management Programs
for Energy Facility Siting . . . . . . . . . . . . . . . . . . . . . . 15
C. Development of the Study . . . . . . . . . . . . . . . . . . . . . . . . 15
D. Organization and Functions . . . . . . . . . . . . . . . . . . . . . . 17
E. Limitations of the Study . . . . . . . . . . . . . . . . . . . . . . . 18

F. Important Facts and Definitions . . . . . . . . . . . . . . . . . . . 19

G. Policy Options and Their Application 21
H. Additional Application of the Report . . . . . . . . . . . . . . . . . 22

INSTITUTIONAL CONSIDERATIONS . . . . . ... . . . . . . . . . . . 27

A. Introduction . . . . . . . . . . . . . . . . . . . . . . . . ... . . . 27@
1. Purpose . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
2. Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
B. Energy Facility Siting Regulation . . . . . . . . . . . . . . . . . . 28

1. Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 28

a. Coastal Zone Management Act (CZMA) . . . . . . . . . . . . . . 28
b. National Environmental Policy Act . . . . . . . . . . . . . . 40
c. Nuclear Regulatory Commission . . . . . . . . . . . . . . . . 42
d. Environmental Protection Agency . . . . . . . . . . . . . . . 44

e. Federal Power Commission . . . . . . . . . . . . . . . . . . . 59

f. Corps of Engineers . . . . . . . . . . . . . . . . . . . . . . 60
g. Federal Aviation Administration . . . . . . . . . .. . . . . . 61

h. Coast Guard . . . . . . . . . . . . . . . . . . . . . . . . . 61

i. Federal Energy Administration . . . . . . . . . . . . . . . . 61

2. Great Lakes States . . . . . . . . . . . . . . . . . . . . . . . . 62

a. Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

b. Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

c. Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Table of Contents (Continued)

Page

d. Minnesota . . . . . . . . . . . . . . . . . . . . . . ... . . 70

e. New York . . . . . . . . . . . . . . . . . . . . . . . . .. . . 72

f. Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

g. Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . 86

h. Wisconsin 89

3. Other Coastal States . . . . . . . . . . . . . . . . .. . . . . . . 91

a. California . . . . . . . . . . . . . . ... . . . . . . . . . . 91

b. Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

c. Maryland . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
d. Massachusetts . . . . . . . . . . . . . . . . . . . . . . . . 99
e. Oregon . . . . . . . . . . . . . . . . . . . . . . . 102
f. Washington . . . . . . . . . . . . . . . .. . . . . . . . . . . 106
4. Comparative Analysis of State Programs . . . . . . . . . . . . . . 107
a. Selected Features of State Programs . . . . . . . . . . . . . 107
b. Evaluation Criteria . . . . . . . . . . . . . . . . . . . . . 113

5. Implications for Policy Options . . . . . . . . . . . . . . . .. . 116

IV. TECHNICAL CONSIDERATIONS

A. Environmental and Economic Factors Affecting the Siting of Energy
Facilities and Analysis of Coastal Dependence of Facilities . . . . . 119

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

a. Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . 119
b. Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119
C. Study Approach . . . . . . . . . . . . . . . . . . . . . . . . 119
d. Definition of Coastal Dependency . . . . . . . . . . . . . . . 120
2. General.Siting Considerations . . . . . . . . . . . . . . . . . . 120
a. System Planning . . . . . . . . . . . . . . . . . . . . . . . 121
b. Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121
C. Engineering . . . . . . . . . . . . . . . . . . . . . . . . . 121
d. Environmental . . . . . . . . . . . . . . . . .... . . . . . . 121
e. Institutional/Regulatory . . . . . . . . . . . . . . . . . . . 122
f. Economics 122
3. Facility Descriptions and Siting Requirements . . . . . . . . . . 122

Table of Contents (Continued)

Page
a. Fossil Fuel (Coal) Power Plants . . . . . . . . . . . . . . . 122
(1) Description . . . . . . . . . . . . . . . . . . . . . .. . 122
(2) Site Requir-ements . . . . . . . . . . . . . . . . . . . . 123
(a) Land Requirements
(b) Location with Respect to Population
(c) Water Requirements
(d) Transportation Access
.(e) Seismology and Geology
(f) Hydrology and Meteorology
(3) Environmental and Other Considerations . . . . . . . . . 135
(4) Emerging Technologies . . . . . . . . . . . . . . . . . . 136
b. Nuclear Power Plants . . . . . . . . . . . . . . . . . . . . . 143
(1) Description . . . . . . . . . . . . . . . . . . . . . . .. 143
(2) Site Requirements . . . . . . . . . . . . . . . . . . . . 145
(a) Land Requirements
(b) Location with Respect to Population
(c) Water Requirements
(d) Transportation Access
(e) Seismology and Geology
(f) Hydrology and Meteorology
(3) Environmental and Other Considerations . . . . . . . 158
,(4) Emerging Technologies .. . . . . . . . . . . . . . . . . . 159
c. Fuel Transshipment and Storage Facilities . . . . . . . . 160
(1) Facility Types . . . . . . . . . . . . . . . . . . . ... 162-
(a) Coal
(b) Oil
(c) Nuclear Fuel
(2) General Considerations . . . . . . . . . . . . . . . . . 165
(a) Systems Requirements
(b) Safety
(c) Engineering
(d) Environmental
(e) Institutional
(f) Economics

Table of Contents (Continued)

Page

. . . . . . . . . . . . . . . . . . . . . . . . . . 167
(1) Description . . . . . . . . . . . . . . . . . . . . . . . 167
(2) Site-Requirements . . . . . . . . . . . . . . . . . . . . 167
(a) Land Requirements
(b) Location with Respect to Population
(c) Wate r Requirements
(d) Transportation Access
(e) Seismology and Geology
(f) Hydrology and Meteorology
(3) Environmental and Other Considerations 174
(4) Summary . . . . . . ... . . I . . . . . . . . . . . . . . . 175
4. Environmental and Economic Impact Analysis . . . . . . . . . . . . 175
a. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . 175
(1) Framework Approach . . . . . . . . . . . . . . . . . . . 175@
(2) FacilIities Activities . . . . . . . . . . . . . . . . . . 176
(3) Impacted Envi ronments . . . . . . . . . . . . . . . . . . 182
(4) Application .@ . . . . . . . . . . . . . . . . . . . . . . 185
b. Energy Facility Construction . . . . . . . . . . . . . . . . . 186
(1) Natural Environment . . . . . . . . . . . . . . . . . . . 186
(2) Cultural Environment . . . . . . . . . .. . . . . . . . . 189
C. Operating Impacts . . . . . . . . . . . . . . . . . . . . . . 202
(1) 'Fossil Fuel (Coal) Power.Plants . . . . . . . . . . . . . 204
(2) Nuclear Power Plants . . . . . . . . . . . . . . . . . . 219
(3)''Coal Transshipment and Storage . . . . . . . . . . . . . 232
(4) Oil Transshipment and Storage . . . . . . . . . . . . . . 235
(5) Refineries . . . . . . . . . . . . . . . . . . . . . . . 238
5. Facil ity Cost Analysis . . . . ... . . . . . . . . . . . . . . . . 242
a. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . 242-
b. Fossil Fuel (Coal) Power Plants . . . . . . . . . . . . . . . 242
(1) Fuel Transportation and Storage . . . . . . . . . . . . . 242
(2) Cooling Systems . . . . . . . . . . . . . . . . . . . . . 251
(3) Electrical Transmission System . . . . . . . . . . . . . 258
(4) Land . . . . . . . . . . . . . . . . . . . . . . . . . . 259
5) Environmental Controls . . . . . . . . . . . . . . . . . 262

vii

Table of Contents (Continued)

Page
c. Nuclear Power Plants 266

(1) Fuel Transportation and Storage 266
(2) Cooling Systems . . . . . . . . . . . . . . . . . . . . . 267
(3) Electrical Transmission Systems 269
(4) Land . . . . . . . . . . . . . . . . . . . . . . . . . . 271
(5) Environmental Controls . . . . . . . . . . . . . . . . . 271
d. Fuel Transshipment and Storage 272
(1) Introduction . . . . . . . . . . . . . . . . . . . . . . 272
(2) Land . . . . . . . . . . . . . . . . . . . . . . .. . . . 272
e. Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . 272
f. Facility Cost Discussion 273
Discussion of Coastal Dependence and Case Study . . . . . . . . . 279
7. Conclusions and Implications for Policy Options . . . . . 291
B. Energy Consumption and Movement in the Great Lakes Region . . . . . . 294
1. Introduction . . . . . . . . . . . . . . . . .. . . . . . . . . . . 294
2. Energy Demand . . ... . . . . . . . . . . . . . ... . . . . . . . 294
a. Fuels for Power Production . . . . . . . . . . . . . . . . . . 294

(1) Origin of Fuels . . . . . . . . . . . . . . . .. . . . . . 295
(2) Great Lakes States Production and Reserves . . . . . . . 299

(3) Present Fuel Mix . . . . . . . . . . . . . . . . . . . . 304
(4) Cost and Use by State and Region . . . . . . . . . . . . 307
(5) Transport of Fuels for Power Production . . . . . . . . . 308
b. Electricity . . . . . . . . . . . . . . . . . . . . . . . . . 314
(1) Power . . . . . . . . . . . . . . . . . . . . . . . . . . 314
(2) Population . . ... . . . . . . . . . . . . . . . . . . . 317
(3) Power Flows in the Coastal Zone . . . . . . . . . . . . . 319

3. Existing Facilities of Energy Supply . . . . . . . . . . . . . . . 322

a. Electrical Generation . . . . . . . . . . . . . . . . . . . . 322
(1) Types by State and Region . . . . . . . . . . . . . . . . 322
(2) Electrical Transmission . . . . . . . . . . . . . . . . . 324

b. Fuel Transshipment and Storage . ... . . . . . . . 326
(1) Facility Type and Size . . . . . . . . . . . . . . . . . 326
(2) Capacity . . . . . . . . . . . . . . ... . . . . .. . . . 332
(3) Demand . . . . . . . . . . . . . . . . . . . . . . . . . 335

Vill

Table of Contents (Continued)

Page
(4) Origins and Destinations of Fuels Handled . . . . . . . . 340
(5) Planned or Scheduled Facilities . . . . . . . . . . . . . 342

c. Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . 346

4. Planned or Scheduled Facilities for Electrical Generation 350

a. Types.by State and Region . . . . . . . . . . . . . . . . . . 350
b. Estimated Capacity Projected Demand . . . . . . . . . . . . . 354
c. Implications of Emerging Technologies . . . . . . . . . . . . 357

V. REGIONAL SCENARIOS OF ENERGY DEVELOPMENT . . . . . . . . . . . . . . . . . 361

A. Introduction to Scenario Approach . . . . . . . . . . . . . . . . . . 361
B. Description and Determin ants of Scenarios . . . . . . . . . . . . . . 363
1. Scenario I - Recent Trends . . . . . . . . ... . . . . . . . . . . 363
2. Scenario II High Coal Electric . . . . . . . . . . . . . . . . . 366
3. Scenario III High Nuclear Electric . . . . . . . . . . . . . . . 367
4. Scenario IV Applied Emergi ng Technologies 367
C. Introduction to Demand Projections . . . . . . . . . . . . . ... . . . 369
D. Review of Past Projections . . . . . . . . . . . . . . . . . . . . . . 371
1. Overviews of Available Projections . . . . . . . . . . . . . . . . 371
2. Analysis of Selected Projections . . . . . . . . . . . . . . . . . 374
3. Selected Growth.Rates for Projections . . . . . . . . . . . . . . . 376
E., Implications of Scenarios . . . . . . . . . . . . . . . . . . . . . . 377
F. Projected Generating Capacity and Resource Requirements . . . . . . . 379
G. Coastal Zone Resource Impact Analysis . . . . . . . . . . . . . . . . . 384
1. Relation of Projected Electrical Demand to Power Plants . . . . . 384
2. Relation of Projected Electrical and Fuel Demands to 387
Fuel Transshipment and Storage . . . . . . . . . . . . . . . . . .

VI. POLICY OPTIONS RELATED TO THE SITING OF ENERGY FACILITIES IN THE GREAT
LAKES COASTAL ZONE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 391
A, Introduction 391
B. Institutional Options . . . . . . . . . . . . . ... . . . . . . . . . 393
1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 393
2. Siting Policy . . . . . . . . . . . . . . . . . . . . . . . . . . 393
3. Organizational Structure and Arrangements . . . . . . 397
4. Functional Responsibilities . . . . . . . . . . . . . . . . . . . 401
5. Siting Procedures . . . . . . . . . . . . . . . . . . . . . . . . 406
6. Siting Criteria and Standards . . . . . . . . . . . . . . . . . . 409

Table of Contents (Continued)

Page
7. Financial Mechanisms . . . . . . . . . . . . . . . . . . . . . . . 414
8. Intergovernmental Relations . . . . . . . . . . . . . . . . . . . 418
C. Technical Options . . . . . . . . . . . . . . . . . . . . . . . . . . 424
1. Framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . 424
2. Description of Options . . . . . . . . . . . . . . ... . . .. . . . 425
a. Exclusion of All New Facility Development from the Coastal
Zone Management Area Including Access to Coastal Waters
and Related Fuel Transshipment . . . . . . . . . . . . . . . . 425
b. Exclusion of All New Facility Development from the Coastal
Zone Management Area, but Allowing Coastal Water Access,
Related Fuel Transportation, and Product Transmission
Through the Coastal Zone . . . . . . . . . . . . . . . . . . . 428
C. Inclusion of New Facility Development in the Coastal Zone
Management Area, Except in Designated Sensitive Areas in
Which Additional Development Would Be Precluded . . . . . . . 434
D. Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 443

VII. SUMMARY AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . . . . 445

A. Institutional Considerations . . . . . . . ... . . . . . . . . . . . . 445
B. Technical Considerations . . . . . . . .. . . . . . . . . . . . . . . . 446
1. Facilities Siting and Coastal Dependence . .... . . . . . . . . . . 446
2. Energy Consumption and Movement . . . . . . . . . . . . . . . . . 448
3. Regional Scenarios of Energy Development . . . . . . .... . . . . . 449
4. Other Considerations . . . . . . . . . . . . . . . . . . . . . . . 452

C. Policy Options . . . . . . . . . . . . . . . .. . . . . . . . . . . . . 453
D. Implications for,Further Research . . . . . . . . . . . . . . . . . . 453

APPENDICES . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . 459

A. Standing Committee on Coastal Zone Management . . . . . . . . . . . . 459
B. CZM Energy Project Steering Committee . . . . . . . . . . . . . . . . 461
C. CZM Energy Project Technical Advisors.. . . . . . . . . . . . . . . 462
D. CZM Energy Project Citizen Advisors . . . . . . . . . . . . . . . . . 466
E CZM Energy Project Staff . . . . . . . . . . . . . . . . . . . . . . . 467
F. Summary of Air Quality Effects of S02, Particulates, and N02 .. . . . . 468
G. Electric Generating Facilities in the Coastal Counties of the
Great Lakes . . . . . . . o . . . . . . . . . . . . . . . . . . . . . 472

ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 475

GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 477

REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 481

LIST OF TABLES

Table Page

1 National Ambient Air Quality Standards 46
2 Allowable Increments of Air Quality Deterioration . . . . . . . . . . . 48
.3 Major Permits Required for Power Plant Siting in Illinois 64
4 Major Permits Required for Power Plant Siting in Michigan 68
5 Major Permits Required for Power Plant Siting in Ohio 84
.6 1Major Permits Required for Power Plant Siting in Pennsylvania 87
7 Features of State Energy Facility Siting Programs . . . . . . . . . . . 108
8 Cooling Water Evaporation Losses . . . . . . /. . . . . . . . . . . . . . 132
9 Status, Number, and Capacity of Flue Gas Desulfurization Systems in the
United States . ... . . . . . . . . . . . . . . . . . . . . . . . . I . . . 142
10 Cooling System Land'Requirements . . . . . . . . . . . . . . . . . . . . 148
11 Required Cooling Water Flow Rates Across Condenser . . . . . . . . . . . 149'
12 Nuclear Power Plant Consumptive Water Use . . . . . . . . . . . . . . . . 150
13 Flows of Major Plant Systems . . . . . . . . . . . . . . . . . . 152
14 Expected Fuel and Waste Shipments for Fermi 2 .153
15 Refinery Land Requirement (Acres) 169
16 Refinery Cooling Water Requirements . . . . . . . . . . . . . . . . . . 171
17 Potential Environmental,Impicts Resulting from Construction Practices. 188
18 Work Force Profile: Nuclear Power Plants
190
19 Work Force Profile: Fossil Fuel (Coal) Power Plants . . . . . . . . . . 190
20 Work Force Profile: Refineries 191
21 Work Force Profile: Fuel Transshipment Facilities 191
22 Tax Payments During Construction of the Jim Bridger Power Plant . . . . 201
23 Construction Impact Summary . . . . . . . . 203
24 Summary of Fuel Cycle Impacts . . . . . . . . . . . . . . . . . . . . . 205
25 Summary of Coal-Fired Power Plant Air 'Emissions . . . . . . . . . . . . 207
26 Trace Element Emissions of a Coal-Fired Power Plant (1000 MWe) 208
27 Annual Liquid Effluent Activity for a 1000 MWe Reactor 223
28 Estimated Annual Radgas Effluents from a 1000 M4e.Reactor 226
29 Maximum Estimated Whole Body Dose at Site Boundary for a 1000 Mwe Plant. 229
30 Estimated Refinery Air Emissions 239
31 Estimated Waterborne Effluent Concentrations 240

xii

List of Tables (Continued)

Table Page

32 Miscellaneous Cost Comparisons . . . . . . . . . . . . . . . . . . 243

33 Costs of Coal Transportation . . . . . . . . . . . . . . . . . . . 246
34 Transportation Costs Per Ton of Delivered Coal . . . . . . . . . . 247
35 Short Haul Coal Transportation Costs . . . . . . . . . . . . . . . 250
36 Cooling System Efficiencies for 800 MWe Coal-Fired Plants . . . . 252
37 Estimated Costs of Two-Unit (1300 MWe Each) Coal-Fired Plant with
Alternative Cooling Systems . . . . . . . . . . . . . . . . . . . . 252
38 Comparison of Costs and Effects on Net Capability for 1200-We
Nuclear Generating Unit . . . . . . . . . . . . . . . . . . . . . 254
1
39 Operation Costs for Water Conveyance by Pipeline, by Distance,
and by Type of Facility -for a 1000 MWe Plant . ... . . . . . . . . 255
.40 Capital Costs of Water Pipelines for Cooling Water Supply . . . . 256
41 Cost of Providing Water to Coal-Fired Power Plant with 12.00 MWe
Capacity Sited Two Miles Inland . . . . . . . . . . . . . . . . . 257
42 Costs and Power Carrying Capabilities of Overhead Transmission
Circuits . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . 260

43 Summary of Total Average.Annual Revenue Requirements of Five
Leading Flue Gas Desulfurization Processes . . . . . ... . . . . . 263
44 Annual Shipments of Radioactive Materials to and from an Offshore
Nuclear Power Station (One 1100 MWe PWR) . . .. . . . . . . . . . . 267
45 Cooling Mode Effects on Nuclear Plant Efficiency . . . . . . . . 268
46 Cooling Mode Effects on Fossil/Nuclear Plant Operation . . . . . . 268
Estimated Costs of Two-Unit (1300 MWe Each) LWR Power Plant with
Alternative Cooling Systems . . . . . . . . .I . . . . . . . . . . . 269
48 Comparison of Costs and Effects on Net Capability for 1200 Mwe
Nuclear Generating Unit Using Alternative Cooling Systems . . . . 270
@49 Cost of Supplying Refined Products to the East Coast from Onshore
and Offshore Refineries . . . . . . . . . . . . . . . . . . . . . . 274

50 Facility-Cost Matrix . . . . . . . . . . . . . . . . . . . . . . . 275
51 Origin and Destination of Coal Deliveries to Electric Utilities
in 1975 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296

52 Primary Energy Purchase Data for Steam-Electric Plants During the
Past Twelve Months of 1975 . . . . . . . . . . . . . . . . . . . . 305
53 1975 Fuel Mix by Fuel Type for Power Generation . . . . . . . . . 307
54 Steam-Electric Fuel Figures . . . . . . . . . . . . . . . . . . . 309
55 U.S. Distribution of Energy Consumption by Fuel and by Sector . . .315
56 Contribution of Each Fuel to the Utility Sector . . . . . . . . . 316

xiii

List of Tables (Continued),

Table Page
57 Per Capita Power Generation . . . . . . . . . .. . . . . . . . . . . 317
58 Total and Per Capita Energy Consumption .. . . . . . . . . . . . . 317
59 Great Lakes States Population-by Coastal Zone . . . . . . . . . . 318
60 Power Generation by State . . . . . . ... . . . . . . . . . . . . . 323
61 Major Coal Shipping or Receiving Ports, 1974 . . . . . . . . . . . 329
62 Major Petroleum Shipping or Receiving Ports, 1974 . . . . . . . . 331
63 Potential GL/SLS Coal Movements . . . . . . . . . . . . . . . . . . 337
64 Projections of U.S. Great Lakes Shipments of Coal . . . . . . . . 338
65 Trend Projections of Great Lakes and St. Lawrence Seaway Shipments
of Crude, Petroleum and Selected Petroleum (1975-1985) . . . . . . @339
66 Bituminous Coal Shipments to U.S. and Canada from Lake Erie . . . . 340
67 Fuel Type, Origin and'Transportation for Fossil-Fuel Facilities
Scheduled Through 1985 . . . . . . . .. . . . . . . . . . . ... . .. 345

68 Barrels of Crude Oil Refined in Each Great Lakes State . ... . . . 347

69 Changes in Nuclear Unit Schedules During 1972-1975 . . . . . . . . 354
70 Planned or.Scheduled Additions in Generating Capacity in the
Coastal Zone, 1976 . .. . . . . . . . . . . . . . . . . . . . . . . 359
71 Planned and Scheduled Additions in Generating Capacity in the
Great Lakes Region . . . . . . . . . . . . . . . . . . . . . . . . 360
72 Major Assumptions-for Base Load Generation for the.Regional
Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364
73 Overview of Electric Power Projections . . . . . 372
74 New Generating Capacity Requirements for 1995 (in MW) . . . . . . . 379
75 1975 Fuel-Mix by Fuel Typefor Power Generation . . . . . . . . . 381
76 Additional Facilities Required Between 1975-1995 for Scenario I,.
Recent Trends ... . . . . . . ... . . . . . . . . . . . . . . . . . 382

77 Additional Facilities Required Between 1975-1995,for Scenario II,
High Coal Electric . . . . . . . . . . . . . . . ... . . . 383
78 Additional FacilitiesRequired Between 1975-1995 for Scenario III,
High Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . 384
79 Additional Resource Requirements of the Great Lakes States, 1975-
1995; Scenarios at 3% Per Year Growth Rate in Electrical Energy
Consumption . . ... . . . . . . . . . . . . . . . . . . . . . . . . 450
80 Additional Resource Requirements of the Great.Lakes Coastal.
Counties, 1975-105, Assuming a 3% Grow'th Rate in Electrical
Energy Consumption . . . . . . . . . . . . . . . 451

LIST OF FIGURES

Figure Page
A Map: Great Lakes Basin Dra inage Boundaries . . . . . . . . . . . . . . . 23
B Map: Great Lakes Region Political Boundaries . . . . . . . ... . . . . 24
1 Schematic of a Fossil Fuel (Coal) Power Plant . . . . . . . . . . . . 124
2 Cooling Water Requirements for Fossil and Nuclear Power Plants . . . . 129
.3 Alternative.Cooling System Configurations . . . . . . . . . . . . . . 130
4 Cross"Sectional Views of Three Cooling Devices . . . . . . . . . . . . 131
5 Schematic Diagram of a Combined Cycle Gas-Steam Generating Plant 140
6 Simplified Diagrams of Three Limestone/Lime Stack Gas Desulfurization
Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
7 Boiling Water and Pressurized Water Reactor Power Plant Schematics 144
8 Definition of Exclusion Area, Low Population Zoneand Nearest,
Population Center . . . . . . . . . . . . . . . . . . . . . . . . . . 143
9 Fermi 2 (Detroit Edison) Water Use Syst em. . . . . . . . . . ... . . . 151
10 Pathways of Radiation Through the Environment . . . . . . . . . . . . 158
11 High Temperature Gas Reactor . . . . . . . . . . . . . . . . . . . . . 161
12 Major Components of a Refinery . . . . . . . . . . . . . . . . . . . . 168
Major National Product Pipeline System . . . . . . . . . . . . . . . . 173
14 Generalized Potential Commuting Zone . . . . . . . . . . . . . . . . . 193
15 Effect of a Major New Facility on the Local Tax Base . . . . . I . . . . 199
16 Diagramatic Summary of Coal-Fired Power Plant Environmental Impacts. . 206
17 Fossil Fuel (Coal-Fired) Power Plant Matrix . . . . . . . . . . . . . 218a
18 Diagramatic Summary of Nuclear Power Plant Environmental Impacts . . . 220
19 BWR Radgas Control System . . . . . . . . . . . . . . . . . . . . . . 222
20 BWR Liquid Waste System . . ... . . . . . . . . . . . . . . . . . . . 224
21 PWR Radgas Control System . . . . . . . . . .. . . . . . . . .. . . . . 227
22 Pathways of Radiation through the Environment ... . ... . . . . . . . 228
23 Nuclear Power Plant Assessment Matrix . . . . . . . . . . . . . . . . 232a
.24 Coal Transshipment Facility Assessment Matrix . . . . . . . . . . . 234a
25 Fate of Oil in tbeMarine Environment . . . . . . . . . . . . . . . . 236
26 Oil Transshipment Facility Assessment Matrix . . . . . . . .. . . . . . 238a
27 Refinery Assessment Matrix . . . .. . . . . . . . . . . . . . . . . . . 240a
28 Distribution of United States Coal Resources . . . . . . . . . . . . 244
29 Transmission Line Capacities . . . . . . . ... . . . . . . . . .. . . . 261
30 Pleasant-Prairie.Power Plant, Preliminary Plant Layout . . . . . . . . 282

xvi

List of Figures (Continued)

Figure Page
31 Proposed Intake/Discharge Corridor . . . . . ... . . . . . . . . . 283

32 Pleasant Prairie Power Plant, Alternative Site Locations . . . . . 284

33 Examples of Great Lakes Shoreline Types . . . . . . . . . . . . . 289
34 Sources of Natural Gas Supply to the Great Lakes Basin States. 297
35 Sources of Crude Oil Supply to.the Great Lakes BAsin.States . . . 298
36 Projections of U.S. Great Lakes Coal Shipments . . . . . . . . . . 338
37 Weekly Load Curve . . . . . . . . . . . . . . . . . . . . . . . . 355

xvii

PREFACE

This study, Energy Facili.ty Siting in the Great Lakes Coastal Zone:
Analysis and Policy Options, can be described as fact-finding and brainstorming
in nature. It is fact-finding in that it surveys existing state and federal
policies affecting.energy facilities siting,@' examines specific types of energy
facilities and their dependence on coastal locations, and reviews projections of
energy use and related facility requirements. For this portion of the report,
tremendous amounts of information (over 150,000 pages of reports, documents and
correspondence, as well as phone calls and interviews) were summarized and
abstracted. The study is of a brainstorming nature in that the staff spent
substantial time evolving institutional and technical options for the siting of
energy.facilities,in the Great Lakes coastal zone..
The st udy was conducted by the Great Lakes Basin Commission staff over a
period of four months,.from July 6 through November 5, 1976. Guidance, sugges-
tions, and review comments were provided throughout the study by the project's
steering committee, technical advisors, and citizen advisors, by state coastal
zone program managers, and by the Office of Coastal Zone Management. This
assistance was gratefully received by the staff and was most important in helping
the staff complete the study on time.
The draft report was reviewed by the project's steering committee,
technical and citizen advisors, the state coastal zone management programs, and
the Office.of Coastal Zone Management. The review period ran from November 10 to
December 7, 1976. Comments received after the closing date.were,.also considered
in the preparation of this final report.
In,the course of the review,,general comments criticized the report from
two standpoints. First', some members of the energy industry indicated that the
report is somewhat biased toward environmental'concerns, whereas some environ-
mentalists suggested thatcertain portions-of the report are too biased in favor
of the energy industry. It.is the conclusion of the staff that the report takes

xviii

a middle ground that will serve the concerns of the state coastal zone manage-
ment programs well as they develop management plans to balance environmental and

economic considerations.

Second, some comments suggested that the report is too long and includes
information accessible elsewhere. (This is, in part, related to the broad scope
of the study.) On the other hand, a considerable number of comments indicated
that the report is very useful, because it synthesizes a tremendous amount of
diverse but related information under one cover. The coastal zone management-
programs, to which the report is directed, are probably best served by this
latter approach since their own resources are limited.
While a broad group of technical advisors from both the public and
private sectors-participated in the study through their review of and comment on,
preliminary material and the draft report, this should not be taken as an endorse-
ment of this final report by them. They served only as information providers,
advisors, and reactors.

xix

ACKNOWLEDGEMENTS

The Office of Coastal Zone Management, National Oceanic and Atmospheric
Administration, U.S. Department of Commerce, funded the Great Lakes Basin Commis-
sion to engage in this study on June 30, 1976, to provide assistance on a regional
basis to aid the Great Lakes states' coastal zone management programs in the
examination of energy facility siting and the development of related options.
The Great Lakes Basin Commission and staff appreciated the opportunity to under-
take this study for the Office of Coastal Zone Management and the eight Great

Lakes states.

The staff received tremendous assistance from the Steering Committee and
Technical Advisors of the study (listed in Appendices A.and B). Their efforts are
greatly appreciated. These people represent agencies and companies involved at all
levels of energy planning. The fact that the staff was able to complete the study
on time can in no small part be attributed to their efforts. In particular, the
he Argonne and Brookhaven
staff would like to acknowledge the expert assistance of t
National Laboratories, the Chicago regional office of the Federal Power Commission,
Mr. Owen Lentz, Executive Manager of the East Central Area Reliability Coordination
Agreement, and Mr. Julius Bleiweis, Executive Director of the Northeast Power
Coordinating Council.

Chapter I

EXECUTIVE SUMMARY

Concerned about energy facility siting in the Great Lakes coastal zone
and anticipating federal legislation to provide for planning of and amelioration
of the impacts from energy facilities, the Great Lakes states coastal zone man-
agement programs requested that the Great Lakes Basin Commission undertake this
study of energy facility siting and develop related policy options. The study
was funded by the Office of Coastal Zone Management, U.S. Department of Commerce,
and was conducted from July 6 to November 5, 1976.
The study examined the state and federal roles in energy facility siting
in orderto develop institutional and technical policy options which the Great
Lakes states might employ to influence or control energy facility siting, pri-
marily in their coastal zones. Coal-fired and nuclear power plants, fuel (coal
and oil) transshipment and storage facilities, and refineries were described
generally and their resource requirements examined. These resource requirements
were then applied to four regional electrical energy facility scenarios to
establish land, water, and fuel (coal) requirements for the period 1975-1995 for
a range of annual electrical energy consumption growth rates from 3% to 8% for
each of the Great Lakes states.and their respective tier of counties bordering
the Great Lakes.. These projections suggested the possible pressures on the
Great Lakes coastal zone for the development of energy facilities. This back-
ground provided the impetus for developing technical options for energy facility
siting.

A. INSTITUTIONAL CONSIDERATIONS

Institutional consideration3 address the legal, organizational, and

procedural aspects of energy facility siting and are distinguished from technical
considerations. The analysis of institutional considerations provides a means
for comparing and evaluating state energy facility siting programs and describes
the federal role and the constraints it imposes on the states and the opportu-

nities it provides.

1. FEDERAL ENERGY FACILITY STTING REGULATION
Several federal agencies exert a considerable amount of influence on
energy facility siting. The Nuclear Regulatory Commission has licensing authority
for nuclear power plants. The Federal Power Commission regulates the siting of
non-federal hydroelectric power plants (including dams and pumped storage facil-
ities) and the interstate sale of ele-ctricity and natural gas. The Environmental
Protection Agency exerts a great deal of influence on energy facility siting by
administering two federal acts. The Clean Air Act (CAA) established National
Ambient Air Quality.Standards (NAAQS) and performance standards for new sta-
tionary sources of pollution. These must be met by all energy facilities. The
CAA also provides for the prevention of significant deterioration of air quality
.that exceeds the NAAQS. The Federal Water Pollution Control Act Amendments of
1972 provide for the regulation of water pollution from various sources, including
energy facilities. In particular, regulations governing thermal di@charges,
cooling water intake structures, and certain chemical constituents are signifi-
cant in energy facility siting,decisions. The U.S. Coast Guard and the U.S.
Army Corps of Engineers are concerned with dischargeg and physical obstructions
to waterways, and the Federal Aviation Administration is concerned with similar
infringements upon air traffic routes.
Two federal laws also affect energy facility siting: the National-
Environmental Policy Act of 1969 (NEPA), and the Coastal Zone Management Act of
1972 (CZMA) and its Amendments of 1976. The CZMA encourages states to develop
plans for managing their coastal zones and provides funding for such planning
and subsequent management. State plans, once approved, become formal documents
requiring enforcement by the state, and all federal actions affecting the
coastal zone must be consistent with these plans. In particular, the Great Lakes
states, under the 1976 amendments, must develop a planning process for energy
facilities located in or significantly affecting the coastal zone, and are
eligible for grants to study and plan for any economic, social, or environmental
consequences resulting from siting, construction, expansion, or operation ofall

types of energy facilities in or affecting the coastal zone. The states are also
eligible for grants to assist them in preventing, reducing, or ameliorating the
loss of valuable environmental or recreational resources resulting from the
transportation, transfer, or storage of oil, natural gas, or coal in or through

the coastal zone. The inclusion of these elements in the.Great Lakes states

coastal zone management programs provides the basis for energy facility siting
programs for the Great Lakes coastal zone. This is particularly significant for
the states that have not already established energy facility siting programs on
a statewide basis. In recognition of the different-institutional arrangements
in each state, the Act provides latitude for the organization of the coastal'
zone energy facility planning process in each state. The National Environmental
Policy Act requires environmental impact statements for all major federal activ-
ities (including issuance of licenses and permits) that significantly affect the
environment. This promotes the environmental compatibility of all energy facility
siting, both within -and outside the coastal zone.

2. STATE ENERGY FACILITY SITING REGULATION

Of the eight Great Lakes states, New York, Ohio, Wisconsin and Minnesota
have recently enacted legislation to regulate the siting of power plants and
other energy facilities. Minnesota has placed siting responsibility with its
Environmental Quality Council. The council has established.criteria for.the
selection of suitable sites and is compiling an inventory of specific sites from
which utilities may select. The Wisconsin statute serves to streamline the site
certification process by concentrating responsibility for the various aspects of
siting in the Department of Natural Resources and the Public Utilities Commission.
Both New York and Ohio have established energy facility siting councils composed
of the heads of several pertinent state agencies. All four states have established
site certification application procedures and provide for the public disclosure
of long-range utility plans, for public participation inthe siting.process and
for mechanisms to finance the regulation of energy facility siting. However,
none of these states address all types of energy facilities in their siting pro-
grams. The facilities that are.not addressed in the siting programs are covered
by applicable environmental protection programs.
The remaining four.states (Illinois, Indiana, Michigan and Pennsylvania)
rZ@ly on general programs for environmental protection, and public utility regula-
tion for any control they exercise over facility siting. These states generally

require that a utility obtain several permits from various state agencies.
Emphasis in these states is on compliance of proposed energy facilities with
applicable standards afid guidelines for protection of air, water, and other
resources. In general, the larger range of siting issues are not addressed in
a comprehensive, coordinated manner. There are no provisions for the disclosure
of long-range utility plans in these states, and opportunities for public par-
ticipation are generally less than in the other four states.
Several coastal states outside the Great Lakes Region (Maine, Maryland,
Massachusetts, Washington, Oregon, and California) were selected for investiga-
tion in this study because of their unique energy facility siting programs. The
approaches used in these states include: regulation of any large land develop-
ment project, maintenance of state-purchased energy facility land reserve,
inclusion of all types of energy facilities in a siting program, and active
encouragement of public participation in the siting process.
State officials And other interested persons are encouraged to carefully
compare and evaluate the various state energy facility siting programs and the
ways in which CZM considerations are incorporated. The following criteria are
suggested by the staff, based on the review of extensive information concerning
energy facility siting, for use in such an evaluation:
e The program should provide for the resolution of conflifts among

intere sts and the identification of tradeoffs.

a . Theprogram. should be accountable to the public and responsive to
its needs and desires.

� The program should include an effective planning mechanism.
� The program should be coordinated with other energy and land use

programs.
0 Energy facility siting should provide tor regional needs.
:0, The program should specifically address the protection of the
environment, Iespecially in the coastal zone.
0 The program should facilitate provision of an adequate supply of

energy.
0 The program should be assured adequate funding and staffing.
0 'rhe program should be tlexible and adaptable.
0 The program should be politically feasible.
0 The program should be as streamlined as possible.

B. TECHNICAL CONSIDERATIONS

1. ENVIRONMENTAL AND ECONOMIC FACTORS AFFECTING THEBITING OF ENERGY
FACILITIES

Technical considerations--social, economic, and environmental-'and their
relationship to energy facility siting are reported in detail in the study. The
facilitiesexamined include fossil-fuel (coal-fired only) and nuclear power
plants, fuel (coal and oil) transshipment and storage facilities, and refineries.
General siting considerations affecting the location of these facilities include,
system planning, safety and reliability, engineering, environmental, institutional/
regulatory, and economic. A generalized facility size was established for each
facility type in order to present comparable resource requirements of the facil-
ities. For both fossil-fuel (coal) and nuclear power plants, a 1,000 megawatt
electrical output (MWe) capacity single unit plant was selected as the generalized
facility. The efficiency and annual average capacity assumed for these two types
of facilities are 38 percent and 65 percent respectively for fossil-fuel plants,
and 32 percent and 65 percent respectively'for nuclear plants. Refineries are
not described in "generalized facility" terms because oftheir complex production
systems reflecting particular product mixes. Fuel transsliipment and storage
facilities do not lend themselves to a generalized description because of their
range in size and uses.
The generalized 1,000 MWe coal-fired power plant is assumed in this study
to occupy from 145 to 2,500 acres, depending on the cooling system used, SO
x
waste disposal method, and coal storage requirements. An average land.require-
ment used for calculating future resource requirements.is 525 acres. Water
withdrawals can range from 9,300 gpm (21 cfsj to 800,000 gpm (1800"cfs), depending
on the cooling system used: once-through, natural draft tower, mechanical draft
tower, spray canal, or cooling pond.
Water consumed in the cooling process is also a major consideration in
power plant location because the amount of water returned to a water body may be
significantly less than the amount withdrawn, depending on the cooling system
used. Generally, for a once-through cooling system, water withdrawal is larger
(equaling the flow across the condenser), but the consumptive water use'is much
less than for closed-cycle systems.
For the generalized nuclear power plant, 1,335 acres is the average land
area required. This figure,is much higher than that for coal-fired plants,
due in part to the requirement for an exclusion zone around the plant for the

protection of people and property from potential radioactive@@ emissions. Nuclear
power plants require significantly more water than do similar sized fossil-fuel
plants, due primarily to differences in thermal efficiency. A lower bound of
13,500 to 18,000 gpm (30 to 40 cfs) withdrawal rate with a consumptive use rate
of about 11,225 gpm (25 cfs) is not unreasonable for an efficient closed-cycle
system of 1000-MWe nuclear unit. A withdrawal rate of one million gpm (2230 cfs)
for'a once-through system with no significant consumptive loss provides an upper
bo und (assuming 150F temperature rise across the condenser). Even if closed-
cycle cooling were used for a nuclear or coal-fired plant of the generalized
size (or larger), there are few river locations in the Great Lakes Basin which
could provide a sufficient amount of water, given other environmental constraints.
Thus, the water source for these facilities would have to be the Great Lakes.

Other major factors affecting power plant siting include: location with
respect to population (important due to transmission line costs-, and aesthetics,
and for nuclear plants, due to safety and radiological considerations), transpor-
access, seismology and geology (particularly important for nuclear plants),
hydrology, meteorology, ambient air quality (particularly important for fossil
fuel plants), minimization of aquatic and terrestrial ecosystem impacts, and
public acceptance. Additional construction and operation effects and activities
of importance are described in the report (Chapter IV, Technical Considerations---
Environmental and Economic Impact Analysis).
The evaluation and determination of an energy facility's coastal depend-
ence or non-dependence must be conducted on a case-by-case basis to determine the

importance of a shoreline location for a given proposed energy facility. For a
power plant., a@large number of considerations must be evaluated, including, but
not limited to: land ownership, mode of fuel delivery, local meteorology and
dispersion patterns, aesthetics, potential land use conflicts, and transmission
line tie-in ability.
The coastal dependence of power plants can be summarized as follows:
:,* Facilities using once-through cooling must'be located on or near the
shoreline-because of substantial costs of transporting water inland by pipeline.
* Facilities using closed-cycle cooling (while drawing water from the
Great takes) are less dependent on locations on or near the shoreline than are
facilities using once-through cooling, assuming all other factors to be approxi-
mately equal. Site conditions will determine the type of closqd-cycle cooling
system used. However, the further inland a facility is located, the greater are

the construction (capital) costs for water provision and blowdown pipelines.
e For facilities using closed-cycle cooling, the cost of locating on
the shoreline versus the cost of locating inland are essentially trade-offs
between construction and operation costs for transmission lines, facilities for
watersupply and cooling, facilities for delivery and handling of fuels and other
supplies, and disposal of waste material.
Nuclear facilities require very large and massive components, which
in most cases rely on water access for delivery. However, rail or road corridors
of adequate width and load carrying capacity can be utilized for delivery Of
these components. If these rail or road corridors are not available to potential
inland sites, the location of nuclear facilities may be more dependent on shore-@-
line or near shoreline locations. In any event, field assembly is.becoming more
common, thus possibly negating some of this shoreline-water access dependence.
Otherwise, nuclear facility coastal dependence considerations would be those
listed in the previous item.
The coastal dependence of fuel transshipment and storage facilities and

refineries can be summarized as follows:
e Fuel (coal and oil) transshipment facilities (receiving or shipping
their commodities by water) must.locate near the shoreline,- althrough the related
storage areas do not have to be located on the shoreline. Storage area location
is highly dependent on industrial needs, future transportation requirements, and

onsite and offsite use of stored fuel.

e Refineries are not coastal dependent, but do need access to water for
processing and cooling. Refinery siting dependence based on water supply and
wastewater disposal considerations is decreasing due to increasing water recycling
practices. Air cooling is also decreasing refinery dependence on easy water
access. Refinery location decisions are increasingly becoming market oriented,
with decisions being made on a national basis, due to the existence of the national
product distribution pipeline.
Coal gasification and liquefaction facilities are not likely to be located
in the Great Lakes Basin, with the possible exception of low-Btu gasification
facilities which can be located at or near the site of use. Large goal gasifi-
cation and liquefaction facilities will have mine-mouth locations due to the
higher cost of transporting coal relative to the cost of transporting substitute
or synthetic natural gas (SNG).

2. ENERGY CONSUMPTION AND MOVEMENT

The Great Lakes Basin and states are net importers of fuels. It is
difficult-to determine whether the Basin is a net importer or exporter of elec-
tricity since this depends on temporal factors. It appears however that the
coastal counties in'most states (except Illinois) are net exporters of electricity.
Furthermore, significant intra-coastal county electrical flows occur, particularly
in areas around Milwaukee, Detroit, Toledo,,and Cleveland.
The combined planned and scheduled electrical energy generating capacity
for the entire Great Lakes states area through the mid 1980's is 74,067 MWe, with
19,433 MWe--or 23 new plants or plant additions--to be located in the Great Lakes
coastal counties,in the states of New York, Ohio, Michigan, Indiana, and Wisconsin.
New generating capacity is not planned or scheduled-to be in service by 1984 in
the coastal counties of Illinois, Minnesota or Pennsylvania. (A state-by-state
analysis is presented in Chapter VI, Technical Considerations--Energy Consumption
and Movement in the Great Lakes Region.) Of this 19,433 MWe of additional capac-
ity by the mid-1980's, 28 percent will be coal-fired (Michigan, New York and
Wisconsin), 12% will be oil-fired (Michigan and New York), and 60% will be nuclear
(Michigan, New York, Ohio, and Indiana).
Regional scenarios of energy development (principally electrical energy
generation) have been prepared. The scenarios are based on different fuel mix
assumptions due to the present uncertain conditions. The four scenarios with
their respective fuel mix assumptions are:
Recent trends--50% coal, 35% nuclear, 15% oil, gas and hydroelectric
High Coal--70/lo coal, 15% nuclear, 15% oil, gas, and hydroelectric
High Nuclea,r--45% coal, 45% nuclear, 10% oil, gas, and hydroelectric
a New Technologies--40-50% coal, 20-35% nuclear, 15-20% new technologies
(solar, wind, fluidized bed, etc.).
In developing regional resource requirements for land, water, and fuel,
(coal), these scenarios were applied to a range of electrical,energy demand,pro-
jections (3%/year, 5.5%/year, and 8%/year), an assumed mix of generating facilities
(75% base load, 20% intermediate load, and 5% peak load), and an assumed capac-
ity load factor .(65%). The resource requirements of the generalized facilities
(coal-fired and nuclear power plants) were then applied to these assumptions to
evolve the regional resource requirements of energy development.
For the purposes of this study a 3 percent growth rate per year in
electrical energy consumption was assumed to be a lower bound in projecting future

power plant development given uncertain circumstances. Actual growth in the
future may be considerably higher or somewhat lower. This 3% growth rate will
describe the minimum amount,of resources required to meet future electrical energy
consumption, as shown in the following.table:

ADDITIONAL RESOURCE REQUIREMENTS OF THE GREAT LAKES STATES, 1975-1995
SCENARIOS AT 3%/YEAR GROWTH RATE IN
ELECTRICAL ENERGY CONSUMPTION

Additional Scenarios
Requirements
(1975-1995) 1 11

Nuclear (units) 70 24 104
land (acres) 46,725 16,020 69,420
water (gpd)
once- through 1,008 x 10 8 346 x 108 1,498 x 10 8
closed-cycle 1,512 x 10 6 518 x 106 2,246 x 10 6
Coal (units) 40 96 12
land (acres) 16,000 38,400 .4,800
fuel (millions of tons per year) 80 192 24
water @(gpd)
8 8 8'
orice-through 403 x 10 963 x 10 121 x 10
closed-cycle 576 x 10 6' 1,382 x 106 173 x 106

The requirements in Scenario IV, New Technologies, are assumed to be about 80% of
those in Scenario I, Recent Trends, due to a postulated reduced dependence on more
conventional generation technologies.
Assuming an 8'10/year growth rate, Scenario I, Recent'Trends, projectsi@an
additional 238 nuclear units and 185 coal units needed, with land requirements
8
of 233,000 acres; water withdrawals of 5,292 x 10 gpd for once-through cooling
6
''or 7,805 x 10 gpd for closed-cycle cooling; and coal requirements of 370 million

tons per year.
For the Great Lakes coastal counties, the following general projected
resource requirements,(Assuming.a 50% coal/50% nuclear mix for additional capac-
ity between 1975 and 1995---an approximate average of the four scenarios) were
developed on the basis of an analysis of the scenarios and each state's energy
development:

ADDITIONAL RESOURCE REQUIREMENTS OF THE GREAT LAKES
COASTAL COUNTIES, 1975-1995,
ASSUMING A 3% GROWTH'RATE IN ELECTRICAL ENERGY CONSUMPTION

Additional Requirements
Generating Water Coal
Generating Capacity Land Withdrawals (gpm) (Millions of
State Units* (MWe) (Acres) Once- Closed Tons@per year)
Through Cycle

Illinois --- --- ---

Indiana --- --- --- --- --- ---
Michigan 11 11,000 5,870 9.3.5xlO6 137,500 11.0
Minnesota 1-2 1-2,000 1-2,000 0.9-1.7xlO 6 12-25,000. 2-4.0
6
New York 7 7,000 3,740 5.95xlO 87,500 7.0
Ohio 4 4,000 2,135 3.4xlO 6 50,000 4.0

Pennsylvania --- --- --- --- --- ---
Wisco nsin 8 8,000 4,270 6.8xlO 6 100,000 8.0

Coal and nuclear units, .assuming a 50% coal/50% nuclear mix, as nated above.
Does not include Bailly nuclear unit, Porter County, on site already containing
two coal-fired units.

If an 8% growth rate is assumed, the figures in the table above would
increase by a factor ranging from 2.0 to 4.8, depending on the state being examined.
This indicates that considerable pressure might be placed on the coastal counties
of Great Lakes Basin for electrical energy generation facilities.

C. POLICY OPTIONS

The policy options developed for this report fall into two categories:
institutional and technical. The institutional options are further classified
.into seven groups: siting policy, organizational arrangements,, functional respon-
sibilities, siting procedures, siting criteria, financial mechanisms, and inter-
governmental relations. The technical options address the types of energy facility
development that might be included or excluded from the coastal zone. Environmental,
economic and social considerations are included in both sets of options.

1. INSTITUTIONAL OPTIONS

Institutional options were derived from the study of existing state pro-

grams and of various proposals for improving such programs. Options for siting

policy describe several possible associations that the siting function may enter
into with respect to other functions and programs. Emphasis in these options is
on the possibilities for the primary orientation of the program. Options for
organizational structure and arrangements focus on the composition of agencies
responsible-for handling siting and related issues. The.options for functional
responsibilities address the means for accomplishing some of the tasks associated
with siting.
,Options for siting procedures deal with the'procedural requirements of
siting regulation that may be employed to meet the energy facility siting goa:ls,
policies and objectives of the states. Options for siting criteria and standards
are related to the options available to a siting program for the site selection
process. Options for financial mechanisms offer the states several options to
facilitate.the planned development.of energy. Options for intergovernmental
relations involve options for interaction and coordination between federal and
state agencies with responsibilities in energy facility siting.

2. TECHNICAL OPTIONS

The technical options related to energy facility siting and development
with regard to the coastal zone have been arranged-to provide a full range of
policy choices which-remain within the context of the Coastal Zone Management
Act. The three major groupings of options were selected as they relate to
jurisdictional decisions. They are:
Exclusion of all new facility development in the.coastal zone manage-
ment area, including access to coastal waters and fuel transportation. This option,
however, is precluded under the Coastal Zone Management Act.
0 Exclusion of all new facility*development in the coastal zone manage-
ment area, but allowing access to coastal waters and fuel transportation.
0 Inclusion of new facility development in the coastal zone management area.
Throughout the development of these options it was assumed that all present
and anticipated environmental controls will be operative as a minimum requirement
and.that the presently stated guidelines of the Coastal Zone Management Act will
be followed in the development of the state CZM programs. The first major option,
that of excluding facility development including access to coastal waters and fuel
transshipment, discusses economic and environmental'implications arising from such
� pol icy. This policy would significantly affect lake movement of fuel and shift
� greater demand to inland modes of transportation. Many of the technical spin-offs

of such a policy relate to the resultant shift in transportation and the develop-
ment of energy production technologies requiring less water. The second major
technical policy option excludes new facility development in the coastal zone
management area but allows access to coastal waters, and fuel transshipment and
pro duct transmission through the coastal zone. It was felt that this option would
be more realistic under the guidelines of the Coastal Zone Management Act because
the exclusion of facilities from coastal resources would not be complete. A
number of suboptions were developed within this policy examining various methods of
implementation relating to fuel delivery, provision of cooling water, and develop-
ment of corridors for transmission of products such as electricity and oil back

into the coastal zone.

The final set of options considers inclusion of new facility development
in the coastal zone management area. Suboptions address specification of critical
areas, development areas, and buffer control zones; the encouragement of dispersed
siting; limitations-on expansion or reconstruction; location in proximity to
existing power grids or near transshipment facilities; maintenance or increase of
public access to the shoreline, permitting shoreline use for energy facilities;
setback distance for energy facilities; permitting shoreline use only bythose
facilities absolutely requiring shoreline location; designation of coastal
development priorities.to energy facilities; priority use for facilities employing
by-product utilization; multiple use/single site development; and specification of
type and size of facility allowed to site in the coastal zone.
These options were developed to provide a broad-range of policy choices
,that are feasible within present technical capabilities. The technical options
were not constrained by existing policies, so it was possible to consider a number
of innovative options that remain reasonable possibilities.
The energy growth rates used in this study do notaffect the particular
options that might be chosen from the range of options developed. The growth rate
of energy consumption in each state or substate-region would serve to suggest:
how much emphasis a particular state should place on developing an energy facility
siting program; how comprehensive that program could be in terms of facilities and
fuels; what the areal extent of the program jurisdiction should be; which levels

of government should be involved with the program; what involvement the coastal
zone management program might have in.such a program; and what authorities and
sanctions should be' vested in the program.

Chapter II

INTRODUCTION

In the Great Lakes Region, people have become increasingly concerned
about the uses to which the coastal areas have been and will be put. Future
energy development in the Great Lakes coastal zone is of substantial importance
to these people and to their governments, acting as resource trustees and man-
agers for present and future generations. In response to public concern and to

the Coastal Zone Management Act of 1972, each of the Great Lakes states is
developing a coastal zone management program charged to balance economic and
environmental considerations affecting coastal'areas and their waters.

The Coastal Zone Management Act recognizes both the economic and
environmental significance of the coastal areas. It highlights the necessity
of preserving certain areas from degradation and developing others. Growing
concern about the impacts of energy development, particularly on the coastal
areas, gave birth to the Coastal Zone Management Act Amendments of 1976. A
major provision in these amendments grants funds to coastal states and local
governments to offset the adverse economic and environmental effects of de-
veloping outer-continental-shelf oil and gas. Although this does not apply to
the Great Lakes, other provisions in the amendments promote energy facilities
study and planning, interstate coordination and mitigation of impacts from the
development of major@ fuel transportation and storage facilities. The energy,
facilities study and planning grants for which the Great Lak Ies state coastal
zone management programs are eligible apply to study and planning for facilities
in the coastal zone such as coal-fired and nuclear electrical generating facil-
ities, refineries, fuel transshipment and storage facilities, and potential
coal gasification and liquefaction plants.

A. STATE AND FEDERAL ACTIVITIES AFFECTING ENERGY'FACILITY SITING

Many state and.federal agencies are responsible for energy development
and energy-related environmental programs in -the Great'Lakes Region. Each of
the Great Lakes states has a public service or public utilities commission,
which regulates the provision of electricity and gas and establishes rates for
these energy sources. Some states also have commissions or boards with author-
ity to monitor energy development and review proposed energy facilities. Each
of the Great Lakes'states has laws, regulations, policies, and/or .programs
affecting energy facility siting. New York and Ohio have had siting p.rograms
for several years. Minnesota and Wisconsin have,recently developed similar
programs. The remaining states are using other governmental mechanisms (de-
scribed in Chapter III) to address energy facility siting. As stated previously,
the coastal zone management programs of each state, established under the
Coastal Zone Management Act of 1972 (P.L. 92-583), must establish programs that
balance environmental and economic values in the management of their coastal
resources. Energy development highlights the trade-offs that must be made and
is an important factor in the development of these programs.
several federal agencies are involved in the siting of energy facilities.
The Nuclear Regulatory Commission is responsible for reviewing and licensing
nuclear facilities., The Federal Power Commission licenses hydroelectric
facilities and determines interstate gas rates. The Environmental Protection
,Agency monitors and regulates environmental pollutants from energy facilities
as well as from other types of plants. The Corps of Engineers is concerned
with energy facility structures placed in navigable waters.- The Federal Energy
Administration is responsible for establishing energy policies and the alloca-
tion of fuels. The Federal Aviation Administration oversees air transport of
nuclearIfuels. The Coast Guard is concerned with aids to navigation, adequate
and.safe navigation conditions, potential pollutants to the aquatic environment
of navigable waters, and potential obstacles to navigation. Furthermore, the
National Environmental Policy Act of 1969 specifies environmental considerations
that must be taken in federally funded, assisted, or licensed programs and
projects. This includes federal responsibilities in the area of energy facili-
ties and energy facility siting.

B. CONCERN OF THE GREAT LAKES STATES COASTAL ZONE MANAGEMENT PROGRAMS ABOUT
ENERGY FACILITIES SITING

The Great Lakes states coastal zone management programs participate on
the Great Lakes Basin Commission's Standing Committee on Coastal Zone Manage-
ment. This Committee was. formed to address opportunities, problems, and
concerns of mutual, interstate or regional interest relating to coastal zone

management.
In late 1975, the states were anticipating the passage of Section 308(c)
and (d)(4) of the Coastal Zone Management Act Amendments which would (and do)
provide grants to the Great Lakes and other coastal states for amelioration of
impacts from fuel transportation and storage facilities in the coastal zone and
for energy facilities planning. This p rovision appeared in both the House and
Senate versions of the bill. Ata meeting in late 1975, the Great Lakes coastal
zone programs caucused and identified energy facility siting as an area in which
they felt they would like to have additional support in developing their pro-
grams. As a result, the Commission staff developed a proposal for the Standing
Committee on Coastal Zone Management to study energy facility siting policies
and programs as well as projections and trends of energy use in the Great Lakes
Region., The Great Lakes states indicated that, as their programs were up for
approval within the next 12 to 18 months, they required immediate input in this
important area, and asked the staff to revise the proposal to focus specifically
on energy facility siting policies at the state and federal level, future re-
gional energy developments, and policy options for the siting of energy facilities
in the Great Lakes coastal zone. They also requested that the study be shortened
from nine to four months at considerably reduced funding. As a result, the
staff prepared a new proposal, which was approved by the Standing Committee on
Coastal Zone Management in April, 1976, and was funded for approximately $53,760
by the Office of Coastal Zone Management on June 30, 1976. The study began on
July 6, 1976, and was conducted over a four month period.

C. DEVELOPMENT OF THE STUDY

The objectives of the study were the examination of energy trends and
the coastal dependence of energy facilities and the development of a full range

of policy options for the siting of energy facilities in the.Great Lakes
coastal zone. A by-product of the study was the development of a facility
activity impact matrix which can be used by the Great Lakes coastal zone pro-
grams in evaluating future proposed facilities for the coastal zone. Also,
scenarios were developed, based on a range of energy growth rates forthe region.
These scenarios present their assumptions and related energy developments along
with resource requirements to 1995, thus indicating the likely pressures on
the coastal zone for various types of facilities. Finally, state and federal
policies and programs related to energy facility siting were reviewed and
summarized, and a comparative analysis of these programs is presented.
Once the Standing Committee on Coastal Zone Management approved the pro-
posal, it established a steering committee for the project. The steering com@
mittee was composed of representatives from the states of Wisconsin, Ohio,
Pennsylvania, and Michigan, and from the federal agencies of the Department of
the Interior, the Environmental Protection Agency, the Department of Transpor-
tation, and the Department of Commerce. Members of the steering committee are
listed in Appendix B. Theproposal also indicated that a group of technical
advisors would be formed to advise the study staff on technical matters., The,
project manager asked the steering committee to identify persons who would be
available and qualified to serve as technical advisors. Additional technical
advisors were identified and added as the study proceeded. These persons are
listed in Appendix C.
After the funding was approved for the study, the steering committee
met, and the project manager pr esented a lengthy listlof energy facilities which
..c,o.uld.be examined'in the.study. The steering committee reduced this list and
ranked them acco rding to their apparent importance to the Great Lakes coastal
zone. The facilities to be examinedi in order from first to third priority
are: (1) electrical energy generation (fossil-fuel and nuclear); (2) fuel
transshipment and storage; and (3) refining. Recognizing the time constraints
on the study, the steering committee indicated that if all types of facilities
could not be addressed,.then the staff should address first those at the top
of thelist, namely, electrical generating facilities.
During the course of the study, state and federal agencies and utili@y
companies and other industries having energy facili ties were continually
involved in the review of interim draft papers prepared.by the project's staff.
Furthermore, the technical advisors were consulted throughout the study and

provided tremendous assistance to the staff. After the first two months of
the study, the steering committee met to review its progress. On the advice
of the project manager, the steering committee indicated that the focus during
the study's last two months should be on electrical energy generation faciliti es
and fuel transshipment and storage facilities.

D. STAFF ORGANIZATION AND-FUNCTIONS

The principal areas of investigation in this study lent themselves to
three major assignments: (1) analysis of institutions, policies, and programs
concerned with energy facility siting; (2) analysis of coastal dependency and
the economic and environmental considerations in the siting of facilities;,,@nd
(3) analysis of the projections and trends and their relation to possible,
scenarios of energy development. Therefore,'the staff was organized into three
principal units: the policy tnit, the coastal dependence unit; and the pro-
jectiohs and trends unit. Two staff members served in the policy unit, three
staff members in the coastal dependence unit, and two in the projections and
trends unit. All persons were assigned according to their background and exper-
tise. In addition, other Commission staff members were utilized inthe study
as technical advisors. Commission staff committed to the study are listed in

Appendix D.
The policy dnit reviewed, summarized and analyzed the state and federal
policies, programs, legislation and regulations affecting energy facility
.Siting in the Great Lakes Region. They also examined programs of coastal states
outside the region. This unit also developed institutional policy options for

the siting of energy facilities.
The coastal dependence unit developed a matrix and an analysis approach
that can be utilized by the states in their assessment of proposed energy
facilities. This unit also described in.detail the major elements of the prin-
cipal types of energy facilities addressed in the study and their associated
resource requirements. Finally, it provided an analysis of the environmental
impacts, both natural and cultural, associated with facility construction and
operation and the major cost components of each facility type.
The projections and trends unit analyzed existing energy flows within
the region, particularly wit hregard to electricity and coal, and examined

projections and trends of future energy growth on the basis of its own analysis
and with the assistance of the technical advisors. It also developed scenarios
of energy development, given different.rates of growth and various assumptions
regarding fuel mix..
The coastal dependence unit and the projections and trends unit combined
their efforts to report the implications on resource requirements of the various
scenarios. In addition, these two units utilized their expertise to develop
technical policy options for the siting of energy facilities in the Great Lakes
coastal zone. These options incorporate the environmental and locational con-
siderations that have been reported in the study.

E. LIMITATIONS OF THE STUDY

As previously indicated, the study focused only on electrical energy gen-
erating facilities (fossil-fuel and nuclear), fuel (coal and.oil) transshipment
and storage facilities, and refineries. Thus, the scope of the study is some@
what narrow and is restricted to conventional technologies. -,
For the electric generating facilities, a generalized facility size was
used to discuss the possible effects on the resources of the coastal zone. The

principal reasons for this approach were:
The short time frame of the study did not lend itself to a discussion
of range of facility size.
e More importantly, the study attempted to examine facilities of the
size which were most likely to be constructed in the coastal zone.
A 1000-MW plant,was selected for fossil-fuel and nuclear facilities. The other
facility types investigated in this study did not lend themselves to a discus-
sion of generalized facilities. The facility sizes for electrical generation
mentioned above (or sizes very close to these) are cited.in the literature and
have been used in recent studies of facility types and their resource implica-
tions. Both larger and smaller facilities may be constructed depending on the
particular requirements of the service area. The generalized facilities also
enabled the staff to discuss from a general standpoint the possible resource
requirements of future facilities and the resultant pressures on the Great Lakes
coastal zone, a topic deemed very important to future management planning in the
Great Lakes coastal zone with respect to energy facilities.

Throughout the report, figures for costs, land areas, water volume.s,
and other(resources affected by the-siting of energy facilities have been.pre-
sented. This quantification has been provided wherever possible to give the
users of this report a base of reference for future comparisons. Whenever
possible, ranges of values for costs, land areas, or other resources were used
to.indicate not only the range of possible resource requirements but also to
suggest-that there are no@"hard" -or "firm" figures.
'Most cost figures in this report use the years 1974 through 1976 as a
base. This narrow range should give a good basis for comparison of facilities
proposed in the future. Caution should be:used when examining and using any of
the figures cited in the report; the figures will change quickly duo to infla-
tion and site-specific or geographic considerations. Thus, these figures should
be used to'discuss the relative, not absolute, magnitudes of effects or resource
requirements of the various facilities. In some cases, cost information was
difficult to obtain; in other cases, it varied so widelyas to be almost
entirely inconsistent. After consultation with technical advisors, the staff
did its best to determine an accurate estimate of these widely varying costs.
Every attempt was made to obtain cost information from both government and
industry sources so as not to-bias the information in one direction or the other.

F. IMPORTANT FACTS AND DEFINITIONS

Several points concerning the study should be made clear.
o The Great Lakes states, through their coastal zone management programs,,
have asked the Great Lakes Basin Commission staff to examine from a regional
standpoint the coastal dependency of energy facilities and the resource require-
ments.and pressures on the coastal zone from future energydevelopment.
o The results of the study are not binding, but only suggestive, and
will be used by each Great Lakds state as it sees fit for the development of
its own coastal zone management policies for the siting of energy facilities.
o The study examined the implications of coastal versus inland siting
of energy facilities and projections related to future energy facilities develop-
ment. The study was not undertaken with the intent of excluding facilities from
the coastal zone, but rather to provide the coastal zone management programs
with a general technical understanding of the relationships involved in

the siting of facilities. Furthermore, the Coastal Zone Management Act specif-
ically directs the states not to exclude from consideration facilities or uses

of the coastal zone which are of greater than local concern. This would
certainly apply to energy facilities.
e The definition of energy facilities for the purposes of this study
.includes facilities for electrical energy generation (fossil-fuel and nuclear),
fuel (coal and oil) transshipment and storage, and crude oil refining.
� The time.period,covered by the study is the next fifteen to twenty
years - to 1995.
� In discussions of inland versus coastal locations for energy facilities,
inland refers to a location generally one mile or more from the coastline, inland

to a distance approximated by the inland boundaries of the Great Lakes states
coastal counties. Coastal refers to general locations or sites on, or near (less
than one mile from) the shoreline of the Great Lakes.

e Coastal dependence refers to the determination of energy facility loca-
tion with respect to the shoreline of the Great Lakes. The following general
considerations aid this determination: system requirement, safety, engineering,
environmental, institutional, and economic. This definition broadens the analysis
beyond simple.dependence on the coast into a more ge neral examination of facility

location.

Other definitions essential for understanding the report are:
0 Coastal county--a county with frontage on one of the Great Lakes, their

connecting channels, or the St. Lawrence River;
* Coastal zone--an area adjacent to the shoreline, generally much
narrower and smaller in area than the tier of counties bordering the Great Lakes
and connecting channels;
e Coastal zone management area--the area along the Great Lakes shoreline
which is designated to come under the purview of the states' coastal zone manage-
ment plans. The lakeward extent of the management area reaches to the inter-
national or state boundary, as appropriate. The landward extent of the manage-
ment area is generally a narrow strip of land, defined differently by each state
(some Great Lakes states have not yet firmly Specified an inland management
boundary). Some activities (uses of or affecting land, air, water, etc.)
adjacent to or beyond the management area which affect or influence the manage-
ment area might also come under the jurisdiction of a state's coastal zone

,.management program.

G. POLICY OPTIONS AND THEIR APPLICATION

Institutional and technical policy options for the siting of energy
facilities in the coastal zone were developed by the staff. The institutional
options suggest possible institutional arrangements which might be used by the
states and their coastal zone management programs to enable them to better manage
the effects of energy facilities located in the coastal zone. Some institutional
options envision major reorganization; others suggest the use of existing
institutional arrangements. The situation in each state will dictate the kinds
of institutional options it might employ in planning for and managing the
effects of energy facilities sited in the coastal zone.
It, should be noted that these options are only suggestions. This study
and report have been undertaken with no intention of asserting that a particular
state or program should adopt any of the options proposed. The Great Lakes
states coastal zone management programs asked only that a full range of options
be developed for their consideration. As the state CZM program staffs examine
the options, they may identify additional options of a specific nature which
could be incorporated into their programs, but, due to the brevity of the study,.
could -not be developed for this report. Furthermore the selection of certain
institutional options will necessarily preclude other institutional options.
The second group of options, the technical options, were developed on
the basis of the technical, environmental, and economic research carried out for
the study. These options range from complete exclusion of energy facilities
from the coastal zone to the inclusion of energy facilities on shoreline loca-
tions. Some of these options may be unrealistic for some or all states. Some

of the technical options are mutually exclusive. The implications of each
option are described so that the state CZM pr.ograms will have an initial
understanding of their respective opportunities and problems.
The energy growth rates used in this study do not affect the particular
options that might be chosen from the range of options developed. The growth
rate of energy consumption in each state or sub-state region would serve to
suggest: how much emphasis a particular state might place on developing an
energy facility siting program; how comprehensive that program might be in
terms of facilities, fuels, and types of energy dealt with; what the areal
extent ofthe program jurisdiction should be; which levels of government should
be involved with the program; what involvement the coastal zone man agement pro-

gram might have in such a program; and what authorities and sanctions should be
vested in the program.

H. ADDITIONAL APPLICATION OF THE REPORT

The,Great Lakes states coastal zone management programs can merge the
information assembled in this report with information on energy requirements of
future industrial, commercial and residential development in their respective
coastal zones. Once these programs can estimate the expected energy demands of
industry and per capita residential use on an area-by-area basis, they can then
estimate the needed energy facilities and their related resource requirements.
Having better locational information for these facilities than is presently
available will permit more meaningful and informed coastal zone management
plans and decisions.
The study focuses only on the Great Lakes coastal zone of the eight states
of New York, Pennsylvania, Ohio, Michigan, Indiana, Illinois, Wisconsin, and
Minnesota. Thus, thelstudy does not-address energy facility siting or associated
policy opti ons for the Hudson River mouth, Long Island Sound, and Atlantic Ocean
portion of New York's coastal zone management program, nor the Delaware River-
Chesapeake Bay estuary element of Pennsylvania's program. Although some of the
information and policy options developed in this study could be useful in
addressing resource management problems for these other areas, the states and
their local levels of government will have to decide on the degree of applicabil-
ity. With respect to projections of electrical energy consumption and associated
resource requirements for the states of Pennsylvania and New York, only the north-
west corner of Pennsylvania and upstate New York were considered. Maps of the
Great Lakes basin and counties appear as Figures A and B.
Exact figures of energy facility cost and resource requirements are
difficult, if not impossible, to arrive at. However, ranges of costs and
resource requirements have been assembled in this report and are intended to be
used to obtain a rough estimate of the magnitude of effects associated with energy
facilities and to extrapolate estimates of future resource requirements of energy
'facilities and the possible pressures on the Great Lakes coastal zone.
The policy options in this report suggest possible approaches to the
planning for and management of the effects of energy facility development in the
coastal zone. This study provides input for one particular aspect of coastal

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zone management. Its relation to other elements of the CZM program will hope-
fully be resolved by the sta Ites. Thus, this report is intended to be a tool to
assist the Great Lakes states coastal zone management programs and it is to
.them that it is directed. The report is not and never was intended to be a
definitive treatise on energy facility siting in the Great Lakes coastal zone.
While a broad group of technical advisors from both the public and pri-
vate sectors participated in the study by reviewing and commenting on preliminary
material and'the-draft report, this should not be taken as their endorsement of
this final report. They served only as advisors, reactors, and providers of
information. So that this point is well understood, it is restat ed at appropri-
ate places-in the report.

Chapter III

INSTITUTIONAL CONSIDERATIONS

A. INTRODUCTION

1. PURPOSE

This chapter addresses the institutional (legal, organizational And
procedural) aspects of energy facility siting, with emphasis on the Great Lakes
states and their coastal zones. Institutional aspects aredistinguished from
technical aspects, which are covered in the next chapter. The study of existing
institutions provides the means for comparing the various state programs and for
developing options for the states to consider in the context of federal programs
and requirements as well as other related state programs. In a broad sense, the
institutions associated with energy facility siting are primarily concerned with
the structure of government, the structure of the energy industry and the relation-
ship between them.

2. SCOPE

The first section describes federal legislation and agencies.that are
deemed to have significant impacts on energy facility siting. The most direct
federal involvement is found in the regulation of the siting of nuclear and certain
hydroelectric facilities, though other significant federal involvement,is possible,
especially in the area of environmental protection. For example, the U.S. Environ-
mental Protection Agency has retained authority over the issuance of water and air

permits.
Subsequent sections describe the energy facility siting programsin the
eight Great.Lakes states and those in other coastal states that provide examples
of unique and/or interesting approaches to the siting problem. Such features are
emphasized in the descriptions.
The final section provides a set of criteria which interested persons may
use to evaluate a state siting program. Several features of state programs are

described, and a table is provided to show how these features are addressed b y

each of the states.

B. ENERGY FACILITY SITING REGULATION

1. FEDERAL

The Congress has recently considered, but has not passed, legislation that
would specifically address energy facility siting. This leaves the federal gov-
ernment with a direct role in siting only in the case of hydroelectric generation
and nuclear energy facilities. However, several federal laws and regulations
affect siting less directly and involve a number of federal agencies in the process.
The Coastal Zone Management Act of 1972 as amended is of central importance to this
study and will be discussed first. Another federal statute, the National Environ-
mental Policy Act of 1969, established a major federal program with widespread
application and will thus be discussed separately. The remainder of the existing
federal legislation that significantly affects or is related to the siting of the
types of energy facilities under consideration in this study are discussed under
the appropriate administrative agencies.

a. Coastal Zone Management Act
The Coastal Zone Management Act (CZMA) of 1972 (P.L. 92-583) created a comprehen-
sive program to plan for and manage the nation's coastal areas. "The Act recognizes
that the coastal zone is rich in a variety of natural-, commercial, recreational.,
industrial, and esthetic resources of immediate and potential value to the present
and future well-being of the nation" [632]. The Act responds to the problem that
presentstate and institutional arrangements for planning and regulating land
and water uses in the coastal zone are often inadequate.to deal with the competing
demands and the urgent need to protect natural systems in the ecologically fragile
area" [6321.
Significant amendments to the Act (P.L. 94-370) were passed in 1976 that
(among other things) expanded the program to provide for increased planning and
management of energy development which affects the coastal zone.
The general institutional approach of the CZM program is one of providing
federal technical and financial assistance to coastal states to encourage them to
develop programs for the management of their coastal resources. The eight Great
Lakes states are currently developing coastal zone management programs pursuant

to the federal legislation. Of particular significance to this study are provisions
for establishing an energy facility planning process within the CZM programs of each

coastal state.

Subsection 305(b) of the Act as amended indicates thatthese programs must

include:

(1) an identification of the boundaries of the coastal zone
subject to the management program;
(2) a definition of what shall constitute permissib 'le land
and water uses within the coastal zone which have a direct,
and significant impact on the coastal waters;
(3) an inventory and designation of areas of particular
concern within the coastal zone;
(4) an identification of the means by which the state proposes
to exert control over the land and water uses referred to in
paragraph (2), including a listing of relevant constitutional
provisions, laws, regulations, and judicial decisions,;.
(5) broad guidelines on priority of uses in particular areas,
including specifically those uses of lowest priority;
@(6) a description of the organizational structure proposed
to implement the management program, including the responsibilities
of local, areawide, state, regional, and interstate agencies in
the management process,,
(7) a definition of the term "beach" and a planning process
for the protection of, and access.to, public beaches and other
public-coastal areas of environmental, recreational, historical,
esthetic, ecological, or cultural value;
(8) a planning process for energy facilities likely to be
located in, or which may significantly affect, the coastal
zone, including, but not limited to, a process for anticipating
and managing the impacts from such facilitiesi.
(9) a planning process for (A) assessing the effects of
,shoreline erosion .(howeve 'r caused), and (B) studying and
evaluating ways to control, or.lessen the impact of, such
erosion, and to restore areas adversely affected by such erosion.

Although the Great Lakes states are at different stages in the development
of their management programs, once they have-defined the inland management boundary(s)
of the coastal zone in their respective states and,the programs are approved by
the Secretary of Commerce and thus implemented, futu-ke-activities and planning
efforts must acknowledge whether they.are in or significantly affect-the coastal
zone. If they are in or affect the.coastal zone,@the plans must receive the approval
of the state's coastal zone management program and be certified as consistent with
it. In the case of activities on federally owned lands, no final de cision has yet
been made concerning consistency requirements.
In determining the,permissible.land and water uses within the coastal zone,

the-states must evolve and apply an objective procedure which includes at a minimum:

(1) a method for relating various specific land and water
uses to impact upon coastal waters, including utilization of
an operational definition of'"direct and significant impact,"
(2) an inventory of natural and manmade coastal resources,
(3) an analysis or establishment of a method for analysis
of the capability and suitability for each type of resource
and application to existing, projected, or potential uses-P
(4) an analysis or establishment of a method for analysis of
the environment al impact of reasonable resource utilizations [6331.
Based on the analyses [mentioned above] and applicable Federal,
State and local policies and standards, the State(s) should
define permissible uses as those which can be reasonably and
safely supported by the resource, which are compatible with
surrounding resource utilization and which have a tolerable
imp4ct upon the environment [6331.

In the event that the states prohibit certain uses.within the coastal zone, the
@reasons for the prohibition should.be identified.
The States must include in their respective management programs an. inventory
and designation of areas of particular concern within the coastal zone, based on
a review of natural and manmadecoastal zone resources and uses, and-upon consid-
eration of state-established criteria. According to the rules and'regulations
implementing.the Act, the factors considered in these designations must include

at a minimum:

(1). Areas of unique, scarce, fragile or vulnerable natural
habitat, physical feature, historical significance, cultural
value and scenic importance;
(2) Areas of high natural productivity or essential habitat
for living resources, including fish, wildlife and the various
trophic levels-in the food web critical to their well-being;
(3) Areas of substantial recreational value and/or opportunity;
(4) Areas where developments and facilities are dependent
upon the utilization of, or access to, coastal waters;
(5) Areas of unique. geologic or topographic significance to
industrial or commercial development;
(6) Areas of urban concentration where shoreline utilization
and water uses are highly competitive;
(7) Areas of significant hazard.if developed, due to storms,
slides, floods, erosion, settlement, etc.; and
(8) -Areas needed to protect, maintain or replenish coastal
lands or resources, including coastal flood plains, aquifer
recharge areas, sand dunes, coral and other reefs, beaches,
offshore sand deposits and mangrove stands [633].

The intent inspecifying,areas of particular concern is to convey some degree of
statewide concern about them and.then to incorporate them within the scope of the

management programs. In this manner, the states will give these areas special
attention in the development and implementation of policies and actions to manage
areas of particular concern.
Of-special relevance to this study and its policy options'(described in
Chapter VI) is the possible designation of: areas,to be preserved, such as areas
of unique, scarce or fragile natural habitat, historical significance, or aesthetic
importance; areas of high natural productivity or essential habitat; and areas
of substantial recreational value or opportunity. These areas should generally
b4 avoided or affected minimally by energy facilities in their construction,
expansion and/or operation. Another important factor to be considered in the
siting of energy facilities is the designation of: areas of unique geologic or
topographic significance (to industry or commerce), and areas of highly competitive
uses for shoreline and water in and near urban concentrations. The possible-
designation of 'Ienergy resource areas" as areas of particular concern to the energy
industry as well as to other industry, commerce, and the public are important for
the future provision of energy to the coastal zone and areas inland. The concern
for energy-related needs must be balanced with other-land uses. This general
,approach is addressed in-greater detail in Chapter VI. Finally, areas of signif-
icant hazard and areas needed to protect, maintain, or replenish coastal lands
or resources must receive special attention in planning.
A significant facet of the coastal,zone management.programs that could affect
energy facility siting is the development of policies or guidelines for establishing
pr1iorities in areas of particular concern for at least those permissible land and
water uses discussed above. The guidelines for these priorities'will describe the
extent of state interest in the preservation, conservation, and orderly development
of specific areas. Certain areas could receive high priority for development,
and other areas, low priority for development, including energy facilities. Sub-
section 306(c)(9) of the Act further states that the coastal zone management
agencies, in order to receive approval of their programs, must provide for "procedures
whereby specific areas may be designated for the purpose of preserving or restoring
them for their conservation, recreational, ecological or esthetic values." Thus,
using the state procedures and criteria for preservation and restoration designation,
these areas can be given a low priority for development, thereby essentially
precluding development, including energy facilities, from those areas..
Additionally, in order to address the requirements of Subsection 306(e)(2),
the management programs must provide evidence that lithe state has developed and

applied a method for determining @ises of regional benefit and has established
a method for assuring that local land and water use controls in the coastal

zone do not unreasonably or arbitrarily restrict.or exclude those uses,of
regional benefit" [633]. Through this requirement, local decisions concerning
land and water use are.prevented from arbitrarily excluding uses that are of
importance to more -than a single unit of government. However, the state may
determine that certain land and water-uses are of regional benefit under certain
conditions or circumstances only. It must then establish standards and criteria
for determining when these conditions exist. Complete exclusion or restrictions
of these uses in the coastal zone cannot be made through local regulation unless
they are based on 11reasonable considerations of the suitability of the area for
the uses or the carrying capacity of the.area" [633]. Therefore, energy
facilities may be permitted in some coastal areas but not in others. Furthermore,
certain types or sizes of energy facilities may be permitted in certain locations
whereas other types or other sizes of similar facilities may be precluded from

the same locations.
In addition, Subsection 306(c)(8) of the Coastal Zone Management Act as
amended includes a requirement that "the management program provides for adequate
consideration of the national interest involved in planning for, and in the
siting of, facilities (including energy facilities in, or which significantly
affect, such state's coastal zone) which are necessary to meet requirements which
are other than local in nature." In other words, energy facilities may not be
arbitrarily excluded from coastal zones if they are considered.to be in the
national interest. Otherwise, the regulation of energy facility'siting is
(except as otherwise indicated) left to.the discretion of each state._
Section 306(e) of the Act specified that the state management program

must provide

for any one or a combination of the following general
techniques for control of land and water uses within the
coastal'zone:
a. State establishment of criteria and standards for
local implementation, subject to administrative review and
enforcement of compliance;
b. Direct state land and water use regulation; or
C. State administrative review for consistency with the
management program.of all development plans, projects, or
land and water use regulations, including exceptions thereto@
proposed by any state or local authority or privatedeveloper,

@33

with power to approve or disapprove after public notice and
an opportunity for hearings.

.Thus, the state must, at the least, oversee local zoning practice in the coastal
zone and enforce the provisions of the coastal zone program.
Due to the specific relationship established between coastal zone
management and energy facility planning as a result of the 1976 amendments,
the following sections of the Coastal Zone Management Act as amended are of
particular relevance to this study:
9 Subsection 305(b)(8), which requires each state program to include.
a planning process for energy facilities;
0 Subsection 308(c), which makes grants available to states for the-study
of and planning for any economic, social, or environmental effects of energy
facilities of all types in or significantly-affecting the coastal zone;
Subsection 308(d)(4), which provides for grants to coastal stat es-
to assist them in the prevention, reduction, or amelioration of unavoidable loss

to the coastal zone of valuable environmental or recreational resources

resulting from a coastal energy activity.
The coastal energy activities outlined in the amendments which apply, or poten-
tially could apply, to the Great Lakes states are: (1) "any transportation,
transfer, or storage of oil, natural gas, or coal"; and (2) "any transportation,
conversion, treatment, transfer, or storage of liquified natural@gas." Energy
facilities (distinguished from coastal energy activities) refer to all.types
including but not limited to: electric generating plants; petroleum refineries
and associated facilities; gasification plants; facilities used for transpor-
tation, conversion, treatment, transfer, or storage of liquified natural gas;
uranium enrichment or nuclear fuel processing facilities; oil and gas facilities,
including@platforms, assembly plants, storage depots, tank farms, crew and supply
bases, and refining complexes; facilities, including deepwater ports, for the
transfer of petroleum; pipelines and transmission facilities; and terminals
which are associated with.the foregoing facilities.
Subsection 305(b)(8) of the 197-6 amendments states that:

The management program for each coastal state shall include... (a)
planning process for energy facilities'likely to be located
in, or which may significantly affect, the coastal zone,
including, but not limited to, a process for anticipating
and managing the impacts from such facilities.

According to proposed rules published in the Federal Register on December 6,
1976 (Department of Commerce, National Oceanic and Atmospheric Administration
[15 CFR Part 920] Coastal Zone Management Program Development Grants, PP.
53418 13425) [6361, the planning process for energy facilities referred to in
the Act should include:

(1) A means of identifying energy facilities which are
likely to be located in or which may significantly affect
the coastal zone;
(2) A procedure for assessing impacts for such facilities;
(3) Development of State policies and other techniques
Jor the management of energy facility impacts; and
(4) A mechanism for coordination and/or cooperative working
arrangements, as appropriate, between the State coastal
.management agency and other relevant State, Federal, and
local agencies involved in energy facility planning [6361.

To reiterate the intent of Subsection 305(b)(8), the planning process is
to cover.energy facilities, whatever their location, that significantly affect
the coastal zone (outside the coastal zone but having major effects on it, or
within the coastal zone), and whenever they might reasonably be expected to have
effects (benefical or adverse, social) economic, or environmental) in the

coastal zone.

In developing procedures for energy facilities impact assessment, states
should include in their planning process assessment of the impacts',from energy
facilities that must be considered under Section 308 of the Act, the Coastal Energy
Impact Program, (discussed further below)-as applicable to the Great Lakes states.
These im pacts might include, but are not limited to, "increased population,
changed employment patterns, changed demands for public facilities and services,
local price inflation, changed patterns of tax or user fee revenues, effects on
fishing revenues, effects on beaches and sand dunes, shoreline erosion, effects
on airand water quality, and ecological effects."
With respect to the development of state policies and techniques for the
management of energy facility impacts, the state coastal zone management programs

are

encouraged to develop, in cooperation with other appropriate
agencies, procedures for assessing need/demand projections;
for allocating these needs among coastal and inland locations;
for ident*ifying potential coastal impacts; and for determining
site suitability-of alternate locations for particular facilities [636].

(See "Policy Options Related to the Siting of Energy Facilities in the Great

Lakes Coastal Zone," Chapter VI.) Suitability analysis of particular sites could
be accomplished with funds authorized under Subsection 308(c) of the Act as
amended (see below). It should be recognized that the nature of the policies
and techniques for managing energy facility impacts in or significantly affecting
the coastal zone that are incorporated in the overall implementation program will
depend in part on the type and extent of energy facility siting policies and
techniques already in existence at the local,.state, and federal levels.
With respect to developing mechanisms for coordination and cooperation
between the state coastal zone management agency .and other local, state, and
federal agencies, the Act states that the states "should give particular atten-7
tion to,State and Federal agencies already involved.in various aspects of energy
planning. At a minimum, where interstate plans exist (as referred to in Sub-
section 306(c)(8) of the Act), these plans should be taken into consideration."
The consideration of interstate energy plans or programs in the state coastal
zone management programs will facilitate some regional consistency among the CZM
programs in energy planning with respect to the management of resources and
energy facility impacts in or affecting the coastal zone. The proposed rules.for
Program Development Grants also suggest that cooperative arrangements be made to
use energy data, projections, estimates of facility needs, and policies developed
by others, including government energy and utility agencies.and energy industries.
This report provides a substantial amount of material on these matters in the

Great Lakes Basin.

Concerning energy facility environmental planning grants for which the
Great Lakes states are eligible, Subs ection 308(c) of the Act states that:

The Secretary [of Commerce] shall make grants to any coastal state
if the Secretary finds that the coastal zone of such state is
being, or is likely to be, significantly affected by the siting,
construction, expansion, or operation of new or expanded energy
facilities. Such grants shall be used for the study of, and
planning for (including, but not limited to, the application of
the planning process included in a-management program pursuant
to Section 305(b)(8)) any economic, social, or environmental
consequence which has occurred, is occurring, or is likely to
occur in such state's coastal zone as a result of the siting;
construction, expansion, or operation of such new or expanded
energy facilities. The amount of any such grant shall not
exceed 80 per centum of the cost of such study and planning.

The objectives of this subsection of the Act as applied to the Great Lakes states
are (1) to aid the states in planning for the economic, social and environmental

effects ensuing, or expected to result, from thesiting.or operation of new or
expanded energy facilities in or.that significantly affect the coastal zone,.and
(2) 11to encourage rational, timely, and thorough planning forthe management of,
energy facility siting and the impacts from-energy resources development."
According to the proposed rules (previously cited), energy facility siting and
impact studies might include:

(1) Collecting data and taking physical measurements;
(2) Making projections of.employment, population, public facility
and public service needs and costs, and tax and user fee revenues;
(3) Comparing the consequences of alternative energy facility types
or sites;
(4) Examining private industry or government siting policies; and
(5) Conducting analyses required for coastal State.or local
government regulatory decisions, including licenses, leases, permits,
and zoning ordinances [6351.

In the Great Lakes states, planning for the management of energy facility siting
and the amelioration of impacts from energy resources development might include,

but not be limited to:

(1) Devising methods of protecting recreational or environmental
resources in the coastal zone...
(2) Devising strategies for recovering compensation from
.appropriate parties for any adverse impacts caused by the. energy
activity involved;
(3) Preparing for the provision of new or improved public
facilities and public services required as a result of new or
expanded coastal energy activity... ;
(4) Designing and carrying out an equitable intrastate fund
allocation process ... ; and
(5) Devising strategies for the public purchase of land upon or
near which energy-related development is to take place in order to
capture the benefits of the increased value of such land or to
contain such development [6351.

The proposed rules indicate that an eligible coastal state may be allotted a
proportion of the 308(c) moneys appropriated to the fund based on employment
equivalencies-for planned energy facilities listed with the Office of Coastal
Zone Management. The proposed rules stipulate that the state agency(s) receiving
these funds do(es) not necessarily have to be the agency responsible for coastal
zone management, but must be desi gnated by the Governor of the state to receive
the funds and must certify that the uses of the funding assistance are compatible
with the state's coastal zone management program. Certain limitations have been
placed on the use of Subsection 308(c) funds under the proposed rules: (1) the
funds cannot be used to "duplicate the development of the general planning

process for coastal energy facilities required of management.programs under
[sub1section 305(b)(8)," and (2) the funds may not beapplied to,general studies
or plans separated from existing, proposed or planned energy facilities [6351.
Subsection 308(d)(4) of the Act states that:

The Secretary [of Commerce] shall make grants'to any coastal state
to enable such state to prevent, reduce, or ameliorate any unavoid-,
able loss in such state's coastal zone of any valuable environ-
mental or recreational resource, if such loss results from coastal
energy activity,...

A major objective of this provision is to "encourage payment of the full cost of
those environmental.and recreational losses resulting from coastal energy activity
by the [individual, corporation or other organization] responsible for the loss".
[6351. The grants are available only if there is no'other means to recover the
cost of amelioration, reduction or prevention of the unavoidable environmental or
recreational loss from the individual, corporation, or orgaLnization causing the
loss, or from another federal program. With respect to the Great Lakes states
these grants would apply primarily to the costs of prevention, reduction, or
amelioration of any unavoidable loss in the coastal zone of valuable environmental
or recreational resources-due to the transportation,'transfer and storage of oil,
natural gas, or coal.
The consistency requirements of the Act (Section 307) affect both state
actions and the actions.of all federal agencies conducting, supporting, or
licensing activities in the coastal zone. Rules proposed (41 FR 42885) pursuant
to Section 307 require that "[c]oastal zone manag eme.nt programs developed by the
coastal states shall-give full consideration to federal consistency requirements
and such consideration shall be reflected by procedures incorporated in the
management program to: (1) review the consistency of federally conducted or
supported activities including Federal development projects, (2) provide public
notice and review of the certification of consistency statements developed by
applicants for Federal licenses and permits, and (3) review the consistency of
Federal assistance to applicant agencies."
State and local agencies applying.for federal assistance under'federal
programs affecting the coastal zone must "indicate the views of the appropriate
state or local agency as to the relationship of such Activities to the approved
management program for the coastal zone" [Section 307(d)]. IFurthermorel the
proposed rules require federal agencies to comply with the consistency policies
and procedures of Section 307.. "Federal agencies shall: Develop procedures--

to provide State agencies with notification and an opportunity to review the
consistency of Federally conducted or supported activities, including Federal
development projects, (2) not grant Federal licenses or permits if the State
agency objects to the applicant's certification, unless the objection is over-
ridden by the Secretary [of Commerce], and (3) not grant federal assistance to
applicant agencies if the State agency finds that the proposed activity is not
consistent with the management program, unless the State agency objection is
overridden by the Secretary [of Commercel".[6341.
On August 10, 1976, the Assistant Attorney General, Office of Legal
Counsel, Department of Justice, issued an opinion concluding that, "The exclusion-
ary clause [in the Act] excludes all lands owned by the United States from the
definition of the Coastal Zone.." OCZM believes (as stated in a draft position
paper) that regardless of the fact that lands owned by the federal government
are not to be included wi thin the boundaries of a state's coastal zone, authority,
under the federal consistency provisions of the CZMA is still sufficient to re-
quire Federal land-holding agencies to conduct actions on such lands in conform-
ance with approved state programs, when the proposed actions will have spill-over
impacts in the coastal zone. For example, if- a federal agency were to undertake
an activity on federal lands which would directly affect an area adjacent to it.in
the coastal zone,.then the agency would be required to proceed in a manner
consistent to-the maximum extent practicable with the state's program.
Thus, an approved state coastal zone management program becomes a legal
document requiring consistency from federal activities directly affecting the
coastal zone, including activities conducted, supported or licensed by federal
agenc.i.es. Federal activities that affect the siting of,energy facilities are

outlined below.

Consistency with the state CZM program is assured through a variety of
mechanisms. The program itself must be developed in consultation with the
appropriate federal agencies. The approval process entails further federal
agency review. Once the plan is approved, state and local applicants for federal
funding or licensing must first obtain approval from the state CZM agency.
Federal agencies receiving other applications. also require that the applicant
must certify "tha t the proposed activity complies with the state's approved
program and that such activity will be conducted in a manner consistent with the
program" [Section 307(c)(3) as amended].

The development of a single plan and program for management of the
coastal zone of each state and the requirements for consistency therewith pro-
mote a unified approach to the management of the coastal zone. The-consistency
requirements further guarantee that energy facility siting will be considered in

terms of alternative uses of coastal lands and the use of other lands in the

vicinity of such facilities. The siting of individual energy facilities will be
considered in terms of the siting of other energy facilities and will provide a
measure of rationality and planning for the best means of supplying energy needs.
The fact that all state plans and programs are reviewed and approved by a single
(federal) agency (the Department of Commerce) helps insure consistency in manage-
ment practices across state lin es. The entire CZM program is. expected to insure
comprehensive, timely, and effective coastal zone planning and management through
the integration of the planning and decision-making process.
The CZM energy facility planning approach as discussed above incorporates
the determination of permissible land and water uses; the designation of areas of
particular concern; the designation of areas to be preserved, conserved, restored,
or generally avoided as well as areas for development; the development of priori-
ties for permissible land and water uses; the considerations for uses of regional
benefit and in the national interest; and the considerations for federal-state
consistency. In addition, once a state has an approved@energy facilities
planning process, including a means of identifying energy facilities that would
significantly affect the coastal zone (whether they be located on or near the
shoreline or inland), a procedure for assessing energy facility impacts, state
policies and techniques for managing energy facility impacts, and a mechanism for
coordination and cooperation with other-agencies involved in energy facility
planning, it has what might be considered the nucleus of an energy facility siting
program for the state's coastal zone and inland areas adjacent to it (and off-
shore or nearshore locations within state jurisdiction in the case.of floating
and/or anchored facilities) in which energy facilities that significantly affect
the coastal zone might be located. For states that already have some form of an
energy facility siting program (see below) which applies to the entire state,
such a process will serve to give emphasis to the sensitive areas and resources
possibly affected by and the potential impacts (positive and negative) from
energy facilities to be located in or near the coastal zone of those states. The
environmental planning grants (under Subsection 308(c) of the Act) permit the

states to move one important step beyond energy facility siting programs examined

in this report (below) by providing funds to study and plan for any economic,
social, and environmental consequence resulting from the siting, construction,
expansion, or operation of new or expanded energy facilities in or significantly
affecting the coastal zone. Also, Subsection 308(d)(4) provides opportunity for

remuneration for costs of environmental or recreational losses resulting from
coastal, energy activity.
Thus, the Coastal Zone Management,Act as amended provides a comprehensive
and basic framework for addressing energy facility siting in or affecting the
Great Lakes coastal zone. This is particularly significant for states not already
having state-wide energy facility siting programs. The policy options for energy
facility siting described later in this report (Chapter VI) elaborate on the
po ssibilities for further development of energy facility siting controls and
programs by the Great Lakes states, given the Coastal Zone Management Act and its

Amendments as a foundation.

Additionally, grants are available for interstate coordination and for
research and technical assistance. The interstate grants (Sec. 309, as amended)
are for "coordinating state coastal zone planning, policies and programs with
respect to contiguous areas" [309(a)(1)]. The establishment of interstate
compacts or temporary planning and coordinating entities is encouraged. Grants
are available under Section 310, as amended, "to assist (coastal) states in
carrying out research, studies and training required with respect to coastal zone
management" [310(b)]. Grants are also available for acquiring, developing or
operating estuarine sanctuaries and for "acquiring lands to provide access to
public beaches and for other coastal areas of environmental, recreational,
historical, aesthetic, ecological, or cultural value, and for the preservation
of islands" [Sec. 315, as amended].
The coastal zone management plan developed by each state must be approved
by the Secretary of Commerce before that state may begin receiving funds for the
administration of its CZM program. Plan approval is contingent upon the factors
noted above, as well as others included in the Act as amended and in the imple-
menting rules and regulations.

b. National Environmental Policy Act
The National Environmental Policy Act (NEPA) is one of the most signifi-
cant federal environmental statutes. The principal action-forcing provision is
the detailed environmental statement that is required under Section 102(2)(,c) of

the Act for any major federal action significantly affecting the quality of the
human environment. The purpose of the detailed statement is the identification

.and assessment of the environmental impacts of a proposed federal action before
the action is taken. The five action review criteria include: (1),the potential
environmental impacts of the action, (2) the unavoidable adverse impacts involved,
(3) the irreversible commitments of resources caused by the action, (4) short-
term considerations vis-a-vis long-term resource needs, and (5) alternatives to
the proposed action. The lead federal agency is responsible for preparation of
the EIS, although this is often delegated to a consultant, applicant, or to a
state agency involved in the organizational arrangement associated with the
federal action. Pursuant,to regulations promulgated by the Council on Environ-@-
mental Quality (which administers NEPA), federal agencies have established NEPA
guidelines covering their respective actions. 'The following list indicates the
lead federal agencies with NEPA responsibility for various types of energy

facilities.

Facility NEPA Responsibility

Hydroelectric generation Federal.Power Commission
facilities
Nuclear fired steam electric Nuclear Regulatory Commission
generation facilities
:'Coal,-oil, and gas fired steam U.S. Army Corps of Engineers,
electric,generation if Corps permit is required
facilities.

Port and Terminal
handling facilities

Petroleum refineries U.S. Environmental Protection
Agency--but only in those
states in which EPA has
retained authority over water
(e.g., Illinois) and air dis-
charge permits.
Any new source of air'or
water discharges

Themajor energy facility siting implications of NEPA revolve around the
mandatory assessment of the environmental effects of a proposal involving a
federal agency or role. The policies and.procedural requirements contained in
NEPA and in the associated administrative rules and regulations,.as well as
subsequent legal interpretations of the Act have established a mechanism for
Public involvement in energy facility siting proposals.

c. Nuclear Regulatory Commission (NRC)

(1) General
The Nuclear Regulatory Commission is a five--@mer@ber commission established
under the Energy Reorganization Act of 1974 to assume the regulatory functions of
the Atomic Energy Commission. In addition to licensing the construction and
operation of nuclear power plants, the Commission also oversees fuel fabrication
facilities, fuel reprocessing plants and enrichment plants.
Under the Energy Reorganization Act, the IVRC was authorized to undertake
the Nuclear Energy Center Site Survey, which considers the possibility of
(1) establishing nuclear energy centers (NEC's) containing up to forty nuclear
power plants (1200 MWe each) on a single site; or (2) establishing fuel-cycle
centers which would accommodate fuel fabrication and reprocessing, uranium
enrichment and waste disposal; or (3) combinations of (1) and (2). This survey
has been published [48 thru 54] and it concludes that, while' the siting of up to
twenty reactors on a single site can be feasible and practical, there is no great
advantage or compelling need for such centers.
The NRC has three components: the Office of Nuclear Reactor Regulation,
the Office Nuclear Material Safety and Safeguards, and the Office of Nuclear
Regulatory REsearch. The Office of Nuclear Reactor Regulation reviews the safety
of and safeguards for all nuclear facilities, materials and activities, including
the monitoring of existing systems, the testing of new systems and recommendations
for updating systems. They also have primary responsibility for the safe trans-
portation of nonfissionable nuclear materials and for the licensing and regulation
of liquid metal fast breeder reactors (LMFBR's).
The Office of Nuclear Material Safety and Safeguards sets standards,
issues licenses, and enforces regulations for construction and operation of
facilities which produce or use fissionable materials, including nuclear power
plants,, uranium milling and enrichment facilities, fuel fabrication and reprocess-
ing plants, plutonium production facilities and-rad,ioactive waste treatment
facilities. It is also responsible for the transportation and storage of fission-
able materials and radioactive wastes, industrial security a nd safeguards, anti-
trust provisions of the Atomic Energy Act, liability coverage associated with
nuclear power, and the financial stability of utilities dealing in nuclear power.
The Office of Nuclear Regulatory Research is charged with developing
recommendations for research related to licensing and regulatory functions and
with performing or contracting for such research.

Concerning nuclear radiation hazards, the role of the NRC preempts state
efforts; i.e., no state may enact restrictions more limiting than those of the
NRC (see Northern States Power.Co. v. State of Minnesota). Section 274 of th e
Atomic Energy Act, enacted in 1959, provides for states to- assume certain regula-
tory functions over small quantities of nuclear material, but this bears little
or no relation to the area of energy production.
In the early months of the National Environmental Policy Act of 1969, the
Atomic Energy Commission displayed great reluctance to consider factors other
than those specifically related to thenuclear aspects of power plants in their
licensing process. The change came with the.Calvert Cliffs case (Calvert Cliffs
Coordinating Committee, Inc. v. AEC, 449F.2d.1,109 or 2ERC 1779) which determined
that the AEC was required to comply with NEPA; i.e., that they must consider all
environmental impacts before approving the construction or operation of a nuclear
power plant. As a result, the NRC and several states duplicate efforts in
environmental review. Attempts are being made to eliminate duplication and

coordinate the state and.federal efforts.

(2) Siting Procedures
The process employed by NRC for issuing permits for the construction of
nuclear power plants consists of three separate functions that proceed simultane-
ously. These functions are: (1) safety, (2) environment and site suitability,
and (3) Antitrust. The first step in the process is the filing of an application
for, a construction permit by the utility and its acceptance by the NRC. Notice
of the filing is published in the Federal Register and copies.are distributed to
appropriate state and local authorities and to a public document room in the

vicinity of the proposed site. Also a notice of hearing is published in,the
Federal.Register and in local.newspapers.
For the environment and site.suitability review, the NRC staff prepares
a draft environmental statement (DES) which is reviewed by federal, state and
local agencies and other interested persons. The comments received become part
of the final environmental statement (FES). Both documents are made available
to the general public. A public hearing follows the FES.
The safety review includes the preparation of a safety evaluation report
(SER) by the NRC staff. Safety is the responsibility of the Advisory Committee on
Reactor Safeguards (ACRS). After their review, the.staff issues a supplement to
the SER which@ discusses any action taken as a result of the review. A public

hearing may then be held; possibly in conjunction.with the environment and site
suitability hearing. Hearings are conducted.by the Atomic Safety and Licensing
Board (ASLB) which is responsible for issuing the permit. Appeals go automati-
cally to an Atomic Safety-and Licensing Appeal Board-and, if necessary, to the

NRC commissioners.

Antitrust reviews areconducted by the NRC and the Attorney General.
Antitrust hearings, if necessary, are separate from other hearings.
The process is essentially repeated for an operating license once the
plant has been constructed. Public hearings are not mandatory here but may be
held if requested by responsible parties. The operating license specifies
conditions for operation. Continuous surveillance and periodic inspections are
conducted by NRC.
The authority of the NRC does not diminish that of the U.S. Environmental
Protection Agency or of the states on issues relating to applicable federal air
and water pollution control legislation.

d. Environmental Protection Agency (EPA)
Of all the federal policies, programs, rules and regulations associated
with the siting of energy facilities, those of the Environmental Protection
Agency are probably the most complex and have the most far-reaching implications.

Within the scope of the nationwide pollution control programs, the EPA has a
major, if indirect, role in energy facility siting in the Great Lakes states. It
is charged@primarily with implementing the mandates of the Clean Air Act
(PL 91-604 as amended) and the Federal Water Pollution Control Act (PL 92-500
as amended). Under these Acts, the EPA is directed to promulgate rules and
regulations detailing performance standards, and with one exception, the states
were given the primary enforcement responsibility. The states are required to
implement management programs and adopt air and water quality standards that are
at least as stringent as those stipulated by EPA. The EPA monitors state per-
formance, and retains ultimate authority if necessary.

(1) Air Quality Program
The existing federal air quality.policy and.implementation program is
derived from two major statutes: The Clean Air Act of 1967, and the Clean Air
Act Amendments of 1970. Through these Acts the states have been given authority
to and are required to establish enforcement programs to implement federal policy

and standards. The major aspects of the air quality program that are relevant
to this study include the following:
The establishment of national ambient air quality standards (NAAQS)
for a variety of pollutants.
0 The establishment of performance standards for new stationary sources
of pollution.
� The prevention of significant deterioration of air quality exceeding

national ambient standards.

� State enforcement of federally mandated emission limitations,
compliance schedules, and enforcement provisions.

(a) National ambient air quality standards (NAAQS)
Under Section 109(a)(1) of the Clean Air Act Amendments of 1970, the
Administrator of EPA was directed to promulgate national primary and secondary
ambient.air quality.standards for each air pollutant. Primary standards were
established to protect health with an adequate margin of safety. Secondary
standards are designed to protect the public welfare, including such things as
property, from any known or anticipated adverse effects created by the presence
of pollutants in the air (see Table 1 for NAAQS). All states were required to
attain primary standards no later than May 31, 1975, and secondary standards
within "a reasonable time." The Administrator may, under Sections 110( -e) and
110(f), and upon request by the Governor of a state, postpone attainment of
primary standards for a period of up to two years if certain criteria are satis-
fied. However, this is not to be interpreted as a continuous source of variance
from attainment of the NAAQS in the future.

(b) New stationary source performance standards
Section 111 of the Clean Air Act directed the EPA to promulgate emission
standards for new stationary sources of pollution. Included in these categories
are fossil-fuel fired steam electric generating plants of greater than 250 million
Btu[hr heat input. The major air pollutants generated by f ossil-fuel fired
steam electric generating plants are total suspended particulates, sulfur dioxide,,
and to a lesser extent, nitrogen dioxide. For these facilities, the following
standards apply:
Total suspended particulates [40 CRF 60.421:
... no owner or operator ... shall discharge or cause the discharge
into the atmosphere of particulate matter which is:

TAB LE 1

AMBIENT AIR QUALITY STANDARDS

Pollutant Averaging.Time Primary Standards Secondary,Standards
Particulates Annual (G) 75 pg/M3_ 60 pg/m'
24-Hour a 260 jig/M3 150. jjg/r'rj3

S02 Annual (A) 80 pg/M3
24-Hour a 365 Ug/M3
3-Houra 1300 pa 3

Co 8-Houra 10 Mg/M3 10 mg/m,
I-Houra 40 Mg/M3 40 Mg/M3

N02 Annual (A) 100 pg/M3 100 pg/M3

Photochemical I-Houra 160 Vg/M3 160 pg/M3
Oxidants

Hydrocarbons 3-Houra 160 pg/M3 160 pg/M3
(6 to 9 a.m.)
aNot to be exceeded more than once a year@

(A) Arithmetic mean
(G) Geometric mean

.(a) In excess of 0.10 lb. per million B.t.u. heat input
(0.18 g. per million cal.) maximum 2-hour average.
(b) Greater than 20 percentopacity, except that 40 percent
opacity shall be permissible for not more than 2 minutes in any
hour.
(c) Where the presence of uncombined water is the.only reason
for failure to meet the requirements of Paragraph (b) of this
section, such failure shall not be a violation of this section.

o Sulfur dioxide [40 CFR 60.431:
...no owner or operator ... shall discharge or cause the discharge
into the atmosphere of'sulfur dioxide in excess of:
(a) 0.80 lb. per million B.t.u. heat input (1.4 g. per million cal.),
maximum 2-hour average, when liquid fossil fuel is burned.
(b) 1.2 lbs. per million B.t.u. heat input (2.2 g. per million cal.),
maximum 2-hour average, when solid fossil.fuel is burned.
(c) Where different fossil fuels are burned simultaneously in any
combination, theapplicable standard shall be determined by proration.
Compliance shall be determined using the following formula:

X(O.80) + z(1.2)
X + y + z

where:

x is the percent of total heat input derived from gaseous
fossil fuel and,

y is the percent of total heat input derived from liquid
fossil fuel and,

z is the percent of total heat input derived from solid
fossil fuel.

0 Nitrogen dioxide [40 CFR 60.44]:
... no owner or operator... shall discharge or cause the discharge
into the atmosphere of nitrogen oxides in excess of:
(a) 0.20 lb. per million B.t.u. heat input (0.36 g. per million cal.),
maximum 2-hour average, expressed as N02, when gaseous fossil fuel
is burned.
(b) 0.30 lb. per million B.t.u. heat input (0.54 g. per million cal.),
maximum.2-hour average, expressed as N02, when liquid fossil fuel
is burned.
(c) 0.70 lb. per million B.t.u heat input (1.26 g. per million cal.),
maximum 2-hour average, express;d as N02, whet solid fossil fuel
(except lignite) is burned.
M When different fossil fuels are burned,simultaneously in any
combination the applicable standard shall be determined by proration.
Compliance shall be determined by using the following formula:
x(O.26),+ X(O.30) + z(O.70)
X + Y + z

where:

x is the percent of total heat input derived from
gaseous fossil fuel and,
y is the percent of total heat input derived from
liquid fossil fuel and,
z is the percent of total heat input derived from
solid fossil fuel.

(c) Prevention of significant deterioration
Another major component of the Clean Air Act, and one that is extremely
important to the siting of energy-facilities,. is the prevention of significant
deterioration (nondegradation) of air that is already clean. Pursuant to a 1973
U.S. Supreme Court decision, the EPA was required to promulgate regulations to
insure nondegradation [459]. The approach taken was to establish increments of

air quality which cannot be exceeded by any new source or combination of sources
within a specific impact zone. In addition, three classes of areas were identi-
fied in which varying degrees of additional pollution are permitted. Class I
areas are those where little or no degradation (i.e., little or no development)
is permitted. In Class II areas, moderate degradation of existing air quality
(i.e some additional development) is allowed. In Class III areas, a substantial

amount of deterioration of existing air quality is allowed, thus permitting
concentrated or large'scale development [459]. In no case will deterioration be
permitted which violates the national primary and secondary ambient air quality
standards. The allo wable increments for sulfur dioxide and suspended particulates

are shown in Table 2.

TABLE 2
ALLOWABLE INCREMENTS OF AIR QUALITY DETERIORATION (ug/m3

Pollutant Class I Class II Class III

Sulfur Dioxide

Annual 2 15 80
24-hour 5 100 365
3-hour 25 700 1300

Total Suspended Solids

Annual 5 10 75
24-hour 10 30 150

Initially the EPA classified the entire U.S. (except those areas that
already violate secondary standards) as a Class II area. The states may redesig-'
nate areas as either Class I or Class III, provided that certain public participa-
tion procedures are followed, subject to EPA approval.

(d) State implementation plans
Under Section 110, the states, through their respective EPA-approved
state implementation plans (SIP), are the primary enforcement agencies of the
Clean Air Act. In order to establish a control mechanism, the EPA designated a
system of air quality control regions (AQCR).. Each AQCR is typically composed
of several counties, after involving two or more states. In the SIP's the states
are required to establish and enforce for each AQCR, ambient air quality and
emission standards that are at least as stringent as those stipulated above by
EPA. The SIP must include (among other things) the specification of land use
and transportation controls to insure the attainment of the federal primary and
secondary ambient standards. In addition, states are required to institute pre-
construction review procedures to insure that new sources of pollution, such as
energy facilities, will meet primary and secondary ambient air quality standards.

.(e) Energy Supply and Environmental Coordination Act of 1974
The Energy Supply and Environmental Coordination Act of 1974 (ESECA)
amended Section 119 of the Clean Air Act by providing a short-term suspension of
stationary-source fuel or emission limitations to permit the continued use of
coal as a fuel source. This is not to be construed as a permanent variance.
Another major aspect of ESECA that is related to air quality is Section 4

of the Act, which mandated the review of all state implementation plans to
determine whether revisions in performance standards can be made to permit the
increased use of coal as a primary fuel source without jeopardizing the attain-
ment of national primary and secondary ambient air quality standards.
Under Section 309 of the Clean Air Act, the Administrator of EPA is

required to review and comment on the environmental impact of certain matters
relating to the authority of the EPA under all applicable federal environmental
protection legislation, dealing with air, water, toxic substances, etc. Matters
included in this provision are (1) legislation proposed by any federal agency,
(2) newly authorized federal construction projects and any major federal action
covered by environmental impact statement-requirements under Section 102(2)(c) of
NEPA, and (3) proposed regulations published by any federal agency. If the EPA
@determines that the legislation, action, or regulation of concern is unsatis-
factory from the standpoint of public health-or welfare or environmental quality,
formal notification of this finding is referred to the Council on Environmental

Quality.

(f) Implications for energy facility siting
It is generally agreed that the federal air quality program will have
significant implications for the siting of energy facilities. All facilities

must meet new source performance standards using the best available control

technology regardless of the site. In addition, no new source will be permitted
which clearly violates national ambient air quality standards even if it meets
the new source emission standards. Finally, existing clean air areas are pro-
tected by the non-degradation provisions, and emissions from new energy facili-
ties must fall within the limits established for their areas, which are designated
,as Class I, II or III. Currently, the Environmental Protection Agency is
administering the significant air quality deterioration program and has tenta-

tively classified all areas as Class II. As the states incorporate@this program
into their planning process they can redesignate areas as Class I or III.
Designation of an area as Class III would permit substantial new sources of air
emissions, such as fossil-fuel fired power plants, provided the new source,
emission standards and ambient air quality standards are met.
For certain facilities, the costs of emission control equipment for new
sources of emissions will vary according to the degree of air quality degradation
permitted. In Class I areas, or in areas where the ambient air quality is
approaching the national ambient standards, these costs will be considerably
higher than Class II or III areas and may be prohibitive. On the other hand,

designation of an area as Class III would require less sophisticated emission
control.technology and would encourage the siting of certain kinds of energy
facilities that would have difficulty meeting the standards imposed in Class I or

II areas.

(2) Water Quality Program
Another major federal program with significant implications for the siting
of energy facilities is the,clean water program, embodied for the most part in
P.L. 92-500, the Federal Water Pollution Control Act Amendments of 1972, and also
administered by the EPA. The approach taken is similar to that of the Clean Air
.Act. Goals, policies and minimum standards were established by the federal govern-
ment, and the states are required to enforce standards at least as stringent as
the federal standards through the state implementation plan (SIP) process. At the
present time, all states in the Great Lakes Basin except Illinois are empowered
by EPA to act as administrators of federal policy. The major aspects of the clean

water program that are relevant to this study include:
0 The establishment of effluent guidelines and standards for various
pollutants for various categories of point sources of pollution.
� The control of thermal discharges.

� The control of intake structures.

� The National Pollutant Discharge Elimination System (NPDES) permit,

program.
The State Implementation Plan Process.

(a) General policy
Congress included in its statement of policy in Section 101 of P.L 92-500
the following:

1. it is the national goal that the discharge of pollutants into
the navigable waters be eliminated by 1985;
2. it is the national goal that wherever attainable, an interim
goal of water quality which provides for the protection and
propagation*of fish, shellfish,-, and wildlife and provides for
recreation in and on the water be achieved by July 1, 1983;
3. it is the national policy that the discharge of toxic pollutnats
in toxic' amounts be prohibited.

These goals and policies are the basis of the rules, regulations and standards
.that have been developed to control.the discharges of waste from energy facilities

and other sources into the nation's waters.
Another significant policy declaration was contained in Section 301, which
inandated the application of the best practicable-control technology currently
available by July 1, 1977, to all point sources of water pollution. Furthermore,
it required the application of the best available technology economically achiev-
able by July 1, 1983. Effluent guidelines and standards have been promulgated to
achieve these 1977 and 1983 goals.

(b) Effluent guidelines and standards
In or der to implement clean water policies, effluent guidelines and
standards were established for a variety of the typical sources of pollution.
Among these point sources are steam-electric power generating facilities fired by
coal, oil,, gas, or nuclear fuels, and petroleum refineries.
On October 8, 1974, special procedures for permit issuance and eff luent.
guidelines and standards were established for the various operational phases of

coal, oil, gas, or nuclear-fired steam-electric facilities [624]. Parameters for
which standards were set include-heat, total suspended solids, pH, oil and grease,
copper, iron, chlorine, zinc, chromium, and phosphate. Chlorine, used extensively
to treat,water discharged by power plants, is recognized by the EPA as a poten-
tially significant source of water pollution [624]. Thus, effluent guidelines
to protect aquatic organisms from the toxic effects of chlorine have been
.promulgated by EPA. The maximum permissible concentration of free Available
chlorine in water discharged from either once-through cooling systems or1cooling
towers is 0.5 mg/l, while the highest average concentration allowed is 0.2 mg/l,
although EPA has recently been applying more stringent limitations on chlorine
concentrations. Furthermore,

Neither free available chlorine nor total residual chlorine may be
discharged from any unit for more than two hours in any one day and
not more.than one unit in any plant may discharge free available or
total residual chlorine at any one time unless the utility can
demonstrate to the regional administrator or state, if the state
has NPDES permit issuing authority, that the units in a particular
location cannot operate at or below this level of chlorination
[62 41.

The results of recent research indicate that these short-term limitations may
undergo modification in the near future.
In addition to regulating point discharges, standards are applied to the
area runoff associated with these facilities, including that generated by the
disturbance of the earth's surface during construction, and that generated by the
storage of materials such as coal or ash.
The effluent guidelines dealing primarily with thermal discharges were
recently remanded to the EPA by the Fourth Circuit Court of Appeals for revision.
Those guidelines dealing with thermal discharges are particularly subject to
revision. Thus, regulation of discharges from steam-electric generation
facilities is in a state of flux. However, state water quality standards still
apply.

W Control of thermal discharges by closed-cycle cooling
In reco gnition of the potentially significant adverse environmental
implications of thermal discharges from electric generation facilities, the
Congress gave special consideration to controlling this type of pollution in the
development of P.L. 92-500. In promulgating administrative rules pursuant to
the Act, the EPA determined that, for certain categories of electric generation

units, closed-cycle evaporative cooling represents the best Available technology
economically achievable for controlling heated water discharges, Power plants
covered by the closed-cycle cooling requirement include those units of 25 Mwe
capacity or larger placed into operation on or after January 1, 1974, and those
units of 500 MWe capacity or larger placed into operation on or after operation
on January 1, 1970 [6214 However, the EPA has also determined that, due to the
time involved in converting to closed-cycle cooling and due to the necessity of
insuring the reliability of electrical generation in the short term, once-through
cooling (or at least no additional restraint on heated discharges) represents
the best practicable control technology currently available. Thus, compliance
with the closed-cycle cooling requirement will not take effect until 1977.

(d) Variance from thermal discharge limitations
Although Congress1dentified as an important objective the control of
thermal discharges from power plants, it also acknowledged that, under certain
circumstances, closed-cycle cooling would not be required to meet the objectives
of P.L. 92-500. Under Section 316(a) of the Act, if an owner or operator of a
facility-that discharges heated water can demonstrate to the satisfaction of the
Administrator of EPA or the state that the effluent standards are more stringent
than necessary to maintain a balanced, indigenous population of shellfish, fish
and wildlife in or on the receiving body of water of concern, the Administrator
or the state may grant a variance from such requirements and impose alternative
thermal discharge effluent limitations, provided that the continued existence of
the aforementioned aquatic-oriented species will not be jeopardized.
In order to obtain a variance under Section 316(a) one must make appli-
cation to the EPA or to the state, and demonstrate that at least one of the
criteria listed below is satisfied. (These criteria are extracted-from [627].)'

e Absence of prior appreciable harm. Under this criterion.it must be
demonstrated that (1) no appreciable harm has resulted from the
thermal component of the discharge (taking into account the inter-
action of such thermal component with other pollutants and the
additive effect of other thermal sources) to-a balanced, indi-
genous community of shellfish, fish and wildlife in and on the
body of water into which the discharge has been made, or (2) despite
the occurrence of such previous harm,' the desired alternative
effluent limitations (or appropriate modifications thereof) will
nevertheless assure the protection and propagation of a balanced,
indigenous community of shellfish, fish and wildlife in and on the
body of water into which the discharge is made.

e Protection of representative, important species. A variance may be
granted if it can be demonstrated that the discharge will assure the
protection and propagation of representative, important species
whose protection and propagation, if assured, will assure the
protection and propagation of a balanced, indigenous community of
shellfish, fish and wildlife in and on the body of water; unless
unrebutted information received duringthe period provided for
public comment or evidence introduced at any bearing held to
consider the permit indicates:
-that the species selected by the Regional Administrator are not
representative, in terms of biological needs, of a balancedi-
indigenous community in the receiving water body; or
-that the temperature requirements employed in calculating the
proposed alternative effluent limitations are not adequate to
assurethe protection and propagation of those species in and
on the receiving water body; or
-that the temporal or spatial distribution of the mixing zone
is excessively large,or otherwise inconsistent with the purpose
of section 316(a).
Evidence provided by biological engineering and other data.
Alternative effluent limitations can be imposed if the applicant
can provide evidence supported by data, models, etc. that indicate
that either of the first two criteria will be met or if such
limitations will assure the protection and propagation of indi-
genous aquatic life [627],.

A technical guidance manual has been issued by the EPA to guide the development
of a 316(a) demonstration.

Several 316(a) demonstration studies in the Great Lakes Basin have been
completed or are in progress, and variances from the ciosed-cycle cooling require-
ment are'quite common. Most of the applications for 316(a) variances have been
associated with requests either for approval of cooling systems currently em-
ployed in existing power plants, or of expansion of generating capacity at these

facilities.

(e) Control of cooling water intake structures
Another major influence on energy facility siting'contained in P.L. 92-500
is Section 316(b). According to this section any standard established to control
point sources of pollution must require'that the location, design, construction,
and capacity of cooling water intake structures reflect the.best technology
available for minimizing adverse environmental impacts. Section 316(b) is
applicable to all existing as well as new cooling water intake structures.
The issues associated with the location, design, construction, and
capacity of intake structures [316(b)] are often more complex than those related

to 316(a) demonstrations and generally need to be,evaluated in detail on a case-
by-case basis. In support of this conclusion, the development document for
intake structures, which is the official source of EPA-guidance on'these matters
addresses this complexity:

Ow ing to the highly site specific characteristics of available
technology for the location, design, construction and capacity of
cooling water intake structures for minimizing adverse environ-
mental impact, no.technology can be presently generally identified
as the best technology available, even within broad categories of
possible application. Within this context, a prerequisite to the
.identification of best technology available for any specific site
should 'be a biological study and associated report to characterize
the type, extent, distribution, and significant overall environ-
mental relation of all aquatic organisms in the sphere of influence
of the intake, and an evaluation of available technologies,,!to
identify the site specific best technology available for the location,
design, construction and capacity of cooling water intake structures
for minimizing adverse,environmental impact [628].

Although the Section 316(a) and 316(b) demonstrations are separate
processes, there is a relationship between' the type of cooling system employed
and the location, design, capacity, and construction activity associated with
the intake structure used with that system. Also, in a given situation, the
environmental impacts of an existing or proposed intake structure may well be
more significant than those associated with the cooling system employed, and the
issues related to the intake structure may require more scrutiny by the EPA or

the state.

(f) National pollutant discharge elimination system (NPDES)
The NP DES permit system was established under Section 402 of P.L1. 92-500
and is the regulatory mechanism through which effluent guidelines and standards
for energy facilities are enforced. All point source discharges into.the nation's
waters (with a few exceptions) must obtain an NPDES permit. Procedures have been
established which insure public access to information, public hearings, and
agency review. States are intended to be the enforcing agency of the NPDES
program, but EPA can assume control if a state's approach is unacceptable.

(g) State implementation plan process (SIP)
Pursuant to Section 303(e) of P.L. 92-500, the states are designated the
primary agencies of the clean water program, provided that they can demonstrate

the initiative and capability for pro'ram administration. They are required to
9
maintain ongoing comprehensive water quality management programs which implement
federal policies and standards. The states may enforce standards that are more
stringent than those of the-federal government. They are required to designate
all segments of their respective waters as either "water quality limited" or
."effluent limited" segments. A segment is classified as "water quality limited"
if it does not meet and/or is not expected to meet applicable water quality
standards assigned to it even after the application of effluent guidelines and
standards to the various uses of the water. A segment is classified as "effluent
limited" if water quality is meeting and will continue to meet applicable stand-
ards or will meet such standards after the application of effluent guidelines
and standards. All of the Great Lakes states except Illinois have been designated
as the primary program administrators., The EPA currently administers the program
in Illinois, but formal approval of the Illinois program by EPA is likely in the

near future.

In setting standards, the states are required to consider and incorporate
the following criteria (excerpted from [6291):

* Water quality standards shall specify appropriate.beneficial water
uses to be achieved or protected and the waterquality criteria
necessary to support those appropriate beneficial: uses;
9 Water quality standards shall be established taking into consider
ation their use and value for public water supplies; propagation
of fish, shellfish, and wildlife; recreational purposes; and
agricultural, industrial, and other purposes; and also taking into
consideration their use and value for navigation;
e Water quality standards shall be such as to protect the public health
or welfare, enhance the quality of water and serve the purposes of
the Act [629].

Another major element of the SIP is the development of a statewide non-
degradation policy and regulatory mechanism. The non-degradation policy must be

consistent with these criteria:

� Existing in-stream beneficial water uses shall be maintained and
protected. No further water quality degradation which would result
in impairment of existing in-stream beneficial uses is allowable.
� Existing high quality waters which exceed those levels necessary to
support propagation of fish, shellfish and wildlife and recreation
in and on the water shall be maintained and protected unless the
.State chooses, after full satisfaction of the intergovernmental
coordination and public participation provisions of the'State's
continuing planning process, to allow lower water quality as a
result of necessary and justifiable economic or social development.

in such cases, the state must assure that the highest statutory
and regulatory requirements for all new and existing point
sources and feasible management or regulatory programs pursuant
to Section 308 of the Act will be achieved..'
e In those cases where potential water quality impairment
associated with a thermal discharge is involved, the anti-
degradation policy and implementing method shall be consistent
with section 316 of the Act [629].

(h) Implications for energy facility siting
The federal and state water pollution control programs, created for the
most part by P.L. 92-500, will exert a great deal of influence on energy facility
siting in the Great Lakes Basin. However, one cannot conclude from the above
discussions that existing federal water pollution control policy will either
strongly encourage or discourage the siting of energy facilities in the coastal
zone or inland. The influence on siting of the EPA or the authorized state agency
iri@terms of water resources will depend largely on the existing conditions at the
proposed site and the applicable water quality standards and guidelines in effect

for that site.

In any event, water quality standards will be met by any new energy
facility in the Grea t Lakes Basin. If specific site conditions dictate the
employment of sophisticated technologies, for cooling systems and of other prac-
tices to avoid unacceptable degradation of water resources, economic considerations

become critical.

(i) Relationship between EPA programs and coastal zone'
management
There are some fundamental relationships between air and water quality and
the use of the coastal zone, and several of the policies and provisions contained,
in the air and water pollution control programs and the CZM program have recog-
nized the importance of these relationships. In developing policies and planning
processes to guide the siting of energy facilities in the coastal zone, the Great
Lakes states must give full consideration to the applicable provisions of the
appropriate federal acts.
There exists a two way consistency between the Coastal Zone Management
Act (CZMA) on the one hand, and the Clean Air Act and the Federal Water Polllution
Control Act on the other. Section N7 of.the,CZMA established,the requirement
that any activity in a state's coastal zone involving participation of a federal
agency must be consistent with the approved CZM program of that state.. However,
Section 307(f) of the CZMA also clearly states that it does not diminish the

authority vested in the air and water pollution control programs:

...nothing.in this [Act] shall in any way affect any requirement
established by the Federal Water Pollution Control Act, as amended,
or the Clean Air Act, as amended, or established by the Federal
Government or by any state or local government pursuant to such
Acts. Such requirements-shall be incorporated in any.program
developed pursuant to this title and shall be the 'water pollution
control and air pollution control requirements applicable to such
programs.

Nothing in the state's CZM program may violate any standard s promulgated under
the authority of these Acts. Also, the state CZM agency cannot set air or water
quality standards directly [630, 6311.
One issue of particular interest in the siting of energy facilities in
the coastal zone is,the possibility that air or water pollution control standards
might be used to encourage or discourage siting in particular areas of a state's
coast. According to the EPA General Legal Counsel, states may not impose more
stringent (or more lenient) limitations on the discharge of airor water pollu-
tants merely because the discharge occurs in the coastal zone [630]. Thus, not
only must CZM plans comply with applicable EPA air and water quality requirements,
but these standards and guidelines provide the baseline for environmental pro-
tection in plan development.

As indicated above, the determination of consistency of actions with the
approved state CZM plan must be based on a comprehensive framework of planning
for coastal areas resources. The state CZM entity may not object to an action as
being inconsistent with the CZM plan on the grounds that the effective effluent
limitations and standards set by EPA orby that state (as empowered by EPA) are
not sufficiently stringent [6301.
Success of the CZM program depends largely on communication and coordina-
tion between the state CZM entity and agencies and interests at all levels of
organization. Coordination between the CZM programs and those programs administered
by the EPA is especially significant.. In developing CZM plans and in establishing
energy facility policies and planning processes, the states should coordinate
.activities with areawide wastewater management plans (P.L. 92-500, Section 208)
and Level B river basin plans (P.L. 92-500, Section 209, and the Water Resources
Planning Act of 1965, P.L. 89-80). Also, existing policies for prevention of
significant deterioration of air quality, and the zones classified by these
policies, as well as any air quality maintenance areas would have to be incorpo-
rated.into the CZM plan.

e. Federal Power Commission
The Federal Power Commission (FPC),has sole regulatory authority over the
siting of all nonfederal hydroelectric generating facilities on lands and waters
subject to federal jurisdiction. The Federal Power Commission was created by
Congress in 1920 to administer the Federal Water Power Act, now Part I of the
Federal'Power Act. In 1930, the FPC was reorganizedby@Congress as an independ-
ent agency.. The kinds of ener y facilities under FPC jurisdiction.include
9
electric generating plants using water from impoundments and from pumped storage.
Since these facilities are of relatively low priority to the study, the role of
the FPC will not be examined in detail.

The licensing procedure employed by the FPC involves five steps; prelimi-
nary permit to investigate (optional), application for license, FPC review,
possible hearing and final determination, and construction and operation., Any
person or entity may apply for a preliminary permit to investigate a potential-
hydroelectric power site for up to three years. A public hearing may be held at
this point if sufficient public interest is expressed. The application for a
license includes the following considerations: the extent of water and land
rights, the lands owned, the right to sell power within the State, the effect of
a project's operation on water use and quality, the recreation possibilities
of the site area, the impact on fish and wildlife, the project's achievement of
the comprehensive development of.the waterway, the evidence of project's optimum
utilization of its power resources, the preservation.of scenic and aesthetic
values, and general environmental considerations.
Review of the application by FPC involves notification in the Federal
Register and in local newspapers,,consultation by applicant with the U.S.. Fish
and Wildlife Service, Bureau of Outdoor Recreation. and appropriate state agencies.
One of the major evaluation criteria.is the effect of the proposal on the over-
all regional ener-gy system. Following application review, a hearing may or may
not be held by the FPC and-should it be held, the-hearing examiner renders an
initial decision that is reviewed and either supported or rejected by the commis-

sion. Finally, the FPC monitors construction and compliance with the terms of
the license.

in addition to its licensing authority over hydroelectric facilities, the
FPC proposes in Docket No. RM76-38 to.amend sections of the Regulations of the
Federal Power Act and the Natural Gas Act to comply with the requirements of
Section 307(c)(3) of the Coa stal*Zone Management Act. The Coastal Zone

Management Act affects the regulatory,responsibilities of the FPC in the follow-
ing areas:
Licensing of hydroelectric projects under Section 4(e) and 15 of-the

Federal Power Act;

9 Ordering interconnection of electric transmission facilities under
Section 202 of the Federal Power Act;
a Authorizing international transmission of electricity under Section
202(e) of the Federal Power Act and Executive Order No. 10485;
e Authorizing import or export of natural gas under Section.3 of the

Natural Gas Act; and
'Certification under Section 7 of the Natural Gas Act.

f. U.S. Army Corps of Engineers
The involvement of the U.S. Army Corps of Engineers in energy facility
sit ing is primarily associated.with construction activities in navigable waters
of the United States. Under authority of Section 10 of the Rivers and Harbors
Act of 1899.(33 U.S.C. 403) each utility and corporation must obtain a permit
from the Corps for any energy facility-related construction activity,in navigable
water, including intake and outfall pipes, bulkheads, piers, and other structures.
Since permits issued for such facilities.often constitute a major federal action
significantly affecting the quality of the human environment, an environmental
impact statement must be prepared in accordance with NEPA. Due to the fact that
Section 10 permits are often the only major federal involvement in fossil-fueled
electric generating plants and refineries, the Corps is the lead agency under
NEPA for such facilities. Nuclear plants must also obtain permits for construc-

tion in navigable waters, but the Corps has no other involvement in these
facilities beyond granting permits. Other kinds.of.energy facilities, such as
port and terminal facilities, in the Great Lakes coastal zone have also been
covered by NEPA under the Section 10 permit.program. [158, 199].
Although'the Corps has no authority or mandate to engage in the full
range of energy facility siting regulation, it is required to consider nonnavi-
gational aspects of proposals covered by the Section 10 permit system [4561,.
This judicial interpretation was based on the mandates of NEPA and the Fish and
Wildlife Coordination Act (16 U.S.C. 661 et seq.,,as amended), the latter of
which requires the Corps to consult with the U.S. Fish and Wildlife Service and
the head of the Appropriate s.tate fish and wildlife department with regard to
Section 10 permit applications [4561.

g. Federal Aviation Administration (FAA)
The FAA is concerned with all hazards to aircraft. Tall structures such

as meteorological towers or cooling towers must be lighted in accordance with
FAA recommendations. Any structure@over 200 feet tall (generally any cooling
tower or smoke stack) requires notification of,the FAA. If the proposed struc-
ture falls within the restricted zone around an airport as described in Federal
Avaiation Regulation 77, the request for permission to construct is routed to
various airlines and the airport management for comment. If a hazard is
determined, the'FAA will seek to have permission to construct denied by the
appropriate state or federal agency. Such hazards are generally considered in
the planning.of facilities and FAA involvement is rarely necessary.'

h. Coast Guard (CG)
The Coast Guard is responsible for investigating oil pollution incidents,
for assessing penalties for violations of,Sec'tion 311: of the Federal Water
Pollution Control Act-, and for oil removal in coastal waters. Coastal waters in
the Great Lakes are generally the lakes, bays, marshes, and rivers inland to the
point where commercial navigation does not'exist. The Coast,Guard would neces-
sarily become involved in 4 nuclear incident which threatened those who use the
Great Lakes through issuing warnings by radio, vessel and aircraft or by conduct-
ing any other action the Coast Guard is qualified to perform. The Coast Guard is
also concerned with hazards to navigation. Lights must be placed on structures
ina navigable waterway, according to Coast Guard regulations. Such hazards may
include dikes or submerged intake structures associated with an energy facility.
.Decisions as to which structures are to be lighted are at the discretion of the
Coast Guard. Permits for such construction are under the purview of the Corps
of Engineers (see Sect. f. above)

i. Federal Energy Administration (FEA)
The Federal Energy Administration (FEA), created by the Federal Ene rgy
Administration Act of,1974, has very little to do with the siting of energy
facilities., The enabling Act.deals with general energy considerations and does
not specifically address energy facility siting [462].
Under Section 10 of the Energy Supply and Environmental Coordination Act
of 1974 (ESECA) the FEA is,directed to weigh the environmental effects of the
use of coal in existing power plants against the savings of petroleum and natural

fuels-,that,could be achieved by converting to coal. Following this analysis,
the FEA Administrator must issue orders requiring conversion from oil or gas to
coal, where desirable, by plants that have the conversion capability. Section
119,(b) of the Clean Air Act was amended by ESECA to permit the continuing use of
coal by.facilities that have.converted.
Another ESECA provision directs the FEA Administrator to require'that all
new fossil-fuel electric generation plants be designed and constructed to allow
the burning of coal as the primary fuel source. Enforcement of this provision,
as well as the decision to convert an oil- or gas-fired power plant to a coal-
fired plant, is contingent upon the availability of,coal, the adequacy of the
coal transportation system, and the maintenance and reliability of power service
(4631.

2. GREAT LAKES STATES

This section describes energy facility siting regulations in the eight
Great Lakes states. The regulatory processea are.discussed in terms of their
general approach to the issue, requirements-for disclosure of long-range plans
and forecasts by applicants for site certification, provisionsfor public partici-
pation in the siting process, the procedure,by which sites are certified, provi-
sions for the acquisition of sites, and@provisions for financing the siting
regulation process.
An exception to this outline.is-found in the description of the program
in New,York state. It was felt that adetailed description of some aspects of the
New York program would provide an interesting example of a comprehensive, sub-
stantive.program for regulating power plant siting.

a. Illinois

(1) General Approach
Illinois has not established special.policies or procedures that relate
to the siting of energy facilities. Utilitie4s are regu Ilated by the Illinois
Commerce Commission, which has recently extended its area of concern beyond cost,
safety and reliability considerations. The Illinois Pollution Control Board has
authority to determine and implement environmental quality standards and through
this responsibility has a major impact on the location and operation of energy
facilities. The Illinois Environmental Protection Agency is also involved, as
are several other state agencies to some extent. Local governments retain control

over siting through zoning and bui lding codes, and several local authorities may
also be involved. Electric and natural gas'utilities, and oil and gas pipelines
are subject to Commission, re gulation,'except those owned or operated by a
political subdivision or municipal corporation. Electric cooperatives are
subject to limited jurisdiction.

(2) Long Range Plans and Forecasts
Long range plans and forecasts are not required in Illinois.

(3) Public Participation
The Illinois Commerce Commission holds public hearings on all power
plant licensing cases.

(4) Certification Procedures

The Illinois Commerce Commission is responsible for issuing both a
"Certificate of Convenience and Necessity" and a "Section 50 Order" which permits
a utility to construct, operate and maintain a facility. The hearings on the
certificate and the order are open to the public.
Permits must also.be obtained from several other state and local agencies@
The state Environmental Protection Agency administers the permit and certification

programs for air and water pollution control. Power plants must have permits for

any permanent fuel combustion equipment and for thermal, chemical and sewage
discharges. Other state agencies with license or permit functions associated
with energ facilit' siting are listed in Table 3.
y y
Local governments retain.control over local zoning and building codes,

and have direct impact on facility siting. Other,local authorities who may
require permits include the building inspector, the county or township road
authority, the fire department, and the local health authority. Furthermore,
there are over twenty kinds of local agencies exercising regulatory authority
over water use,.many of which enjoy' permit granting authority.

(5) Site Acquisition
The Section 50 Order issued by the Illinois Commerce Commission usually
includes explicit authority to acquire private property by eminent domain.

(6)' Financing
There are no specific provisions for funding the work associated with
energy facility siting regulation in Illinois.

TABLE 3

MAJOR PERMITS REQUIRED FOR POWER PLANT SITING IN ILLINOIS

.AGENCY LICENSE OR PERMIT AUTHORITY

Dept. of Public Construction permit or Ill. Rev. Stat.
Works and Bldgs. intake and discharge Ch. 19 Sect. 52 et.
Division of Waterways flumes seq. (1969)

Dept. of Mines Permit to drill water wells Ill. Rev. Stat. Ch. 104
Sect. 62 et.seq. (1969)

Illinois EPA Permit to discharge sanitary Ill. Rev. Stat.
waste during construction Ch. 111-1/2 Spct.1001
et.seq. (1970 Supp.)

do. Permit to install auxillary do.
boiler heating systems.

Commerce Commission Certificate of Public Ill. Rev. Stat.
Convenience and Necessity Ch. 111-2/3 Sects.
authorizing and directing 50 and 55 (1969)
construction facilities

Dept. of Highways Permit for transmission Ill. Rev. Stat.
lines to cross highways Ch. 121 Sect. 1-101
et. seq. (1969)

Dept. of Aeronautics Permit to construct
meteorological survey
tower.

Dept. of Public Health Special, license for Ill. Rev. Stat.
radiation-installation Ch. 111-1/2 Sect. 211,
et. seq.

b. Indiana

(1) General Approach

Indiana does not have a comprehensive program for energy facility siting.
Responsibility for approving a power plant is divided among several agencies
within the Department of Natural Resources, the Stream Pollution Control Board,

the Air Pollution Control Board, the Environmental Management Board, and the
Public Service Commission (PSC). However, regulation of siting,is largely
indirect through these several regulatory agencies. The power of,eminent domain
resides with the utilities for acquisition of power plant sites and transmission

line corridors.

(2) Long Range Plans and Forecasts
There are no provisions for utility disclosure of long range plans or

forecasts in Indiana.

(3) Public Participation
Meetings of regulatory bodies are open to the public. A pollution
control board or other regulatory bodies may choose to hold public hearings.
State citizens who oppose a permit granted by a regulatory body have been granted
standing under a 1971 state law. Citizens may initiate agency review and/or

judicial review of the permit.

(4) Certification Procedure
FaciIlity certification is under the purview of the PSC. 'Environmental
considerations are the responsibility of the DNR and the Environmental Management

Board. Both a construction permit and an operating permit are required from
b'oth the Stream Pollution Control Board and the Air Pollution Control Board,
agencies within the Environmental Management Board. Permits are required from
the DNR for any construction in the floodway of a river, for water withdrawal
from a navigable stream or from Lake Michigan, and for inter-basin diversions.
Site selection is the prerogative of each utility within these constraints.

(5) Site Acquisition
Utilities have the right to exercise eminent domain to acquire sites.for

their facilities.

(6). Financing
The Stream.Pollution Control.Board charges a fee for outfall permits.
Ifthe discharge.is less than 50,000 gallons per day the fee is $10.00. If the
discharge is greater than 50,000 gallons per day the fee is $100.00 forthe first
outfall and $50.00 for each additional outfall.

In addition,.if plant construction requires the removal of sand and
gravelor other minerals from the bed of Lake Michigan, a yearly fee of $50.00
is assessed by.-the Department of'Natural Resources plus a charge of $.10 per cubic
yard of sand and gravel removed from, or filled over in Lake Michigan.

C. Michigan

(1) General Approach
The State of Michigan presently has no legislation directly governing the
siting of energy facilities. The regulatory framework that is currently employed
is best described as traditional utility regulation. Most of the factors related
.to the geographic siting of energy facilities in Michigan are addressed at the
local level through land use control techniques such as zoning, and building
codes. However, a considerable degree of state authority is exerted over facility
certification through the implementation of various envirorimental protection and
natural'resource management programs. The thrust of this general approach is to
influence siting indirectly by insuring compliance with various environmental

protection policies. In brief, emphasis in the existing regulatory mechanism is
pl,dc ed on facility certification instead of alternative site evaluation and

selection.

A number of statutes exert at least some influence on the siting of
ener gy facilities in Michigan. The Shorelands Management and Protection Act of
1970, which predated the Federal Coastal Zone Management Act of 1972, calls for
the''control of environmental and high risk erosion areas situated within 1000
feet of the ordinary high water mark of the Great Lakes. Flood hazard areas are
also covered and are not limited to the 1000 feet criterion. Authority for
implementation of this program rests primarily at the local level. The Michigan
CZM,Program is being built primarily around this state Act.
Another element of environmental policy in Michigan that affects energy
facility siting in the coastal zone is the Great Lakes Submerged Lands Act. This
Act established a permit program for construction activities in navigable waters

that is somewhat similar to the permit system required by Section 10 of the
Rivers and,Harbors Act of 1899, administered by the Corps of Engi neers,.
A statute that could influence energy facility siting in inland areas
,is the Michigan Natural.Rivers Act of 1970. Under this Act, segments of the
state's rivers that meet certain criteria may be designated as areas that Warrant
statewide concern and management. This Act provides for mandatory local zoning
of corridors of the:river,s included,-in the program. It is unlikely that4n
energy facility would.be sited in close proximity to a river included in this

program.

(2) Long Range Plans and Forecasts
At present, no formal mechanism exists for a state role in long range
energy facility planning and demand forecasting. Traditionally, this has been
performed by the private sector.. Recently, the Public Service Commission has
requested that.the electric utilities voluntarily disclose the details of'their
projected capital improvement expenditures over the next ten years for electric
generating plant expansion and for air and water pollution control equipment
installation.- Disclosure of this information allows,at least some evaluation
of planned,siteJocations. Cooperation,by the utilities has aided this process.
However, public involvementin the early stages of alternative site evaluation

and selection remains limited.

The Michigan.Energy Administration has recently begun to look at.a broad
range of problems and needs associated with future energy production in Michigan..

(3) Public Participation
Public invol vement in energy fa.cility,siting decisions occurs primarily
in the public hearings concerning permit and license applicat ions required by
state and l,ocal governments. State requirements areloutlined in the next section.
Hearings are also held On the utility rate regulation process administered by
the Public.Service Commission., In the event that an environmental impact state-,
ment were.,prepared on a proposed siting pursuant to Michigan's environmental
impact review program (as discussed below), hearings would be held and public

input would be solicited.,

(4) Site Gertilfication

Michigan does not have widespread authority to override local governments

in siting decisions. Thus, energy companies must obtain all necessary clear-
ances at the local level as well as at the state and federal levels. In accord-
ance with existing State of Michigan and U.S. federal legislation, a number of
permits are required to site an energy facility. The Environmental Protection
Branch, of the Michigan Department of Natural Resources is in charge of imple-
menting environmental protection policies through the enforcement of the permit
requirements. 'Table 4 lists the principal permit programs that apply to energy
facilities in Michigan.

TABLE 4

MAJOR PERMITS REQUIRED FOR POWER PLANT SITING IN MICHIGAN

Termit Required Authority

Watef Resources Nation Pollutant Mich. Act 245,
Commission Discharge Elimination P.A. 1929, as
System (NPDES) permits amended
for all point source dis-
charges to surface waters

Water Resources Permit for all discharges Mich. Act 245,
Commission to groundwater P.A. 1929, as
amended

Water Resources Soil erosion and sedimenta- Act 347, P.'A. 1972
tion control permit

Water Resources Permit to erect a structure Act 247, P.A. 1955
Commission in or alter the flow of
navigable water (similar to
Corps of Engineers Section 10
permit)

Water Resources Permit to physically alter Act 346, P.A. 1972
Commission inland lakes and streams.

Air Pollution Control Permit to install source Act 348, P.A. 1965
Commission of air emissions as amended

Air Pollution Permit to operate source Act 348, P.A. 1965,
Control Commission of air emissions as amended

Resource Recovery Permit to dispose solid Act 366, P.A. 1974
Commission wastes

As mentioned above, Michigan has adopted a statewide process of-environ-
mental impact assessment. This process, which was created by Executive Order
1974-4, is applied to major state actions that significantly affect the quality
of the human environment. Although this process has not been routinely applied
to energy facilities, coverage could be extended to include these facilities

since the statelicenses, or permits that are invariably required could-be defined

as major state actions requiring an environmental assessment.

(5) Site Acquisition
The acquisition of sites for energy facilities is usually accomplished by
the private sector through voluntary purchase on the market.,@Although the

electric utilities have the authority to exercise the power of eminent domain for
site acquisition, subjec,t to approval by the Public Service Commission, this
authority Is rarely used.

(6) Financing
The existing energy facility siting regulatory mechanism is funded through
the normal budgetary process. Modest fees must be submitted with some of the

permit applications to cover certain costs.

(7) Power Authority Proposal
A recent study of electric power generation in Michigan warrants.attention

in this discussion. In 1975 Governor Milliken issued Executive Order 1975-4

which established the Governor's Advisory Commission on Electric Power Alterna-
tives. In his charge to the commission the Governor identified some of the-major
institutional problems associated with the provision of an adequate supply of

electric power:

Traditional regulatory practices simply will not.be adequate to
solve the enormous and complex problems of the electric utility
industry in Michigan. The process does not react fast enough to
provide sufficient relief@given the rapid pace of developments
in the national economy. In addition, regulation may create dis-
incentives to economic efficiency. Yet, even though the system
has been and will continue to be strengthened, it does not.pr.ovide
regulators with@sufficient control to rectify the problems...
The State of Michigan must act now to examine other alternatives
to the existing regulatory structure. The state must insure the
availability of an adequate supply of power at an affordable price.
The financial condition of Michigan's major utilities must be
improved or the state will in the very near future be faced.with-

a-the indefinite deferral of all major construction;
b--the termination of environmental and safety'programs;
c--the inability to serve new residentiall commercial,'and
industrial customers;
d--the deterioration of existing service [457].
'Specifically, the Commission was directed to:

a. examine the general trends in the rates of growth of the demand
for electric energy both in the nation and in Michigan; ...assess the
accuracy of utility industry and.state government projections of such
electric energy demand growth; ...and
b. examine all of the feasible alternatives that will provide the
consumers of Michigan with an adequate supply of electric power,
...specifically including establishing a Michigan Power Authority
to engage in the financing, construction and operation of new..
generating or other facilities, establishing a program of insurance
and guarantees on the state level to bring about the lower cost of
financing electric utility debt, and urging some-form of federal
financing support [6mphasis added] [4571.

The final,report of the Commission was issued in August, 1976. The foremost
recommendation was the establishment of the Michigan Power Authority (MPA). The
recommendations of the commission address many of the problems and needs identi-
fied throughout this study, and the reader is referred,to the.Final Report of the
[Michigan] Governor's Advisory Commission on Electric Power Alternatives [457]
for further information on this concept.'

d. Minnesota

(1) General Approach
The Minnesota Power Plant Siting Act was passed in May, 1973 to provide
for the siting of power plants and the routing of transmiss'ion@lines under
authority of the Environmental Quality Council (EQC). The state also has an
Energy Agency created in March, 1974, which has authority tb'issue certificates
of need for energy facilities. The Environmental Quality Council is composed of
the heads of seven state agencies (including Energy), a representative of the
Governorts Office, andfour public members appointed by the Governor. The
council has additional responsibilities under the Subdivided Lands, Critical
Areas and the Environmental Policy Acts. Local zoning and land use control
.regulation are preempted by EQC site approval. Aggrieved partiesmay appeal

council decisions in district court.

(2) Long-Range Plans and-Forecasts

Public utilities, either individually or in concert, must submit biennial
forecasts covering the subsequent 15-year period. The forecasts must include:
tentative descriptions of size, type and general location of power plants and
transmission lines; a statement of projected demand for electricity and the
underlying assumptions used in its calculation; an estimation of capacity required'
to meet this demand; and a description of the relationship of each utility to each
other and to power pools.
Annual five-year plans for facility development must also be submitted
by utilities. These plans are to include identification of a tentative site and
at least one alternat ive, with a preliminary indication of the potential impact
of planned facilities on the existing environment and how such impacts may be

avoided or minimized.

(3) Public Participation
There are four members of the public on the 12-person EQC, and the..si,ting
Act includes several provisions for additional public input. The process begins
with identifying the criteria to be used for selecting suibable sites and corri-
dors for electric power facilities. Public hearings are required for the develop-
ment of these criteria. An annual public hearing is also held in order afford
interested persons an opportunity to express their views regarding the inventory
of potential sites or any other aspect of the council's activities, duties or

policies.

The Act stipulates that the council appoint advisory committees comprised
of a majority of public representatives. Such committees include represen tatives
of the utilities, the regional council, and any county or municipality whi ch is
host to a proposed site. The Act requires additional public participation beyond
public hearings and advisory committees, but is not specific as to the nature of

this participation.

(4) Certification Procedure

Pursuant to the Power Plant Siting Act, a set of criteria has been
developed to establish an inventory of potential sites for the generation and
distribution of electric power. The actual inventory of sites is in the final
stages of development at this writing and will be available in the near future.

Utilities must either select tentative sites from this inventory in its annual
facility plan or, if selecting a -non-inventory site, set forth reasons for this
departure and make,an evaluation of the site or route using the established

cfiteria.

Applications for sites and routes are made in a form and manner pre-
scribed. by the council. The council conducts both studies and hearings on the-
application and designates a suitable site or corridor for each facility. Such
designation is made in accordance with the established site selection criteria
and standards. An approved site or corridor receives a certificate of site
compatibility'. Time limits of one year for power plants and 180 days for trans-
mission line corridors are provided. The study and evaluation process includes
assessments of,environmental impact, direct and indirect economic impact,
potential b.eneficial uses of waste energy (heat), and an evaluation of alterna-

tives and irreversible commitments of resources.

The process is not a single-phase operation, because the EQC is respon-
sible only for site certification. Utilities must also obtain permits from other

agencies as,in the past. Thus, the public service commissions and environmental
protection agencies retain responsibility for issuing permits and certificates
for power plant construction and operation.

(5) Site Acquisition
The Act provides for the continuance of utilities' rights of eminent

domain.

(6) Financing
An application fee of $500 to $1000 for each $1 million of estimated
investment and a minimum fee of $5000 are used to cover the-cost of site-specific
studies. An annual levy based on both kilowatt-hour and dollar sales of electri-
city is used to finance the general work of the council, including baseline -
studies, criteria development, inventory preparation and general environmental

studies.

e. New York

(1) General Approach

The-State of New York has established a specific regulatory mechanism
to deal with the siting of steam electric generation facilities of greater than

.73

50 MWe capacity. This includes coal, oil and nuclear-fueled plants. Article
VIII of the Public Service Law.created the New York State Board on Electric
Generation Siting and the Environment. The board was placed in the Department of
Public Services and is composed of the chairman of the Publ ic'Service Commission
(who is also chairman of the board), the heads of the Departments of Environmental
Conservation, Commerce, and Health, and citizens appointed by the Governor on an
ad hoc basis from the areas of the proposed sites. The board has considerable
authority to implement the various state laws that apply to the siting of
electric generation facilities. All aspects of siteand facility approval are
administered by the board. In the final analysis, all necessary approvals and
review processes are incorporated into the Certificate of Environmental Compati-
bility and Public Need, which must be obtained before a facility of 50 MWe or
greater can be sited.

Long-Range Planning
Under the authority of Section.149-b of the New York Public Service Law

each electric utility must submit an annual long-range plan which includes:
a forecast of demand for the next ten years, specifying anticipated
load duration, including peak loads;
e identification of generating capacity to be utilized in meeting such
demands, including capacity to be provided by others.oln a contractual basis;
.0 an inventory of all major facilities operated by members of the

New York.Power Pool, including the dates for completion, operation and retire-

ment;
0 an inventory of land owned and held for future use As a major steam
electric generating facility site-,
a anticipated expenditures fox research in the areas of generation
-and transmission of electricity and.ab.atement and1control of pollution during

the next year;
such additional information as the commission may by regulation
require to carry out the purposes of this.section.
Subchapter E-1 of Chapter I of.The Rules of Procedure outline the
fladditional information" required by the PSC for long-range planning. The
utilitie s are required to notify a wide range of public and pri@ate organizations

and individuals of the filing of the annual report. Following notification, the
PSC holds one or more public hearings on the annual plan. The annual plan

contains four major sections: power demand and'energy requirements, generation
facilities, transmission facilities, and" research and development.
Each plan must document thesummer*and winter peak loads in the service
area of concern for the previous 10 years and must-provide estimates for the
current year and for each of the 20 years subsequent to the year of filing. In
addition,.information is also required on the energy requirements for the time
frame mentioned above for such uses as residential, small light and power, large
light and power, corporate uses, street and highway lighting, railroads and rail-
ways, and other public uses.
The plan must also contain a documentation of the methodology used to
estimate peak loads and energy requirements, including a description of the
Pconomic and demographic assumptions employed in peak load and energy requirement

forecasts.

Finally, data used in the forecasts must accompany the 'annual plan, and
each utility is required to describe present and-planned future efforts with
regard to encouraging energy conservation or to stimulating demand.
Under the generation facilities section utilities are required to specify
in detail the existing and projected generation capacity of their respective
systems. This section requires a projected timetable of plant completion,

including the approximate date of application of any permit or license required
under state or federal law. A summary must be presented of each New York State

environmental law, rule, regulation or-standard of less than statewide applica-
bility pertaining to any facility proposed within ten years of the year in which
the plan is filed.
For each facility proposed within 10 years of the plan of concern,
utilities must provide an estimate of the capital cost. of environmental control
facilities and a description of the maj or design constraints posed by environ-
mental standards or'site-specific conditions.
In terms of site inventory, information is required with regard to:

� the size and location of the site

� any applicable land use standards as contained in zoning regulations
and master plans
� the changes in land use that would result from construction at the
proposed site
� the probable environmental suitability of the site for the type of
generating facility proposed.

Finally, the plan must discuss how the availabili.ty of environmentally
suitable sites,. the location of load centers, the configuration of the state
bulk transmission facilities, and the final costs of delivered power have
influenced the selection of each proposed site.

(3) Public Participation
Public involvement in the decision-making process is provided by a
variety of means, including public disclosure of long-range plans by utilities,
procedural requirements insuring notification of the filing of an application
for a certificate, and public hearings conducted on long-range plans for site
development. In addition, local interests are represented on the board as ad
hoc members from the j udicial district of,the proposed site.

(4) Site Certification

In New York the certification of the site and of the facility is handled
by means of the application and approval processes associated with the Certifi-
c.ate of Environmental Compatibility and Public Need. All permits and.licenses
related to compliance with environmental protection legislation are handled.
through the board and are included as part of the applicationfor the certificate.
Under the authority of Section 149-a of Article V.III of the Public Service Law,
the board preempts all other state and local authorities in siting-related
matters by effectively incorporating theselegal requirements in the.certifica-

tion process.
The decision-making process surrounding site approval is characterized by
a formal, legal adversary proceeding, at which the various interests present
testimony on matters related to the proposal of concern. The extensive informa-
tion obtained in applying for the certificate supplies much of the basis for, the
evaluatio n of the proposal. The findings of the board, which may constitute.
approval, approval with conditions, or. disapproval of the proposed siting, are
based on the following criteria:
* the public need for the facility and basis thereof
9 the nature of the probable environmental impact, including a speci-.
ication of the predictable adverse effect on the normal environment and ecology,
public health and safety, aesthetics, scenic, historic and recreational value,
forest and parks, air and water quality, fish and other marine life, And wildlife

that the facility represents the minimum adverse environmental impact,
considering the state of availabIt technology, the nature and economics of the'
various alternatives., the interests of the state with respect to aesthetics,
preservation of historic sites, forest and parks, fish and wildlife, and other

pertinent considerations

� that the facility is compatible with the public health and safety
� that the facility will not discharge any effluent in contravention of
the standards adopted by the Department of Environmental Conservation or, in
case no classification has been made of the receiving waters that the facility
will not discharge any effluent that will be unduly.injurious to the propagation
and protection of fish and wildlife, the industrial development of the state, and
public health and public enjoyment of the receiving waters.
9 that the facility is designed to operate in compliance with applicable
state and local laws 'and regulations issued thereunder,concerning, among other
matters, the environment, public health and safety, all of which shall be binding
upon the applicant. However, the board may refuse.to apply any local ordinance,
law, or resolution which it finds unreasonably restrictive in view of the
existing technology or the needs of or costs to consumers whether located inside
or outside of such municipality. The board shall,provi.de the municipality an

opportunity to present evidence in support of such ordinance, law, resolution,

regulation, or other local actin issued thereunder

e that the facility is consistent with long-range planning objectives
for electric power supply in the state.
e that the facility will serve the public interest, convenience, and
necessity, provided, however, that determination of necessity for a facility made
by the Power Authority of the State of New York@ pursuant.to Se ction 1005 of the

Public Authorities Law shall be conclusive on the board; and

that the facility is in the public interest, considering the evidence
in support of such ordinance, law, resolution, regulation, or other local action

issued thereunder.

Regulations implementing Article VIII,of the New York Public Service Law
require that at least two locations (primary and alternate) be evaluated in,
detail for the proposed facility, or that, in addition to the primary location
for the proposed facility, an alternate facility at an alternate site mustalso

be evaluated in detail.

(5) Guidelines for Application for Certificate
The rules and regulations governing the Certificate of Environmental
Compatibility and Public Need are highly detailed and cover an extremely broad
range of factors related to the siting of electric generation facilities.
'Each of these categories is broken down into subsections. No attempt
will be made here to provide an in-depth review of these regulations. The points
most relevant to this study will be described to the extent possible according

to the headings that appear in the guidelines.

(a) General requirements
Provisions are made in this section to insure that the,applicant and the
board are fully aware of all federal, state and local laws, rules, regulations,
standards applicable to any apsect of the proposed site.

(b) Public need and engineering design
The data relevant to demand and supply forecasts as determined in the
most recent long-range electric system plan are incorporated in the certificate
application to document the need for the proposed-facility. Also included is

information on.engineering design, transmission facilities, costs of initial
investment, and costs of generation of electricity.

,.(c) Air quality and meteorology
Under this section, the applicant is required to submit. information on

meteorological conditions at the proposed site. Data are collected for suspended
particulates, sulfur dioxide, nitrogen dioxide, and other contaminants likely to
be discharged by the.facility. Data are also collected for other meteorological
parameters to establish a framework within which to predict impacts of the pro-
posed facility on air quality.

(d) Aquatic ecology
In order to assess the effects of.the proposal on aquatic ecosystems, the
applicant is required to collect data for a period of not less than 12 consecu-
tive months, ending not more than 6 months prior to the date of application.

These data are in addition to any data collected by the U.S. Fish.and Wildlife

Service and -the New York Department of Environmental Conservation. The design,

operation, and maintenance aspects of the facility are then evaluated in terms of

the ecological relationships that are likely to be impacted by the proposal. The

impact areas include:

9 physical disruption of bottom sediments

9 discharge of,thermally enriched water
e scheduled or unscheduled shutdown
e significant change in dissolved oxygen
a major change in-local current patterns or water movement

significant buildup of a toxic material in the sediment
0 impingement or entrainment of any significant life-form.

(e) Environmental noise

Noise impacts are .evaluated in a fashion similar to that of air impacts.

Present conditions are determined; construction, operation, and maintenance

activities are specified; and the associated effects are predicted.

(f) Geology and seismology.

This section was unavailable, for review.

(g) Land use and aesthetics

Land use effects are treated in the same manner as air and noise effects.
The categories of land use effects that must be discussed include the following
social and economic impacts:

the total number of employees and the associated payroll for each year
of the construction phase and the total number of employees and associated payroll
by annual salary levels for the first two years of operation;
a the number of persons to be employed from the local labor market;
the probable impact, if any, of the use of the site and any associated
influx of employees upon the sufficiency of police,fire, health, and other
public services, as well as.housing, educational, and recreational facilities;
the estimated annual amount of municipal or- special district property
taxes and any municipal or special district user charges;
e the impact of any change in access to any land as a result of the
construction, operation, or maintenance of the proposed facility;
if there is any plan for using the site area for other than the pro-
posed facility, the impact of the preemption of that plan by the proposed

facility; and

the impact on adjacent land uses, including existing patterns of land
use and zoning in the locality.

(6) Site acquisition

State involvement in site acquisition is limited to requiring that

electric utilities disclose ownership of or interests in prospective future
sites. Site 'acquisition is usually achieved through.voluntary negotiation.

(7) Financing
Applicants are required to submit an application fee of $25,000 to the
board which may be distributed to the local jurisdictions affected by the pro-
posed siting if they can demonstrate a need for the funds. These funds are

intended to defray expenses incurred by local interests in providing expert
testimony in their behalf at the formal hearing. Unused funds are returned to
the applicant.

f. Ohio

(1) General Approach

The State of Ohio has modeled its power plant siting program after that
of'New York. Although some differences exist, the general approachesare the
same. The regulatory mechanism has been fashioned into a one-stop process. The
Ohio Power Siting Commission (PSC) is the lead agency through which the process
operates and.is composed of the heads of the Departments of Environmental Protec-
tion, Health, Economic and Community Development, and the Chairman of the Public
Utilities Commission. In addition, an engineer appointed from the general public
also serves on the PSC. It is noteworthy that in Ohio, as opposed to New York,
the responsibilities for natural resource management and environmental protection
are performed by separate agencies, the Ohio Department'of Natural Resources
(ODNR) and -the Ohio Environmental Protection Agency (OEPA). Although ODNR is not
represented directly by membership on the PSC, it is extensively involved in the
review process of site proposals.
Covered by this program are electric generating facilities, including
oil, coal, and nuclear power plants of greater than 50 MWe capacity, electricity
transmission lines of greater than 125 kV capacity, gas transmission lines and
associated facilities capable of transporting gas at greater than 125 pounds per

square inch.

In order to-site a facility of the type covered, a utility must first
obtain a Certificate of Environmental Co mpatibility and Public Need from the

OPSC. All permit and license requirements are incorporated in the certificate
application'process.

(2) Long-Range Planning
Chapter 4906.15 of the Ohio Revised Code establishes the requirement
.that utilities prepare annual forecasts of electric power and natural gas demand
and supply. The PSC has promulgated detailed guidelines for.these forecasts.
The electric generating and transmission facilities forecast is composed of three
parts: (1) electric power demand forecast, (2) resource,fore.casts and site
inventories for electric generating plants and (3) resource forecasts and site
inventories for transmission facilities. The regulations include An appendix
which outlines various forecasting methodologies which may be employed by the
utilities. The time frame that must be employed for data analysis includes:
0 the past five years' actual historical data
a the current year forecast (both actual and projected)

0 a ten-year forecast of loads, both in terms of energy and peak

demands, as appropriate.

(a) Demand forecast

The utilities must provide the following:

0 a description of the extent to which the reporting utility coordinates

its load forecasts with those of other systems, such as affiliations in a holding
company group, associated systems in a power pool or other coordinating organi-
zation, or other neighboring systems
e a description of the manner in which such forecasts are coordinated

and of any problems experienced in this coordination
e a brief descriptib.n.of any computer modeling, demand forecasting,
polls, survey or data gathering activities engaged in during the past year
(exclusive of normal operations), including cost data, manpower requirements and
significant findings.
In order to facilitate the analysis of forecasts, Ohi6 has established 11
service districts, and 15 planning regions for the state. Some elements ofthe
demand forecasts are linked to this breakdown. The output of the demand forecast

is composed of five parts:

* a forecast of the energy demand in'the utility's service area
@ a forecast of system energy demand in Ohio by industrial sectors
only

e a separate ten-year forecast of energy demand for that part of each
state planning region included in the reporting utility's service area
� a forecast of system peak demand levels for winter and summer

seasons

� a forecast of annual peak loads for each major load center.
Another requirement of the annual ten-year forecast is the documentation
of the approach used in the forecast, the major factors of which are the metho-
dology, the data base,.and the assumptions employed. Particular attention is
paid to the use of assumptions in the forecasts, and those related to the
following points must becovered:
o relative prices and availability of alternatives to the use of

electric energy
0 pricing policy, including:

- alternative rate structures

- promotion of consumption or conservation

- predicted future price behavior
- impact of price changes on quantity demanded.
o growth in the economy
advertising policy-assumed
availability and potential development of primary energy sources
(coal, oil, hydro, nuclear, solar, wind, etc.) used in generating electricity
o other assumptions critical to forecast techniques-or company operating

procedures.

(b) Resource forecasts and site inventories for, electric
generating plants

This section of the overall forecast is intended to provide documentation
.of estimated future resource requirements and of the prospective sites under
consideration by the reporting utility. The major items that must-be addressed

are outlined below:

a description of the generating capacity of the existing system
a ten-year resource.plan which identifies the requirements of new
facility construction to meet projected loads (broken down on an annual basis)

e a description of the rationale for planned expansion
e an inventory of prospective sites for generating plants that are
subject to the certification process.

With regard to this last item, utilities must provide a detailed site
description, ecological data, a description of likely socio-economic impacts, and

a brief discussion of alternate sites.

(3)- Site Certification

In the Ohio program site certification and environmental certification of
the facility are combined into one process. The OPSC administers all state and
local laws, permits and licenses that apply to a proposed energy facility covered
by the program. The OPSC preempts the authority of all other state and local
agencies and units of government in the regulation of siting.
'As required by Section 4 of Ch apter 4906 of the Ohio Revised Code,
utilities must obtain a Certificate of Environmental Compatibility and Public
Need before siting an electric generating facility. In reviewing an application

for a certificate the OPSC must determine:

* "the basis of the need for the facility
9 the nature of the probable environmental impact
* that the facility represents the minimum adverse environmental
impact, considering the state of available technology and the nature and economics

of the various alternatives, and other pertinent considerations
* in-the case of an electric transmission line, that such facility is
consistent with regional plans for expansion of the electric power grid of the
electric systems serving this state and interconnected utility systems; and that
such facilities will serve the interests of electric system economy and reliability
e that the facility will comply with Chapters 3,704., 3734., and 6111. of
the Revised Code and all regulations and standards adopted thereunder
9 that the facility will serve the public interest, convenience, and
necess ity." (ORC, Section 4906.10)
The Rules and Regulations of the OPSC include an extensive section on the comple-
tion of an application for a certificate. The relevant points under each major
heading of this section of the guidelines will be covered.

(a) Justification of need

This discussion must include a description of the relationship of the

proposed site to the most recent ten-year forecast And an analysis of the
alternatives considered. This section also provides for a project schedule which
describes the time staging of the procedural requirements and of plant construc-

tion.

(b) Technical data

In order to fully evaluate the proposal, certain detailed information is
required. In terms of the site itself, data must be collected on geography and
topography, geology and seismology, and hydrology.. Al so required are data on site
layout and preparation, and on generating, cooling and emission control equipment
to be employed.

This section of the certificate includes a detailed environmental assess-

ment of the proposed site. As used in this context, "environmental" generally
refers to the poilution-related@asp*e'cts' of environmental impacts. The data
requirements are listed in detail, and the general assessment headings include
air, water, and solid waste, radioactive emissions, noise, and resources.

(d) Social and ecological impact of the proposed generating
facility
The major headings under this section include health and safety impacts,
ecological impacts, impacts on resources, economics, land use and community
development, and cultural@'effects.

(e)- Permit requirements

As mentioned above, the various permits and licenses that must be
obtained by the applicant in order to site an electric generation facility are
incorporated into the application process for the certificate. A list of the
major permits is given in Table 5.

(4) Public Participation
The Ohio program provides a variety of opportunities for public involve-
ment. All information submitted to the OPSC by the electric utilities (except
proprietary information) is available for,public review. Widespread notification
is made of applications for certifi-cates. In addition, the annual ten-year

forecast report meetings, the pre-application review conference (if held), the
formal hearing on the certificate, and other meetings of a non-proprietary nature
are all open to the public.

TABLE 5

MAJOR PERMITS REQUIRED FOR POWER PLANT SITING IN OHIO

Resource Ag.!!-_ncy Pe it Required Authority

Air Ohio EPA Permit to install source Ohio Revi sed' Code,
of air emissions Chapter 3704.03

Air Ohio EPA Permit to operate source Ohio Revised Code,
of air emissions Chapter 3704.03

Water Ohio EPA Permits for all discharges Ohio Revised Code,
into receiving waters Chapter 6111.03
(NPDES permit)

Solid Waste Ohio EPA Permit to dispose of Ohio Revised Code
solid wastes Chapter 3734

(5) Certification Procedure

A well-defined application and review procedure has been developed for
electric generating facility siting in Ohio. The procedural guidelines will be
described briefly according to the major topical headings.

(a) Le'tter of intent

In order to provide adequate lead time for the evaluation of the proposed
siting and to insure the proper course of action, the Ohio P6wer Siting Commis-

sion requires that a letter of intent be filed at least one year in advance of
the filing of an application for a Certificate of Environmental Compatibility and
Public Need. In the letter, the utility may request waivers from certain OPSC
rules and regulations. The OPSC must respond to the letter of intent within
sixty days, making any appropriate comments.

(b) Pre-application conference
The purpose of this conference is to identify environmental, social, and
public factors that could result in disapproval of a specific site, before signifi-
cant time and monetary-resources have been expended. The pre-application hearing
is also open to the public, and may be held before or after the filing of the

letter of intent.

The next major step is the filing of the application for the certificate
with the OPSC, which then has 60 days to determine the completeness of the appli-
cation. During this period, appropriate state agencies, principally the ODNR and
the OEPA, review the application. Major substantive factors that do not appear
to be addressed in the application are identified at this point. The utility
then responds to these 6omments and.resubmits its application, after which the
OPSC has 60 to 90 daysto circulate the application for review and schedule a
public hearing, at which the formal, legal.proceedings take place. During this
period, review comments by the ODNR, the OEPA, the PUCO and other agencies are
solicited by OPSC. The OPSC has established specific certificate evaluation,
procedures and guidelines, which specify the statutory authority of the review,
the particu lar agency and staff.member responsible for the review, and the pri-
mary focus of the review. The results o ,f this-substantive review form the basis
of the testimony presented at the formal hearinv-.. At this point, the certificate

is either approved, approved with conditions, or denied.

(6) Site Acquisition
The State of Ohio is not involved in the acquisition of prospective sites
for energy facilities. The private sector acquires sites primarily through
voluntary negotiation with landowners.

(7) Financing

Ohio has established a financial mechanism to,offset the costs of various

aspects of the.program including review, analysis, evaluation, investigation,
monitoring, enforcement, etc.
The application fee for a power plant is determined by the following

formula:

the product of, $1.10 times the maximum kilowatt electric
generating capacity as determined by the name plate rating,
plus
ten percent of the amount determined above, times
the difference between the anticipated year of expiration
of the period of initial operation and the anticipated
year of commencement of construction.

g Pennsylvania

(1) General Policy Approach
At present, Pennsylvania does not have legislation that specifically
addresses energy facility siting. The regulations and standards of the environ-
mental protection and natural resource,management policies'form the basis for the
existing, indirect regulation of siting. The concept of local control of land
use is deeply imbedded in Pennsylvania, and this will continue'to play a major
role in future policy development.'
In 1970 Pennsylvania passed legislation establishing the'Departmeint of
Environmental Resources and charging it with the development of statewide
environmental master plan. The Environmental Quality Board is the policy making
body of the DER and is in charge of master plan development. The chairman of
the Public Utility Commission is also a member of the board. The approach taken
in the master plan is the identification, policy development, and management of
environmental areas of critical state importance. The general categories identi-
fied as priority areas include:

9 prime agricultural soils
e watersheds with high quality streams
.0 floodplains

� coal resources

� areas with limited water supply

� clean air resource areas

� open space in metropolitan Areas
� geologic areas with development constraints.
These categories generally reflect a land capability approach to environmental
planning. The policies developed for the.general critical areas will signifi-
cantly influence the siting of electric generating facilities as well as other
types of energy facilities.

(2) Site Certification

Site certification and facility certification are handled under separate
mechanisms in Pennsylvania. With respect to site certification, no state approval.
is required if a proposed electric generating facility site has been zoned for
such a use or if a variance has been granted by the appropriate local governmental
jurisdiction. Under existing law, the Pennsylvania Pablic Utility Commission
(PUC) can preempt local regulations and can grant the conditional power of

eminent domain to utilities.. If the proposed sit e has not been givenlocal
approval, the utility can apply to the PUC for intervention. If the PUC deter-
mines that the proposal is needed.to maintain an adequate supply of electricity,
it can grant a Certificate of Necessity for the proposal. This gives the utility
the power of eminent domain to acquire the site and transmission line rights-of-

way.
With regard to certification of the facility, Pennsylvania has established

environmental protection legislation for air and water pollution, soil erosion
and sedimentation, and solid waste disposal. The Department of Environmental
Resources (DER) is the principal agency in charge of the environmental protection
programs. Table 6 lists the major permit requirements for energy facilities in
Pennsylvania.

TABLE 6

MAJOR PERMITS REQUIRED FOR POWER PLANT SITING IN PENNSYLVANIA

Resource Agency Permit Required Authority

Air DER Bureau of Permit to install source Penn. Air Pollution
Air Quality of air emissions Control Act
Control

Air Permit to operate source
of air emissions

Water Bureau of Water Industrial waste discharge Penn. Clean Streams
Quality Manage- permit Act of 1937, as
ment amended.

Water U.S.E.P.A. National Pollutant Section 402,
(Authority not as Discharge Elimination P.L. 92-500
yet delegated to. System (NPDES) permit
Penn. DER)

Water/Soil Bureau of Water Soil erosion control Penn. Clean Streams
Quality Manage- permit for earth Act of 1937, as
ment changes greater than amended
25 acres

Solid Bureau of Land Permit to dispose Penn. Solid Waste
Waste Protection of solid waste Management Act

The specific requirements under each permit vary according to the type of
facility and site under consideration. The DER has established regional offices
to coordinate these permit systems and to expedite procedural matters.

(3) Long-Range Planning
Long-range planning for electric generating plants and other kinds of
energy facilities is performed by private corporations. The PUC does require
that electric utilities demonstrate that an adequate supply of reasonably priced
,electricity will be available in the future. Thus, some knowledge is gained of
possible future sites, but detailed disclosure of specific plans is not required.

(4) Site Acquisition
The normal site acquisition procedure i,s-one of voluntary purchase by
private corporations. Negotiation usually is sufficient for acquisition. The
PUC has the authority to grant the power of eminent domain to electric utilities
for land acquisition. Although condemnation is used oc..casionally for acquisition
of transmission line rights-of-way, it is rarely used.for large tracts of land

for future sites.

(5) Public Involvement

Public involvement in the siting decision process in Pennsylvania is
provided mainly through public hearings conducted on.,the various environmental
.protection permit, applications mentioned above.

(6) Financing
There do not appear to be any financial mechanisms established to
facilitate or implement the energy facility siting process in Pennsylvania.

h. Wisconsin

(1) General Approach
.The Wisconsin legislature enacted a power plant siting bill in September
1975 which provides for the siting of large power plants (over 300 MWe) and high
voltage transmission lines. The Act does not create a new agency but rather
assigns responsibilities to existing agencies, especially to the Public Service
Commission (PSC) and Department of,Natural Resources (DNR). Local ordinances
which preclude or inhibit installation and utilization of facilities covered by

the Act are preempted. The Act provides for judicial review of any decision by
the PSC regarding the advance, plan or the certification of facilities.

(2)* Long-Range Plans and Forecasts
Biennial plans are required of the utilities and may be submitted
individually or in concert. The plans are to include a general description of
facilities and locations planned for the succeeding ten-year period, identifica-
tion' of possible@alternatives and reasons'for selecting the proposed facilities
and locations, a' detailed projection of electric energy demand and the basis
thereof, identification' of planned research projects, and identification of pro-
grams to discourage inefficient and excessive power use.
The utility plans are to be submittedto the'PSC with copies to seven
other state-agencies and any concerned regional planning commission. These
agencies are allowed 180 days in which to comment on the pldns. Copies are also
sent to cities, counties and libraries in proximity to proposed sites and to
those who request copies. Local governments and members of the public may also
submit written comments within 180 days. A hearing on the plan will also be held
within 180 days within the vicinity of the site proposed to be constructed in the
following three years. At least thirty days prior to the hearing, the PSC must

prepare a single environmental assessment on all plans submitted by the utilities.
Within eighteen r@o@nths of i.ts filing, each plan must either be approved
or disapproved by the commission. Approval is based on four criteria: provides
adequate supply, i,s in the public interest, is coordinated with other long-range
plans and policies, and provides programs for discouraging inefficient and

excessive power use.

(3) Public Participation
At least one public hearing is to be held on each utility plan. Several
public hearings are also held in the vicinity of a proposed site after the appli-
cation for Certificate of Public Convenience and Necessity has been filed. The
public is provided access to copies of the utility's plans through county librar-
ies and is invited to make written comment.on the plans.

(4) Certification Procedure

At least 120 days before filing an application for a certificate, a
utility must notify the PSC and the DNR of its intention to file and provide an

engineering plan showing the location of the proposed facility accompanied by a
description of the facility including anticipated effects on air and water
quality. Within 60 days of such notification the DNR provides the applicant with
a list of all permits and approvals required for the construction or operation of
the facility indicating which of these would be required prior to issuance of the
certificate. An optional permit procedure allows the utility to,obtain a single
permit from the DNR covering all permits and approvals issued by that agency.
The certificate is required prior to commencement of construction. Time
limits of eighteen months for power plants and six months for transmission lines
are specified for the approval process. The process is to include "as many
hearings-as practicable." Approval of the certificate is based on: compliance
with the most recent advance plan, necessity to meet demand, consideration of
alternatives, environmental considerations, and conformance with orderly land use
and regional development plans. The PSC issues the certificates.

(5) Site Acquisition
.Utilities in Wisconsin have the power of eminent domain, but the Siting
Act restricts the use of this power. A utility may condemn a limited interest
in real property or appurtenant personal property for purposes of feasibility
tests and studies under certain restrictions. A utility may not acquire real or
appurtenant personal property by condemnation until a Certificate of Public
Convenience and Necessity has been issued for the site.

(6) Financing
The Act does not provide for the funding of siting regulation procedures.

3 OTHER COASTAL STATES
This section briefly describes energy facility'siting programs in
selected coastal states outside the Great Lakes.Region. -States were selected
-for the uniqueness oftheir, approach to the question of energy facility siting.
All six states have,recently enacted legislation to,@deal directly with this
issue. California has the only program that specifically relates energy facil-
ity siting to coastal zone.,management.

a. California

(1) General Approach
The California Energy Resources Conservation and Development Act of May
1974 provides that state with one of the most,comprehensive energy programs in
the country. The Act establishes the Energy Resources Conservation and Develop-
ment Commission (ERCDC), which is comprised of five governor appointees confirmed
by the senate, two non-voting, ex-officio members, the secretary of the state
Resources Agency and thelpresident.of the Public Utilities Commission. Conflict
of interest provisionsare specified in the Act, The commission is charged with
power plant siting and certification, energy resources.conservation, and" research/
development,programs to deal with supply, consumption and conservation of energy.
The commissionbas sole responsibility for site certification except in the
coastal zone, where prior approval from the state Coastal Zone Conservation

Commission is also required.

(2) Long-Range Plans and Forecasts
Utilities must prepare biennial 5-, 10-, and 20-year forecasts of demand,
estimated savings through greater efficiency, alternative ways to meet increases
in demand, siting needs, and the potential for increasing capacity at existing
sites. The forecasts are to be widely disseminated with comments invited from
all quarters. The Public UtilitiesCommission submits an independent evaluation
of each forecast during the four-month review period, after which the ERCDC
issues a preliminary statewide report on the forecasts. After more review and
another public hearing, the forecast is incorporated into the biennial report.
The report concerns overall energy needs, developments, policies and practices.
It includes a list of possible sites to meet the 10-yearneed for electricity
and a 20-year projection of the likely environmental, economic and social impacts

of continuing present trends, with recommendations for reducing demand, conserving
energy, and developing potential energy sources.

(3) Public Participation

Public participation is not only permitted, it is actively sought out.

An Office of the Public Advisor has been established to insure dissemination of

information to the public and the notification of interested parties and the
general public with regard to public hearings and other commission actions"
This appears to be a unique attempt to,facilitate public particiation and insure
an open and thorough decision-making process.

(4) Certification Procedure
A utility proposing to construct a power plant in California must first
submit a notice of intent to file an application for site certification to the
Energy Resource Conservation and Development Commission (ERCDC). The notice of
intent is to include identification of three alternative sites, a description of
the facility proposed for each site, a preliminary statement of the relative
economic, technological, and environmental advantages and disadvantages of each
alternative, and a statement of need and information showing compatibility with
the most recent biennial report. Of the three alternative sites, at least one
must be outside the coastal zone. The notice of intent may- also describe phased
development for a site.

Copies of the intent notice are widely disseminated. The ERCDC then

requests comments from appropriate agencies, including the Public Utilities
Commission, from whom a certification of public convenience and necessity may
also be required,and the Coastal Zone Conservation Commission, from whom prior.
approval is required for facilities in the coastal zone.
Public hearings are begun in the county of the proposed sites in the
interval from 60 to 90 days after the filing of a notice of intent. Hearings
are to conclude within 90 days of commencement. Within 90 days after the con-
clusion of hearings, the council issues a preliminary report on the notice of
intent. Thirty days are provided for distribution of the preliminary report and
another 60 days for written responses thereto. Within 120 days of the issuance
of the preliminary report, the final report is to be prepared and distributed.
Public hearings on the final report are to commence within 30 days of its release
and conclude in another 30 days.

Among other things, approval of the notice of intent requires that at
least two of the three alternative sites and related facility proposals be found
acceptable. Approval of the permit with only one acceptable site is possible
under certain conditions. If no acceptable site is found, but.the need for a
power plant established, the commission may designate a feasible site and related
facility, if so requested by the applicant.
The above process may proceed simultaneously with the processing of an
application for a Certificate of Public.Convenience and Necessity by the Public

Utilities Commission.
At least 18 months before the planned commencement of construction, a
utility must file for certification of a site and related facility found accept-
able under the process described above. An environmental.impact report is then
prepared, with the commission acting as lead agency except where the Coastal
Zone Conservation Commission has jurisdiction. A new round of agency review and
public hearings-is,initiated with, a -final decisiondue within 18 months of the
filing for certification. Sites in the coastal zone will not be certified until
a permit is issued by the appropriate (re
gional or state) coastal zone commission.

.(5) Site Acquisition
Utilities have 'the power.of condemnation. The utility may also be
required to acquire development rights in a buffer zone to insure that maximum
population densities in thearea of the plant would not be exceeded. Maximum
population densities may be established by the commission to protect public
health and safety. For a nuclear facility such population densities may be de-
termined by the Nuclear Regulatory Commission (as successor to the AEC).

(6) Funding
A surcharge of one-tenth of a mill per kilowatt-hour of electric power
produced, subject to annual revision, is used to finance the operation of the
Energy Resource Conservation and.Development Commission. In addition, the filing
of a notice of inteqt@requires submission of a fee of 1(@ per kilowatt of net
electric capacity of the largest proposed alternative-within the range of $1,000
minimum to $25,000 maximum total. Applications for other types of facilities
(e.g., transmission lines) must be accompanied by a $5,000 fee.

b Maine

,(I) General Approach
Due to increasing pressures to-locate petroleum refineries in the coastal
zone, and for other reasons, the State of Maine has developed its principal state

land use control program around the siting of large-scale facilities involving
more than-20 acres of land or water. This includes all energy facilities which
meet the size criterion. Although Maine does not specifically address energy
facility sitingas a separate issue, it does administer (as do some Great Lakes
states) a complex set of fairly broad programs for environmental,protection and
natural resource management, and these influence energy facility siting and/or
.the coastal zone. Included in this set are programs for the siting of major
developments (including energy facilities), long-range energy planning, oil and
gas conservation and development control, air and water pollution control, public
utility regulation, the protection of coastal wetlands, the alteration of rivers
and streams, shoreland zoning with jurisdiction up to 250 feet from coastal waters,,
,the protection of critical areas of scenic, scientific, or historical value, and

state land use planning and regulation in unorganized territories of the state.
Maine is currently developing a coastal zone management plan but has not as yet
adopted policies specific to the siting of energy facilities in the coastal zone.
Local autonomy in land use and deve lopment decisions is deeply ingrained,
and coastal zone management in the State of Maine has encountered considerable
local opposition [456].

(2) Long-Range Plans and Forecasts
Underthe Energy Resources Act the state Office of Energy Resources (OER)
is engaged in independent, long-range energy planning. The OER provides technical
advice on energy matters to the Board of Environmental Protection. There do not
appear to be any action forcing provisions which relate energy facility site
approval to long-range plans and forecasts prepared by the state. The private
sector prepares its own plans and forecasts for future energy development, and
these plans are more influential than state plans.

3) Public Participation
In Maine an applicant must possess all the necessary state and local
permits and license .s in order to apply for a permit under the Site Location of'

Development Act. Public participation in. the siting decision process begins
with the public hearings held on these various Ipermit and license requirements.
In addition, the preheari ng conference and the formal decision hearing are also
open to the public. Project-related.files of the Board of Environmental Protec-

tion are open to public inspection.

Certification Procedure

The certification of a site for any type energy facility revolves around
the permit sIystem established by the Maine Site Location of Development Act.
Site approval and environmental certification of the facility are combined into
one comprehensive application process. For petroleum refineries, port'and ter-
minal handling facilities, and very small electric generating facilities for
the site location permit is essentially all that is required at the state level.
For electric generating facilities of 1,000 kW capacity or larger, the Maine
Public Utilities Commission must also approve the proposal by granting a Certif-
icate of Public Convenience and Necessity.
The process begins with the filing of an application for a site location
permit for a power plant, refinery, or other energy facility. At this point the
applicant must possess all the necessary local licenses and permits, as well as
proof of ownership of the site. Although the board does require that local
conditions be met, it retains the authority to override local approval. All
final.approvals on the state level are handled by-the board. The information
'requirements of thes e permits are consolidated into one application form.
Following notification by a developer, the state has 30 days to hold a
public hearing on'the proposal., The board may hold a prehearing conference to
expedite the conduct of the hearing. At the formal hearing, appropriate state
agencies present testimony. The burden of proof is on the developer to satisfy
the following criteria:
9 Financialcapacity. The developer must have the financial capacity
and technicalability to meet air and water pollution control standards and make
adequate provisionfor solid waste disposal, the control of offensive odors and
the securing and maintenance of sufficient and healthful water supplies.
Traffic movement. The developer must make adequate provision for
traffic movement'of all types out of or into the development area.
0 No adverse effect on the natural environment. The developer must
make adequate provision for fitting the development harmoniously into the existing

natural environment and ascertaining that the development will not adversely
affect existing uses, scenic character, or natural resources in the municipality
neighboring municipalities.
Soil types. The proposed developmentImust be built on soil types
suitable to the nature of the undertaking [508].

(5) Site Acquisition
Site acquisition is the responsibility of the energy corporations. With
regard to electric generating facilities, the utilities may exercise the power of
eminent domain, subject to approval by the PUC. The'applicant for a site location
permit must demonstrate that the proposed site has been,acquired, before the

permit can be issued.

(6) Financing
Maine's site location permit program is financed through.the'normal
state budgetaryprocess and does not entail application fees or production sur-

charges.

c. Maryland

(1) General Policy Approach
The State of Maryland has developed a centralized. program to regulate the
siting of all electric generating facilities. Some elements of this program are
considerably different from those adopted by other states,,while other'elements
are fairly commonly applied. The scope of this program is limited to electric
generating facilities. The siting of other types of energy,facilities is handled
under separate regulatory mechanisms with a lower degree of state involvement.
The Maryland program has pioneered what is generally referred to as the
one-stop decision process. In this particular approach, input by the state
agencies responsible for economic, health, environmental, and planning consider-
ations is incorporated into a single, final decision by the Maryland Public
Service Commission. The overall program is basically composed of four sub-
programs dealing with site evaluation, site acquisition, monitoring, and research.
The basic thrust of the program is to predict the impact of proposed generating
facilities, to assess the impacts of existing facilit ies, and to acquire alter-
native sites for utilities unable to find suitable sites on their own.

The Maryland Department of Natural Resources also plays a major role in
the power plant siting program by conducting environmental impact as sessments
and suitability analyses of alternative site proposals. Other major elements of
the Maryland program include preemption of local authority in siting matters,
requirements for long-range plans and forecasts, and a comprehensive application
procedure for site approval.

(2) Long-Range Plans and Forecasts
Like other states having established active state-level roles in the
regulation of electric generating facilities, Maryland requires all electric
utilities to prepare, on an annual basis, ten-year plans specifying future
resource requirements and proposed, potential sites for new facilities. The
Public Service Commission compiles and evaluates the various ten-year plans and
identifies proposed future site locations. Following the filing of the plan with

the PUC, the DNR is notified of the proposed sites outlined in the ten-year plan.

The DNR then conducts a detailed environmental assessment of.the sites. The

general assessment criteria applied to the sites are essentially the same as
those outlined in the National Environmental Policy Act of 1969. If the DNR
determines that a proposed site is unsuitable, the Public Service Commission
must,delete this site from the ten-year plan. If it is found that a site is
likely to result in a violation of applicable federal or state environmental
standards, the site must be declared unsuitable. This implies that prospective
sites are evaluated with sufficient detail to determine compliance with air and

water pollution standards.

(3) Public Participation
Maryland requires public disclosure of the annually updated long-range
plans and forecasts prepared by the electric utilities. Public hearings are
held on all Certifications of Public Convenience and Necessity and all associated
materials are available for public inspection. Although public hearings are not
required at other points in the process, they may be held at the discretion of

state officials.

(4) Site Certification
Following the preliminary screening of sites outlined in a particular
ten-year plan, the DNR conducts detailed assessments of sites deemed suitable.

This. amounts to the preparation of a formal environmental impact statement on the
site. The final EIS on the site.must be published at least two years prior to
the proposed date of construction as outlined in the ten-year plan. At this
point, the formal application procedure for approval of a specific site begins.
The principal means of formal site approval is the Certificate of Public
Convenience and Necessity. The certification process is handled by the Public.
Service Commission with the technical advice and recommendations of the Depart-
ment of Natural Resources. Within 60 days after an application has been filed
with the commission, the DNR is notified of the application and is directed to
complete any additional study and investigation necessary, including, but not
limited to, the necessity for dredging and filling at the plant site and the
water requirements of the facility. At some point following the filing of the
application, the PSC establishes a date for the formal administrative hearing.
Following the testimony presented at the hearing, all interested parties are
given 15 days within which to modify, affirm, or amend their initial recommenda-
tions. The.,final decision on the application must be mad,e by the PSC within 90
days after the hearing. Due to the extensive preliminary evaluations of alter-
native sites, the amount of information required in the certificate application

is somewhat reduced.

The monitoring program is designed to provide feedback to the overall
energy facility siting program. As part of this program,. the DNR issues, on a
biennial basis-, a cumulative environmental impact statement of all power plants
currently operating in the state.

(5) Site Acquisition
This phas e of the power plant siting process is one of the more inter-
es,ting elements of the Maryland program. The state is actively engaged in the
acquisition of sites determined suitable. Within two years of the date on which the
prospective site is identified by the state, a detailed environmental assessment
is prepared and the site is either accepted or rejected. If accepted, the site
is acquired by the state through voluntary agreement or by condemnation.

The electric utilities may also acquire prospective power plant sites
although such sites must undergo the same environmental assessment as those
owned by the state. The inventory of suitable state-owned sites serves as a
source of alternatives from which the utilities may lease or purchase sites in
the even't that their own sites are unsuitable.

(6) Financing
In order to administer the*program, Maryland established the Environmental
Trust Fund. The fund, administered by the Secretary of Natural Resources, is
derived from a one- to three-tiehths mi.11 per kWh surcharge on electricity gen--
erated within the state. The electric utilities are specifically authorized to
.add.thefull surcharge to customers' bills. The fund is used to administer the
program and to acquire prospective sites.

d. 'Massachusetts

General Policy Approach
Massachusetts has adopted one of the most comprehensive energy facility
siting regulatory pr6grams'in the nation. The program includes electric gen-
erating facilitie's of 100 MW or more capacity, facilities for manufacturing or
storing gas, and facilities for refining or storing,petroleum. The organization
responsible for implementing energy siting policies is the Energy Facility Siting
Cou.ncil. The'council is composed of the secretaries of the Departments of
Environmental Affairs, Consumers Affairs, Manpower Affairs, and Administration
and Finance, and five governor appointees: one representing conservation and
protection'., bf the'environmen@t, one professional engineer, and one each*knowl@
edgeable' of electricity, gas, and oil industries, respectively.
The siting regulatory process is fairly centralized and can best be
Aescribed as a one-stop process. The council has Authority to preempt other state
and local requirements.

(2) Long@-Range Plans and Forecasts.
All electric utilities are required every five years to submit a long-
range electric power forecast covering the subsequent ten-year period. In
addition,.updates and revisions must be filed every year. In preparing the ten-
year forecasts the utility must provide the following information:
e A description of all existing agreements with other electric companies
for joint planning or joint fore casting of electric power needs and the purchase
or sale of electric- power or reserve capacity.
0 A forecast of the electric power needs for its market area, taking
into account wholesale bulk power sales or purchases or other co-operative ar-
rangements with other utilities and electric energy policies as adopted by the-

100

commonwealth.

e A description of actions planned to be taken by the company which
.will affect its capacity to meet such needs, including:
- expansion, reduction, or removal of existing facilities
- construction or acquisition of additional facilities
- description of alternatives to planned action such as:
other methods of generating

other site locations

other sources of electrical power

no additional electric power.
a description of environmental impact of each proposed facility.
In this regard, the council shall, after public notice and a period for comment,
be empowered.to issue dnd revise its own list of guidelines providing a minimum
of data for initial review of impacts on land use, water resources, air quality,
solid waste, radiation,.and noise.
Within six months of submittal of the plan, a Dublic hearing is held, and
the council accepts or rejects the plan in whole or in part within one year of
filing. In making this decision the council insures that the following conditions

are fulfilled:

9 All information relating to current activities, agreements and policies

as adopted by the.commonwealth is substantially accurate and complete.
e Projections of demand for electric power and of the capacities for
existi ng and proposed facilities are based on substantially accurate historical
information and reasonable statistical projection methods.
e Projections relating to service area, facility use and pooling ar-
rangements are consistent with such forecasts of other companies subject to this
chapter as may,have already been approved, and reasonable projections.of activ-
ities of other companies in the New England area.
Plans for expansion and construction of the applicant's new facilities
are consistent with current health, environmental protection, and resource use and
development policies as adopted by the commonwealth.

(3) Public Participation
Public hearings are held on all long-range forecasts and in localities
where prospective electric generating sites are identified in the plans. Public
disclosure of this@information is required. In addition, at least two hearings

101

are held on each notice of intention to construct and operate an energy facility.
Hearings may also be held on applications for Certificates of Environmental
Impact and Public Need.

(4) Certification Procedure

The'principal mechanism for siting certification in Massachusetts is the
notice of intention. This process applies.to all types of energy facilities
covered by the program. At least two Iyears prior to the expected commencement
date of construction the applicant must file a notice.of intention with the
council. Separate and distinct from the notice of intention is the processfor
the Certificate of Environmental Impact and Public Need., Any energy company may
petition the council for a certificate if one of the following conditions exist:
The applicant is prevented from building a facility because
it cannot meet standards imposed by a state or local agency
with commercially available equipment.
There has been an undue delay imposed on the applicant by
state or local agencies.
There are inconsistencies among resource-use permits issued
by state or local agencies.
There are nonregulatory issues or conditions imposed by
state or local agencies such as aesthetics, recreation, etc.
There are disapprovals, conditions, or denials by local
governments [5081.
Information required in the application includes:
� A description of the location of the facility to be constructed or,

operated thereon.
� A summary of the studies which the applicant has made of the environ-
mental impact of the facility, and a statement of the reasons for the choice of

the location.

o A copy of the long-range plan approved by the council in proof of the
need for the facility to meet the energy requirements of the applicant'.s market
area, taking into account wholesale bulk power sales or purchase or other co-
operative arrangements with other utilities and electric energy policies as
adopted by the commonwealth.
0 A statement setting forth the need of:the applicant for the certifi-
cate, including:
all licenses, permits and other regulatory approvals required by
law for the construction or operation of the facility which have been granted.

102

indication of the good faith effort made by the applicant,to
obtain from state agencies and local governments the licenses, . permits and other
regulatory approvals required by law for construction or operation of the facility.
indication as to the inability, if any, of the applicant to com-
ply with any law, ordinance, by-law, rule and-regulation affecting the construc-
tion or operation of the facility.
indication As to the applicant's inability to proceed with the
construction or operation of the facility by reason of the denial, delay, oi,
imposition of a burdensome'condition-in issuing specified,licenses.- permits or

approvals.
Only those council members with interest or expertise in a particular
type of facility may participate in decisions affecting that particular type of
energy facility. For instance, the oil and gas industry representatives may not
vote on decisions concerning electric generating facilities.

(5) Site Acquisition
Electric and gas utilities can employ the power of eminent domain, subject
.to approval by the Department of Public Utilities, to acquire land for sites,
but, in general, site acquisition is achieved through voluntary purchase agree-

ments.

(6) Financing
Massachusetts employs an application fee of $25,000 maximum for each'
certificate application. For each forecast or supplement thereto the electric
..utility industry is also assessed a total of $400,000 which is broken down ac-
cording to the proportion of electric energy generated by each utility A
similar proportional assessment is levied on gas companies based on a total
industry assessment of $125,000 annually. Finally, each notice of intention to
construct an oil facility must be accompanied by a filing fee graduated'in ac-
cordance,with the expected capital investment in the facility to a maximum of
$400,000. Revenues are employed for program administration.

e. Oregon

(1) General Approach

On June 30, 1975, the Energy Facility Siting Council replaced the Nuclear

103

and Thermal Energy Council, which had been in operation four years. The Energy
Facility Siting Council consists,of seven public members appointed by the
governor subject to senate confirmation. The powers.and duties of the council
include:
9 preparation and execution of studies, investigations, research and
.programs relating to all aspects of site selection
'6 designation of areas within the.state suitable or unsuitable for
various types of energy facilities
0 establishment of standards and promulgation of rules that applicants

for site certificates must meet.

The council is responsible for siting power plants, transmission lines, solar
collectors and pipelines above specified minimum sizes.
Oregon also has a Department of Energy whose duties include:
collection and dissemination of information and data on energy@
resource:, including an annual forecast
0 education of the.public regarding energy problems and means of con-

servation

0 coordination of energy research.
in addition to these agencies, there is an Energy Policy Review Commit tee
consisting of nine members appointed by the governor@ the president of*the senate
and the speaker of the house. The Committee's functions are primarily to review
programs, rules and reports and to make recommendations on all aspects of energy
policy.

(2) Long-Range Plans and Forecasts
The Department of Energy issues an annual forecast of the energy situ-.
ation as it affects Oregon. The forecast is to include estimates of energy
demand, resource availability and the impacts of conservation, new technology
and future construction. The forecast covers the five years as well as the.tenth
and twentieth years following issuance of the forecast.
Information and data for the,.forecasts are to be supplied by all producers,
suppliers and major consumers of energy resources and by political subdivisions
of the state. Subpoena power may be employed to obtain information, but data
must be kept confidential and presented in such a way as to conceal the source
if so requested.

104

A preliminary forecast is required of the department by July 1. Public
hearings must be scheduled withi@ 45 days and the final forecast must be issued
by January 1.
The site certification process includes a provision for a notice of
intent to file an application for a site certificate. This noticeof intent to
file must be filed at least twelve months prior to the filing of the application
for a site certificate and must identify the proposed site.

(3) Public Participation
The Department of Energy holds public hearings on the annual long-range
forecast as described in Section (2) above. Preliminary forecasts are made avail-
able to anyone who requests one at a fee not to exceed the cost. The final fore-
cast is included in the annual report of the Energy Council to the governor and
the legislative assembly.
Upon receipt of a site application, the Siting Council holds public
hearings in the affected area and elsewhere as it deems necessary. Any person may
appear and present testimony at the hearings. The recommendation of the council
is subject to judicial appeal. Public hearings are also held prior to deter-

mining whether areas are suitable or unsuitable for energy,facilities.
The.Energy Facility Siting Council is comprised of general public members.
Appointment to the council is denied to anyone with pecuniary interest in energy
facilities, and employment by an owner or operator of an energy facility is pro-
hibited for two years subsequent to councilmembership.
The council must designate the local governing body (of the city or county
host to a proposed site) as a special advisory group and may appoint additional
advisory groups as it deems necessary.

(4) Certification Procedure

The Energy Facility Siting Council is charged with advance,designation of
sites as suitable or unsuitable for thermal power plants (nuclear and fossil)
larger than 200 MW, geothermal power plants, and any additional energy facility
type for which the council determines such designations necessary.
The first step in site certification is the notice of intent to file an
application for a site certificate, which must precede the application itself by
at least twelve months and include identification of the site. The Energy
Facility Siting Council gives public notice that the intent has been filed.

105

Copies of both the notice of intent and the application for site certif-
icate are sentfor comment and.recommendation to twelve state agencies and to any
affected city or count y. A time limit for response is s et by the council., The
council may commission an independent study of any aspect of the proposed facil-
ity to be funded from the application fee.
Public hearings are held in the affected area and elsewhere as necessary.
Following the hearings and the receipt of any au. thorized studies, the council
may reject, recommend, or recommend withconditions the application for a site
certificate. Time limits from the filing of an application to final council
action are specified as follows: 24 months for a thermal power plant, except
combustion turbine types for which the limit is 9 months; 6 months for most
expansions of energy facilities; and 12 months for other energy facility con-
struction.. The governor has thirty days in which to execute the certificate.
The site certificate is executed by the governor.arrd the applicant and
includeslauthorization both to construct and operate the proposed facility,
-subject to any conditions which may,be specified in the certificate. Local'
regulation is preempted by the state.., State agencies are to issue the appropriate
permits, licenses and certificates subject only to conditions of the site certif-
icate, though the individual agencies continue to exercise enforcement authority.

(5) Site Acquisition
The siting legislation does not provide,any special means of site
acquisition. The Siting Council is charged with designating areas of the state
as suitable or unsuitable for use as sites for various types of energy facilities.
Applications are not accepted for sites in unsuitable areas. Public utilities
have the power of eminent doMa4n for the purchase of sites.

(6) Financing
A $5,000 fee is required with each notice of an intent to file for a
site certificate.' This wilibe credited against any subsequent fees. Site
certificate applications requir'e,*fees.of 5(@ per kW of planned maximum net elec-
tric capacity or $1,000 for each $1 million of estimated capital investment in
any.other proposed facility or addition. In addition, thermal power plants must
pay an annual fee of 2.5 0, per W of maximum net capacity authorized by the site
certificate. Other energy facilities are assessed $300 for each $1 million of
estimated capital investment. Furthermore, the statets gas and electric utilities

106

are assessed a total of $300,000 annually on a proportion.al basis.
.Funds from application fees are used solely for conducting studies with
respect to the proposed site. Unused funds must be-returned to the applicant.
The annual assessments are used for the operations of the Department of Energy
and the Siting Council.

f. Washington

(1) General Approach
The energy facility siting program in Washington is among the most com-
prehensive in that it provides for the siting of pip@!Iines, refineries, oil ports,
.and transmission corridors, in addition to power plants. Responsibility for this
program lies with the Energy Facility Site Evaluation Council which is composed
of the administrators, or their designees, of fourteen state agencies and an ad
hoc member appointed by the county legislative body with jurisdiction over the
proposed site. The director of the state Energy Office serves as non-voting

chairman of the council. The decisions of the council serve as recommendations

to the governor, who has final authority to approve or reject site applications.
The state Energy Office is responsible for energy resource data collec-
tion, analysis and dissemination; the coordination of research and other
activities; advice to and support of state agencies on energy matters; and guide-
lines for conservation plans. The director of the Energy Office is appointed by
the governor with the consent of the senate.

(2) Long-Range Plans and Forecasts
The state Energy Office has responsibility for producing analyses of
projections and/or forecasts of energy supply and demand. The legislation does
not specify a time interval to be covered by such analyses or a frequency for
their production, but they are to be prepared "as necessary for development of
recommendations with respect to the timing of construction of additional facilities
and other energy programs." There are no provisions for public disclosure of
plans/forecasts; in fact, the law shows concern -only for protecting the confi-
dentiality of information, if so requested.

(3) Public Participation
The Energy Facility Site Evaluation Council holds hearings on proposed

site locations.

107

(4) Certification Procedure
The Energy Facility Site Evaluation Council receives all applications
for site certification. The council then commissions its own independent con-
sultant study to measure the consequences of the proposed facility on the
environment. Within 12 months of the receipt of an application, the council must.
report its recommendation to the governor as to the approval or disapproval of
the application. If the application is approved by the governor, the council
has 30 days thereafter to compose and submit a certification agreement for exe-
cution by the governor and applicant.

(5) Site Acquisition
Utilities do not have the power of eminent domain in Washington. Sites
or options thereon are generally purchased prior.to commencement of.the appli-

cation process.

(6). Financing
A-fee of $25,900 must accompany each site application. This fee is 'used
to fund the environmental impact study and any unused portion is returned to the
applicant. Studies,whose cost exceeds the fee must be approved and paid for by

the applicant.

4.@ COMPARATIVE ANALYSIS OF STATE PROGRAMS

This section provides-the means for comparing and evaluating the state
energy facility siting programs.previously described (Sections.2 and 3). While
no critical evaluation of individual programs will.be,undertaken here, such
efforts by appropriate state personnel and interested citizens are encouraged.
The material.in this section may provide the basis for such an evaluation.

a. S'elected Features bf@State Programs
Table 7 summarizes.the descriptions of 14 state energy facility siting
programs. The 21 features listed.are divided into six general categories: the
state's general approach to siting; provisions for long- range plans and fore-
.casts; provisions for public participation in the siti ng.process; selected fea-
tures of the actual site certification process; the various means by which site
,selection is achieved; and different methods of financing the,siting program.
The individual features under each of these categories are described below.

108

TABLE 7 FEATURES OF STATE ENERGY FACILITY SITING PROGRAMS

Gener9l Plans and Forecasts
Principal Types of Local elation Conserv. Public Time Appr ocument.
t jRto CZM oval D
Agency Facilities Preemp Program Discl. Frame Process of Method.

Illinois Commerce No --- --- %10
Commission

Indiana PUC --- By Em. --- No
Domain

Michigan DNR/PSC No Unspec. None No ---

Minnesota Environ- PP (50 MW) Yes Regional Energy Yes P-5 None Utility
mental TL (200 kv) Zoning Agency Biennial
Quality Preempted F-15
Council
New York Board on PP (50 MW) Yes lUnspec. Utilities Yes P-10 Public Assump-
Electric must Hrngs. tions and
Generation describe data
and Siting

Ohio Power PP (50 MW) Yes Unspec. Utilities Yes P-10 Public Method,
Siting Gas & Elec. must show Hrngs. Assumpt.
Commission Trans. impact and data

Pennsylvania Dept. of Condi- None No --- ---
Envr. tional
Resources/
PUC

Wisconsin DNR/PUC PP (300 MW) Yes Unspec. Utilties Yes Biennial Public NO
TL (100 kv) must P-10 Hrngs.,
describe Agency
leview

California Energy PP (50 MW) Yes --- Cons. Div. Yes Biennial Public State
Resource TIL within F-5,10 Hrngs. Specifies
Conservation ERCDC 20 State
& Dev.,Comm. Approval
Maine @Dept. of All EF Yes Unspec. --- No --- ---
Envr. over 20 ac.
Protect.

Maryland PSC/DNR All PP Yes Unspec.. Yes P=.10 Eval. of No
TL (69 kv) Sites in
Plan

Massachu- Energy PP (100 MW) Yes Unspec. --- Yes P-10 Public No
setts Facilities TL (69 kv) Hrngs.
Siting ST (500 Council
Council kbbl) Votes
Others

Oregon Energy PP (25 MW) Yes None Dept. of Yes P-5,10 Public No
Facility TL (230 kv) Energy 20 Hrngs.
@Siting geotherm. F-1-5, State
lCouncil PL, Solar 10,20 Compiles

Washington Energy Fac. All EF NO Shoreline State No As Energy No
Site Eval. Permits lEnerev lNecess. Office
Council Preempted Office 1Prepar
esi

KEY: PP - Power Plants ST = Storage Tanks P = Plans
TL = Transmission Lines PL = Pipelines F = Forecasts
EF = Energy Facilities OR = Oil Refineries

109

TABLE 7 (Continued)

Public Participation Site Certification Site Selection Financing
Agency Access I Public One, Time' Envr. Alternate Site Site Applic. Annual
Members to Info Hrngs. Sto Limits Assess. Sites Select. Acquis. Fee Fee

--- --- Facility No --- --- --- Private Cond. Em.
Certific. Sector Domain

--- No No --- --- Private Em.
Sector Domain

--- Notice, of Air No --- By Exec. --- Private Em. --- ---
Envr. water Order Sector Domain
Permit Permits
Applic. Etc.
7S Yes Criteria, Yes PP (I yr) EQC One State Em. $500/ Based on
ic Inventory, TL (180) Staff Alt. Site Domain million kwh + $
4FM Site Inventory ($5000 sales
Certific. min.

4S P lans, LR Plan Yes Hrng. 6-7 DER as One Site Suit- Private $25,000 ---
IA Applic. Pre-applic. mos after part of Alt. ability Sector
for Cert. Application applic. applic. Criteria

4S Plans, LR Plan Yes 2-5 yrs. PSC/1 Four Site Suit- Private Formula ---
1G Applic.,, Pre-applic. DNR/ Total ability Sector for PP
for Cert. Application EPA Criteria

Notice of Hrngs. on No --- No --- Private ',ondi-
Envr. Pre Envr. Formal Sector tional
Applic. Permits Require- Em.
Ment Domain

LR Plan Plan, 2-Stop SM. PP + DNR No Private Condi@ ---
Site IDNR/PUC TL (150) Sector tional
Cert:rf. 1g. PP, Em.
(480) Domain

5PM Office of Plans Yes 18 mo. Siting Three Private Em. 0 mills/ .1 mill/
l
Public Forecasts, Except CZ Agency Total, Sector Domain capac. kwh
Advisor Site (ERCDC) '0.ne ($1000 to
Certific, Inland $25,000)

lopm Notice of Pre-applic. Yes Hrng. 30 Part of No Private Em. ---
is Permit hr-ng, siting da. after Permit Sector Domain
Applic. hrng. ap lic. Applic.
PSC LR Plans Applic. Yes 2 yrs. DNR Yes Site In- By State --- .1 - .3
Members EIS Sites Conference minimum ventory & and mills/
Applic. Utility Utility kwh

4S LR Plan LR Plan Yes PP(6 mo.) Dept. of No Site Em. ?25,000 Complex
2PM Notice of Notice of OR(1-2 yr) Envir. Suitabil- Domain :or PP, Fee on
3G Intent Intent Affairs ity omplex Plans &
Applic. Applic. Criteria -or EF Forecasts

7PM LR Plans P+F Yes w/ PP(24 mo) Indep. No State Condit. 50 mills/ 25 mills/
Suitable Governor Other EF Study Desig. Em. kw kw
Areas, (6-12 mo.) Possible Suitable Domain 1% of $3001$
Site Cert. Regions invest. million

Not Site No 12 Mo. + Indep. No Private No Em. $10,000
Specif. Cert. ocal & 60 da. + Private Sector Domain
overnor 30 da. Consult.

S State Agency Heads G = Other Governor Appointee
PM'= Public Membir A - Ad Hoc Member
(Appointed by Governor)

1 Days, unless indicated otherwise.

110

(1) General
These features describe the methods which each state employs to accomplish
energy facility siting.@

.(a) Principal agency
This column lists the one or two agencies with primary responsibility
for energy facility siting'. Common-abbreviations are used.

(b) Types of facilities
This column indicates the types of facilities regulated by the state
siting agency. A blank indicates that any regulation of siting is simply a part
pf the utility regulation process and not addressed specifically by the state.
Minimum sizes are indicated for power plants (PP), transmission lines (TL), and.
petroleum storage tanks (ST) where appropriate. Oregon includes pipelines (PL),
geothermal facilities and solar collectors among its regulated facilities.

(c) Local preemption
This column indicates whether or not local zoning laws are preempted by
the state in energy facility siting. In Indiana, the utilities' power of eminent
domain supersedes local zoning,and utilities are-generally unrestricted in their
site selection. In Pennsylvania, the commonwealth may grant eminent domain
powers -that override local zoning restrictions.

(d) Relation to CZM

This column specifies what, if any, relationship exists between the
regulation of energy facility siting and the management of the coastal zone.
At present, only California provides for coordination between the agencies re-
sponsible.for coastal zone management and energy facility siting. This is
expected to change as other coastal states develop,their coastal zone management

programs.

(e) Conservation program
One approach to the regulation of siting involves.efforts by the state
to reduce the demand for sites by reducing the demand for energy. The state
itself may assume an active role in conservation or it may require that indus-
try implement conservation programs.

(2) Long-Range Plans and Forecasts
The construction plans and demand forecasts of-the energy industry are
important to the siting process. The states have various ways.of handling
plans and forecasts.

..(a) Public disclosure
This column indicates whether or not industry plans and forecasts are
made public. Such plans and forecasts are generally required of those industries
whose siting is regulated by the state. The law in Washington allows the state
siting council to obtain information from the industries but does not provide
for public disclosure of that information.

(b) Time frame
The period to be covered by the required plans (P) and forecasts (F) is
indicated, Forecasts are often included as part of a plan where only the latter
is indicated. Plans/forecasts are to be submitted annually unless otherwise

indicated.

(c) Approval process
The means for approving plans/forecasts is indicated in this column.
Approval implies that the plan will assume a formal role in the regulation of
siting, such as a requirement for subsequent siting proposals to conform with
the plan.

(d) Documentation of methodology
This column indicates.the means by which the forecast methodology is
documented. The state either requires that the forecaster.describe his method-
ology, including the data and assumptions employed, or the state may spe6ify
the methodology to be emplo@ed:

@3) Public Participation
The states provide a variety of devices for involving the public in the
siting process. The previous section (Plans and Forecasts) implies some public
role in the states with regard to disclosure of long-range plans and the require-
ment for public hearings on the approval of plans. Additional public parti&ipa-

tion is indicated in this section.

-112

(a) Siting agency members
This column shows the composition of the state energy facility
siting council. The council usually includes public members appointed,by the
governor (PM) or representatives of state agencies (S). Other governor appoint-
ees (G) represent special interests, and New York provides an ad hoc member (A)
to represent the locality in which a site is being considered for approval.

(b) Access to information
This column indicates the provisions for keeping the public informed on
various aspects of the siting process.

(c) Public hearings
This column indicates whether public hearings are held, and if so, for which
aspects of the siting procedure they are held.

(4) Site Certification
This section is comprised of selected features of,the actual site

certification process.

(a) One-stop siting process
An affirmative response here means that a single agency has responsibility
for site certification. Facility certification may be performed separately by
the public utilities commission, the department of natural resources,, or the
environmental protection department.

(b) Time limits
This column indicates the period of time alloted for the site certifica-

tion process from the receipt of the application through final approval. Other
time frames are specified where appropriate. This time may be different for
power plants (PP), transmission.lines (TL), oil refineries.(OR), or other energy
facilities (EF).

The entity responsible for the assessment of environmental impacts on
proposed sites is listed in this column.

113

M Alternate sites
This column indicates requirements for the proposal and consideration
of alternate sites as opposed to an application for approval of a single site.

(5) Site Selection
This category is divided into two components; site selection and site
acquisition.

(a) Site selection
This heading re fers to the choice of a site or sites to be proposed for
construction of an energy facility. The private sector (utility, etc.) is
usually free to find and propose sites, but some states have chosen to enter
the process at this early stage. The state may establish criteria for the
selection of sites or take a more active role in the procesTs.

(b) Site acquisition
Eminent domain is generally provided to regulated utilities while other
energy industries must purchase sites on the-open market. Eminent domain powers
may be conditioned upon site certification.

(6) Financing
The two common methods for financing the energy facility siting program.
are the application fee and the annual fee.

(a) Application fee
This is a fee assessed with each application for site approval. The fee
may be based on the proposed capacity or cost of the facility.

-(b) Annual fee
The annual fee is used to finance general agency functions and is often
based on annual electricity production, either.in terms of kilowatt-hours or
dollar value or both.

(b) Evaluation Criteria
This section will suggest a set of criteria'by which siting regulation
programs may be evaluated. These'criteria@have been drawn together from a

114

variety of sources.' Most of them, rather than specifically addressing energy
facility siting, focus on some aspect of public sector decision making.

(1) Resolution of Conflicts of Interest
The program should prvide for the resolution of conflicts among all
interests. Government should seek to identify and provide for the public inter-
est, which in this case may be considered to consist of several special inter-
ests, including the assurance of a reliable supply of energy and the protection
of the environment. There are also components of the public interest concerned
with economic matters (e.g., low utility rates, return on investment by utilities,
etc.) and environmental sub-interests related to the coastal zone. These inter-
ests and others must Ul be considered together and balanced against one another
in the siting of energy facilities.
Conflicts.have arisen over the use of different types of fuels dueto
the inherent interrelationships among the various forms of energy and predic-
tions of scarcity, both real and artificial (e.g.,.an oil embargo) of certain.
forms. The production of electricity may entail the use of fuels better used
for other purposesi and electricity itself becomes a form of energy that is
interchangeable to some degree with various fuels. The issue of energy use as
opposed to conservation is also one that states may choose to address.

Accountability to the Public
Those responsible for energy facility siting regulation should be
accountable to the public and responsive to public needs and desires. Maximum
accountability is achieved through direct popular election, though this method
may be unacceptable for other reasons,.- Provisions to@assure accountability of

appointed decision-makers include the accountability of the appointer and
restrictions on the previous or subsequent employment of decision-makers by
those regulated. An open decision process is also essential.
.Open decision making also promotes responsiveness. Th& process should
afford@meaningful piablic input at public hearings and through workshops, advisory
councils, and, perhaps, representation on the decision-making board. Responsive-
ness is further enhanced by public access to information in a timely fashion.

(3) Effective Planning Mechanism
The process should include an effective planning mechanism. To plan

115

effectively, decision makers require"both information and the authority to
implement plans.* Information includes the long-range plans and forecasts of
energy suppliers and independent (state) data collections and.analysis for
economic and environmental impacts. Effective planning requires knowledge of
how each energy facility will fit-into the ultimate energy scenario for the
state at some future date. The effect of today's decisions on limiting future

choices must be considered.

(4) Coordination with Other Programs
The facility siting program should be coordinated with other energy and
land use programs. Facility siting should account for the inherent interrela-
tionshilps and interchangeability among all forms of energy. An overall energy
policy which addresses alternative uses of.fuels, innovative technologies, and
conservation should be developed at the state level and coordinated with facility
siting. Siting should also be coordinated with programs affecting land use in
critical areas or the,.coastal.zone or general programs for the siting of large

facilities.

(5) Regional Needs
Energy facility siting should provide for regional needs. The site
certification process should preempt local zoning and other local land use au-
thority in order to assure a more rational program based on issues other than
local in nature. Energy facilities require consideration of regional, state,

interstate and national needs and-resources.

.(6) Environmental Protection
The siting process should specifically address protection of the envi-
ronment, especially the-coastal zone. Protection of unique and fragile eco-
systems should be a primary concern in energy facility siting. The coastal zone
is a small portion of -total land area but is subjected to the greatest develop-
mental pressures. The unique ecological, recreational, and aesthetic aspects
of the coastal zone require special consideration and protection in any program
for energy facility siting..

(7) Energy Supply
The siting process should facilitate provision of an adequate supply of

116

energy. The process should commence sufficiently in advance of planned construc-
tion to preclude delAy in the availability of new sources of energy. Time limits
should be established for the various phases of the process. "Generic" issues

common to several facilities or sites should be resolved in advance of the

siting process to obviate repeated consideration and arbitrary decisions.

(8) Funding
The energy facility siting program should be adequate ly funded. The
effectiveness of the program should not be constrained by a lack of resources.
A permanent staff should provide information on environmental, economic, and
other issues to promote consistency and expertise in the siting process.

5. IMPLICATIONS FOR POLICY OPTIONS

The existing institutional arrangements governing energy facility siting
in the Great Lakes Basin have several significant implications for the kinds
and ranges of options that can realistically be implemented by the,states. At
the federal level, the policies and performance standards of the Clear Air Act
and the Federal Water Polluction Control Act are of fundamental-importance to
siting. Options available to the states with regard to federally established
environmental protection standards are subject to a one-way flexibility; the
states cannot institute standards less stringent than those mandated, by the U.S.
EPA. The Coastal Zone Management Act of 1972 as amended, which is ultimately
administered by the states, contains several provisions of primary concern to
this study. Most of these provisions, however, have not been sufficiently
studied to justify definitive statements as to their influence or value. Other
federal agencies concerned with energy facility siting operate under their own
legislative mandates and policies. However, under Section 307 of the CZM Act,

these agencies are required to insure and demonstrate that their actions are
"consistent" with approved Great'Lakes State CZM programs. Consideration must
also be given to the siting of facilities that are in the national interest.
Thus, it behooves the states to consider a broad range of alternative institu-
tional mechanisms with wRich to implement policies for the siting of energy

facilities in the coastal zone.

The preceding overview of state regulation of energy facility siting
indicates that an extremely wide range of factors is at play in determining the
overall regulatory climate. The policies, programs, legal authorities, and

117

social institutions that operate within each state will ultimately determine
those options that are easily implementable, those that will require significant
changes in the existing institutional framework, and those options that are
simply'not feasible. The wide variety of approaches to energy facility siting
regulation exhibited by the Great Lakes states, coupled with the fact,that is
unrealistic to restrict energy facility siting regulation to the coastal zone
management program, dictate that the range of options for institutional alrange-
ments developed later in this report should be broad in scope.
In view of these considerations, an attempt will be made, to the extent
practicable, to tailor institutional options to the specific policies,programs,
legal and organizational arrangements, discussed above. However, it is clear
from the preceding institutional overview that the feasibility or attractiveness
of any set of options will vary a great deal from state to state. A detailed
analysis of the implications of each option as applied to each of the Great
Lakes states requires an intimate familiarity with the situation current in
these states, and is beyond the scope of ihis report. Rather, it is intended
that the institutional options presented will provide a broad-based framework
of cons'iderdtioh from which'skilled, informed individuals at the state level
will select elements for indepth analysis.
One'very significant implication underscored by this institutional
overview clear to all those involved in energy facility siting, is that there is
a pressing need to design regulatory processes that are streamilined,operate
efficiently and are capable 6f insuring decisive action on proposals within well-
defined time periods. However, no process can be successful in the long ruo
unless adequate measures are incorporated to insure consideration of the full
range of public and private concerns for energy facility siting and management

of coastal area resources.

One final point should be addressed in this discussion. The primary
focus of this study is the siting of energy facilities in the coastal zone.
Thus, policy initiatives.in this area by coastal states are of particular inter-
est. A concerted effort was made to identify such initiatives in the states
analyzed in this overview. In addition, several other coastal states were con-
tacted for this purpose. The conclusion that can be drawn is that, in general,
the adoption of policies by coastal states to guide the siting of energy facil-
ities in the.coastal zone is at an early state of development. Several state CZM
programs are currently engaged in this activity, but have notas yet produced
material useful to this study.

119

Chapter IV

TECHNICAL CONSIDERATIONS

A. ENVIRONMENTAL AND ECONOMIC FACTORS AFFECTING THE SITING OF ENERGY FACILITIES,
AND ANALYSIS OF COASTAL DEPENDENCE OF FACILITIES

1. INTRODUCTION

a. Purpose
This section reviews the technical factors, both environmental and
economic, which determine the eventual location of energy facilities, and sum-
marizes the impacts associated with these facilities once they are sited. Also,
it is the intent of this section to determine'the degree to which these facili-
ties are dependent on coastal resources and locations, based on the technical
factors mentioned above. These findings will then provide the basis for the
development of technical pol icy options for the future siting of energy facili-

ties in the coastal zone.

b. Scope
The energy facilities which have been consi dered for this report are
those involved with electrical energy generation, fuel transshipment and storage,
and fuel production. Specifically, they are fossil-fuel (coal) and nuclear gen-
erating plants, coal and oil transshipment and storage,facilities, and petroleum
refineries. Emerging technologies which may s ignificantly affect these fAcili-
ties within the time frame of this report (15-20 years) have been included with
the,facility descriptions.

C. Study A@pproach
The coastal dependence analysis is carried out in several phases. Con--.
siderations associated with the site selection process for energy'facilities are
outlined in general. The facilities are individually described and their speci-
fic siting requirements and considerations summarized. Next, the environmental
and economic impacts associated with the construction, operation and main-
tenance of each of the facilities is reviewed. A facility cost analysis follows
which highlights the relative costs of the essential components of each facility
and indicates how these costs may vary with location.

120

Following these three sections of background information and analysis is
a discussion of those factors determined to be most significant with regard to
the question of coastal dependence. In conjuction with this discussion is the
presentation of a case study that attempti to relate the identified coastal de-
.pendent factors to the final siting decision for a proposed (and approved)
energy facility. Finally, the implications of this coastal dependence discus-
sion are summarized. as they may relate to the technical policy options which
the coastal zone management programs of the eight Great Lakes states may con-
sider in the formulation of their individual energy facility siting policies.

d. Definition of Coastal Dependency
In determining the relative dependence of an energy facility.on a
coastal location,. it is important to understand what is meant by the term coast-
al dependence. To provide latitude for analysis and consideration.1 yet remain
within the confines of the study objective, the following definition was
adopted.
The determination of energy facility location with respect
to the lake shore as expressed through the following general
considerations; system requirements, safety, engineering, en-
vironmental, institutional, and economic.

This definition broadens the analysis beyond simple dependency into a
more general facility location examination. By maintaining reference to the
lakeshore, however, the intent of coastal zone management, and the role of the
state coastal zone programs may be more readily addressed.

2. GENERAL SITING CONSIDERATTONS
A review of.procedures for siting energy facilities has resulted in the
selection of six general considerations which appear to be applicable, in a
broad sense, in the planning and location of all of the.selected energy facili-
ties addressed in this report. The ordering of the considerations should not
imply a priority rating, as the considerations will vary in their importance
depending on the facility (e.g., safety will be a higher consideration for the
siting of a nuclear p lant than for the location of a shipping'port). Neverthe-

less, certain facets of each of the six considerations will contribute to the
eventual selection of any energy facility site [174].

121

a. System Planning
Included in system planni4ig are considerations given to territorial
responsibilities of public utilities, geographical locations of projected load,
coordination with system transmission plans, and location with respect to the
fuel source and transportation routes. Production and/or storage capacity of
the proposed facility is coordinated with these systems considerations in order

to meet.demand requirements.

b. Safety and Reliability
Safety considerations include the location of.population centers and
associated population distribution and density, seismological and geological
restrictions on foundation locations, and potential lake or riverine flooding.
As stated above, safety considerations are applied most heavily to siting of
nuclear energy facilities to reduce potential radiation threats. In addition,
safety considerations are applied to fossil-fuel plants, refineries and gasi-
fication and liquefaction plants, with regard to air and water emissions and
the resultant health and safety of.the population centers. Lake and river
flooding are important safety and reliability considerations in the siting of
plants. Likewise, geological and seismological factors are both safety and
reliability considerations.

c. Engineering
Engineering considerations are numerous and extremely site- and f acility-
specific in their application to overall siting criteria. However, several gen-,
pral aspects of engineering feasibility may be applied to the siting of energy
facilities. These would include water supply, accessibility to trans portation
routes, soil and/or bedrock conditions, topography, and facilities.design.
Water supply and coal delivery are the most important of the engineering con-
siderations in the siting of energy production facilities. Water supply is a
determinant of the.cooling method alternatives that may be considered.

d. Environmental

Perhaps the most,recently developed and most important considerationsin
terms of their widespread applicability are the variety of factors which fall
into the environmental category. Enacted primarily via the provisions of the
Environmental Policy Act of 1969, environmental siting criteria have come to

122

the forefront of considerations in the overall site selection procedure for
energy facilities. Among these considerations are the dedicated lands, en-
vironmentally sensitive areas, surface and groundwater hydrology, meteorology,
aesthetics, and public attitudes. Associated with these are the various air
and water quality considerations which must be investigated regardless of the
type of energy facility. Thus, consideration must be given to present and po-
tential land uses and the potential land uses and the potential environmental
impacts of a proposed facility.

e. Institutional/Regulatory
Siting considerations within this category refer to all of the regula-
tory requirements which must be met in both the siting procedure and the final
site selection and facility construction and operation. These include all
local (where applicable), state, and federal regulations and requirements apply-
ing to enviornmental standards, water resources, land use, transmission and
transportation routes,,economic. development, and activity-specific policies.

f. Economics

There are three primary cost considerations to be weighted when looking
at the economics of energy facilities: the cost of system planning considera-
tions, the cost of engineering considerations,.and the cost of environmental
and social considerations [174]. These may be very site specific. The system
planning costs include factors such as transportation routes, access to the,
site, and the transmission line location. Engineering costs are concerned with
excavating, building, and operating the facility. In this report, costs related
to@diffetent cooling systems and transmission lines will be evaluated. Environ-
mental costs are concerned with mitigation of air, water, and land quality prob-
lems, while social costs and benefits are concerned with sociolocrical effects,

land values, fiscal effects, local economic effects, and public acceptance.

3. FACILITY DESCRIPTIONS AND SITING REQUIREMENTS

a. Fossil-Fuel (Coal) Power Plants

(1) Description

The facilities considered in this section are base load electrical pow-
er generating plants that burn fossil-fuels to generate steam. Because it is

123

likely that the majority of future'fossil-fuel Vower,plants in the Great Lakes
Basin will use coal as their primary heat source'', discussion.is limited to such
facilities. In developing the siting consideration presented below, it has been
assumed that present technology will-be employed in the design and operation of
new plants built in the time frame of this study. 'A discussion of how new
-technologies might affect these considerations is included at the end of this

section.

The analysis of the fossil-fuel power plant is based on a 1,000 megawatt
electrical output (MWe) capacity coal-fired unit with a plant life of 35 years.
It is further assumed that this unit operates at 318 percent efficiency with a
capacity factor of 65 percent on an annual basis. It is recognized that the
-present trend is toward multiple-unit complexes with total outputs in.the range
of 1000 to 2000 MWe, with some as large as 3200 MWe (e.g.,' the Monroe facility
operated .by Detroit Edison). While the site'requirements are developed for only
one such unit, problems related to scaling the facility up are also addressed.
Figure I shows a simplified schematic diagram of a fossil-fueled gen-
erating system [222]. In actuality, a modern steam-electric plant is much more
complex than Figure 1 suggests, "with a number of steam cycles operating at
different temperatures and pressures and driving several high and low pressure
turbines mounted on the same shaft as the generator" [451; p.54]. 'For the pur-

poses of this study however, the information'in Figure 1 will be sufficient.

(2) Site Requirements
In'addition to the general site selection criteria discussed previously
there are several spec.ific@site requirements considered in choosing a site for
a major new coal-fired power plant. These are discussed below, with quantitative
estimates.of resources@(land and.water primarily) required given where appro-
priate and available.
(a) Land requirements
The amount of land required for a coal-fired power plant depends on

MWe refers to the electrical output capacity of the facility. This is dis-
tinguished from MWt, the thermal energy equi .valent, which.represents the
total energy produced by the combustion of the fuel. The 1000 Mwe figure
.assumed for a fossil-fueled power plant would, be a very large'facility by
today's standards (a single unit plant may be 800 MWe). The selection of
1000 MWe should not be seen as advocating a larger unit size for coal-fired
pl ants. It was selected for convenience and comparative purposes only.

FIGURE 1

SCHEMATIC OF A FOSSIL FUEL (COAL) POWER PLANT

High Pressure
HighTemperature Steam
Turbine
Heat Input Generator El ectrica I
To Cycle Boiler ->-,Energy
(Fuel)
Mech.anical Energy
High Pressure Output To Generator
Nat Ier Condenser Low Pressure
Low Temperature
Pump Steam
Low Pressure
water
Heat Rejected From Cycle

[Source @22]

125

several factors: onsite requirements for fuel handling and storage, setting
(urban or rural), solid waste di;posal techniques, cooling system type, possible
multiple use of parts of the site, and ultimate plant capacity 1203, 451].
Land required for the actual powerhouse (boilers, turbines, generators,
and condensers) itself is quite small, amounting'to less than 5 acres for the
1000 MWe facility considered here. In addition parking lots, office space, and
emission control devices require approximately 5 acres, bringing the total to.
about 10 acres (estimated from information in 451).
An important,determinant of site size is the fuel handling and storage
system. Generally, th'ere.are two coal storage areas, one that provides the
feed'to the combustion chamber, the.otber holding a larger reserve supply to
allow the plant to operate through fuel supply interruptions. While reserve
requirements vary, in the Great Lakes Region, a six-month reserve supply is
generally maintained to allow for winter disruption of the shipping season
[526,.539]. Facilities not dependent on lake-borne coal deliveries also main-
tain reserve supplies but may be enough for only 90 days of operation [203,
4511. Six-month and 90-day reserves for a 100OMWe facility would require about

50 acres and 25 acres respectiv ely. The size of this coal storage area will
vary with plant size, so that a multiple unit facility would require propor-
tionately more land for storage. A linear relationship between plant size and
storage area can be assumed if pile heights-remain constant (e.g., a 2000 MWe
plant would require twice the storage area of a 1000 MWe plant).
Ash disposal is another major factor in determining the site size re-
quired for a-coal-fired plant. Coal burned in large plants in the Great Lakes
Region had an average ash content of 11 percent iii 1973 [192]. Estimates based
on a 3000 MWe facility indicate that 300-400 acres would be required for ash
disposal, assuming a 35-year plant life and an average pile depth of 25 feet
[first cited in 4421. This gives an incremental requirement of 0.0033 acres/,
year/MWe for ash disposal. For the 1000 MWe facility considered in this study,
a total of 100 acres to 130 acres would be needed over the life of the plant.
The above discussion does not take into account the potential for fly-
ash recovery and reuse. A study [cited in 451] by the Edison Electric Insti-
tute indicated that 17.4 perce-at of the fly ash generated nationally was reused.
Possible uses include backfilling,mines, neutralization of acid.mine water, use

in automobile tires and cement, and construction fill [4511.

..Another solid waste disposal requirement is additional land for sulfur dioxide

126

.control wastes. @If a throwaway system (a system in which the adsorptive mate-
rial is used only once, such as limestone scrubbing) were used,.the land re-
quired forwaste disposal would be, increased by 100 to 200 percent [442]. Also,
additional land for limestone receiving,and storage would be needed.
The final important consideration in determining the land required for
a coal-fired power plant is the cooling system used.; A 1000 MWe plant of the
type considered here would reject 3.62 x 10 9 Btu/hr of waste heat on an annual
basis. Of this, 90 percent (3.26 x 10 9 Btu/hr) is dissipated to the cooling
water through the condenser, with the remaining 10 percent lost up the stack.
The acreage required for each of the cooling system alternatives considered here
for a 100.0 MWe plant are [from 203]:

Once-through 1 acre

Natural Draft Tower 10 acres

Mechanical Draft Tower 45 acres

Spray Canal 100 acres
Pond 2,000 'acres

Transmission lines (on-site) and switchyards will add about 10 acres
more to the total land required.
Based on the information presented above, a 1000 MWe-coal-fired power
plant will occupy from 145 to almost 2,500 acres depending on the cooling'sys-@
tem used, SO x waste disposal, and coal reserve size. "Typical" configurations
and their-site sizes are given below:
Once-through cooling, 6-month coal

supply (50 acres) onsite ash (120 acres) and
SOx waste (200 acres) disposal . . . . ... . . . . . 395 acres

e Natural draft cooling towers,
6-month coal supply, onsite ash and SO x
disposal . . . . . . . . . . . . . . . . . . . . . . 405 acres

o Mechanical draft towers, 90-day
coal supply, 20% ash utilization (removed
from site), no SO waste disposal .. . . . . . . . . 190-acres
x

Spray canal cooling, 6-month coal
supply, onsite ash and SO waste disposal 495 acres
x

127

These figures do not take into account multiple use areas, buffer zones
to shiel'd the plant from general view, transmission line rights-of-way, or any-
thing else beyond the factors discussed above. However, they do compare well
with figures prepared for a conventional plant both with and without SO scrub-
x
bing systems--640 and 435 acres, respectively [222].

(b) Location with respect to population
Unlike the' case for @nuclear facilities, there is no explicit exclusion
or isolation requirement for coal-fired power plants. They can, therefore, be

located near to population concentrations and, in fact, have been so in most
cases in the past to meet system requirements and to take advantage of-reduced
@transmission costs. However, while there may not be specific regulations re-
garding isolation,'it should be apparent from the above discussion regarding
land requirements that in many cases such isolation is necessary; the expense.
of procuring storage land in urban areas might offset the savings of reduced
transmission distances. In addition, public health problems related to air
quality may force plants to locate away from metropolitan,areas (see Section
IV.A.4.C.1). Finally, aesthetic considerations and other factors that influ-
ence public acceptance may necessitate isolating new facilities from large

population centers.

Water requirements

As mentioned above, a 1000 MWe coal-fired power plant with the operating
charactetistics assumed here (65% plant capacity, 38% efficiency) would reject
3.62 x 10 9 Btu/hr. annually. The purpose of the cooling system is to absorb a
large part of this excess heat.and dissipate it to a large receiving body (the
atmosphere, a river, lake, or ocean). There are three basic elements common
to all systems [441]:
An intake for supplying cooling water to the power plant
9 kcondenser where turbine exhaust steam is condensed at low tempera-
ture and low pressure while transferring waste heat to the cooling water
a A device for transferring this waste heat to the atmosphere (and
finally to the ultimate sink--outer space).

The amount of water that mustflow through the condenser is determined
by the amount of heat rejected by the plant and by the temperature rise desired
in the cooling water. Figure 1 [from 4411 shows the relationsfiip between these

128

factors. Based on the fossil fuel plant characteristics shown in Figure 2,
a 1000-MWe plant would require the following cooling water flow rates for

the accompanying temperature rise:
lemperature Rise (At) Flow (cfs)
30OF 600
200 900
100 1,800

As these figures show, the flow across the condenser rises in direct proportion

to the decrease in At.

As discussed in the section on Land Requirements, five alternative

cooling methods are considered for this report: once-through or open-cycle;
natural draft: wet cooling towers; mechanical,draft wet towers; spray canals;
and cooling ponds. The last four systems are termed closed-cycle because most
of the cooling water is recycled through the system in a loop configuration.
Not considered explicitly in this study were the combination systems, which
utilize an off-stream device, such as a cooling tower, to cool the water prior

to returning it to the source waterbody. These three cooling configurations
are shown in Figure 3. In addition, Figure 4 shows simplified cross-sectional
views of three of the closed-cycle devices: natural draft towers, mechanical
draft towers, and spray canals.
Two water use requirements are important for the plant cooling system:
total withdrawal and amount consumed. In a once-through system, consumption is
quite small, but withdrawals must equal the flow across the-condenser, generally
1000 cfs (450,000 gpm) or more. In closed-cycle systems, the consumption is
more significant, although withdrawals are limited. The figures in Table 8
show representative values for evaporative losses for a 10007-MWe fossil-fuel
plant.
Makeup water for evaporative losses is only a porti on of the water
requirement for,a closed-cycle system. Another important consideration is
blowdown water replacement. Blowdown is that portion of the cooling water
removed to prevent an undesirable buildup of dissolved and suspended solids.
The blowdown (B) is a function of the available makeup
(B+D+Ev) water quality and is related to evaporation (Ev)
and drift [water lost in droplet form] (D) in the fol-
lowing manner:
C = (B+E-%,+D) / (B+D)
In this equation, C = cycles of concentration: the number of
times the concentration of any constituent is multiplied from
its original value in the makeup of water [441; pp. 24-251.

129

FIGURE 2

COOLING WATER REQUIREMENTS
FOR FOSSIL AND NUCLEAR POWER PLANTS

COOLING WATER ME'QUIREMENTS FOR
FOSSIL AND NUCLEAR POMIER PLANTS
NUCLEAR, FOSSILIW
33 %7 71 t = 40%
IN-PLANT LOSSES IN-PLANT AND
5 */6 STACKLOSSES'
=15 %

2500

.0e
2000 At
J** eLp
CL
1500 v
Ld

1000

500 .01

.0
0 1000 2000 3000
COOLING VJ A T ER FLOW 'to), Cis

AT = CONDENSER TE"tAP. RISE.
= PLA71T THEMMAL EFFICIENCY

[Source 4411

130

FIGURE 3

ALTERNATIVE COOLING SYSTEM CONFIGURATIONS

STEAM FROM TURBINE WATER TO BOILER
ONDENSER

OPEN CYCLE

COOLING
TOWERS
(not used In this 'Ode)
t -

ONDENSER

HYBRID CYCLE

COOLING
TOWERS

RIVER

CONDENSER

CLOSED CYCLE

COOLING
TOWERS
SLOWDOWN! MAKE-UP WATER
RIVER
HD<

Ha@

[Source 451]

131

FIGURE 4

CROSS-SECTIONAL VIEWS OF

THREE COOLING DEVICES

AIR OUT
AIR OUT

WATER
IN
(From wdemed

AIR IN AIR IN

7%
WATER
AIR IN AIR IN OUT

MECHANICAL DRAFT
WATER OUT
FILL MATERIAL WATER IN COOLING TOWER
(From condonser) (WET-TYPE)

NATURAL DRAFT COOLING TOWER
(WET-TYPE)

DIFF USERS

WATER OUT
WATER IN @,3
(From coridanser)

SPRAY CANAL

[Source 4511
[@@ IIM"'
AIR I

132

TABLE 8

COOLING WATER EVAPORATIVE LOSSES

EVAPORATIVE LOSS
COOLING SYSTEM GPM CFS
Once-Through 3901 0.91
03 03
6301 1.41
Natural Draft Tower 35022 7.82
9503 2.13
6301 1.41
Mechanical Draft Tower 38002 8.52
9503 2.13
37002 8.22
Spray Canal
4721 1.11
Pond 52502 11.72
14103
1 [78]
2 [2031
3 [2221

As C increases, blowdown makeup decreases. The values below are representative
of this relationship (based on Ev 21.4 cfs and D = 0.05 cfs):

-C B (cfs)

1.2 107
2 21.4
5 5.3
10 2.3
20 1.1 [441; p.27]

In summary, water withdrawals can range from approximately 9,300 gpm
(21 cfs) to 800,000 gpm (1,800 cfs), depending on the temperature rise and
cooling system used (203]. Site selection depends on a water supply adequate
for-normal plant generations as well for long-term low-flow conditions. For
once-through systems, plants are limited to locations where large quantities
of lake water are economically available. There are few river locations in the
basin-adequate for even closed-cycle plants.

133

(d) Transportation access
Transportation access requirements for coal-fired power plants relate
primarily to fuel delivery and, in some cases, waste disposal, if disposal is
off-site. However, it is also important during the construction .phases for move-
ment of workers, heavy equipment, and materials to the site.
Coal deliveries to the plant are generally made either by rail br,water
(ship or barge). Because a modern 1000-MWe plant may require 8,000 to 10,000.
tons of coal per day, delivery by truck, except at minemouth plants, is usually
done only to supplement rail receipts. For the scale of facilities discussed,
in this report, trucks cannot provide sufficient deliveries to make them the

primary suppliers.
Another delivery system not considered to be a major factor in future
coal movement to plants in the Great Lakes Basin is the slurry pipeline. While
coal slurry pipelines can be used to move large volumes of@coal over long dis-
tances, the easy availability of cost-competitive alternatives in the basin
makes the development of such a system unlikely.
The most common rail delivery system is a dead-end line into the plant
with 75-120-car-unit trains (100 tons per car) used to move the coal from the
mine to the plant J221]. Approximately 200 trainloads per year would.be re-
quired, or one every day-and-a-half for this studyls generalized 1000-MWe coal-
fired plant. By designing the unloading facilities around the train configura-
tion it is possible to reduce operating costs as well as provide a continuous
supply of coal. In addition, the reduced turnaround time means lower freight
rates, important in the economics, of large coal plants [2211.
Receipt of coal via water borne carriers requires a site with harbor
access. A naturally deep harbor in which extensive dredging can be avoided is
ideal, although suitable harbors can be developed if necessary.
Barges with capacities in the range of 500 to 3,000 tons draw up to 12
feet of water. A 1000-Me plant should have "harbor, docking, and unloading
facilities capable of handling 3 to 7barges per day" [221; p.13]. Gravel-
filled sheet pile cells with barge unloading cranes on 80-100-foot centers pro-
viding 600-1,000-foot- long docks are generally used [221].
'Movement of coal by-lake vessel is an important alternative in.the

At present, the laT'gest planned slurry pipeline will deliver 330 tons of
pulverized coal slurry per hour over a distance of 275, miles.

134

Great Lakes basin. For example, the proposed Belle River plant, (Detroit Edison)
would receive western coal from Superior, Viisconsin by lake vessel; "these

freighters will have a capacity of 45,000-60,000@tons and unload at a rate of
approximately 7,000 tons per hour" [526; p.471. These large carriers, re-

qUiring drafts up to 26 feet, can provide large volumes of coal per delivery,
reducing the need for a constant stream of coal to the.site. In addition,
many of these vessels.are self-unlo aders, obviating the need for extensive dock-
side works (see the section of Coal Transshipment and Storage Facilities for a
more complete description).
It is desirable to provide dual access by rail-and water. There are
two important reasons for this. First, there may be some uncertainty as to the
long-term (over the life of'the plant) source.of coal as environmental and
economic conditions change. Second, there is a ne6d-to protect against possible
work stoppages in one mode that could cause fuel;shortages. Thus, while either
mode may provide sufficient delivery capacity for-the facilities.considered
here, it is desirable to maintain options for both.
It is also desirdble.to locate nearsthe existing bulk transmission sys-
tem. The existence of a major network of EHV and UHV (765#V)@ transmission.lines
constrains, to some extent, the location of major new generating:.fac.ilitios.
The desire to reduce costs while maintaining a high levels of reliability and
flexibility makes tie-ins to the existing system generally preferable to the@
construction of major new carriers. There are, of course, exceptions when sys-
tem expansions-are desired or when current'capacity is reached.

(e) Seismology and geology
There are no special geologic..of seismological requirements for the
siting of coal-fi.red plants other than that-a satisfactory foundation for the
plant structure be available and that there should be no active faults.

(f) Hydrology and meteorology
The most,important meteorological requirements relate,-to the dispersion
of air pollutants generated by the facility. It is important that.account be
taken of prevailing winds and that the facility be sited so that.;particulates*
and other pollutants will not be blown to nearby-population concentrations.
The most important hydrological requirements,are related,to the cooling

system requirements. Generally, for consumptive uses of s tream waten, the

135

average withdrawal rate should be no greater than one-third of the 10@year-7-day
low flow. In addition, the thermal effluent receiving body should be capable of
rapidly dispersing the heated return flow. Finally, the receiving body must be
able to adequately dilute and disperse the blowdown effluent.
Other:hydrological requirements relate to the protection of surface and
ground-water resources against contamination from other sources: leachates and
runoff from the coal storage and waste disposal areas, storm runoff from the
plant in general, and sanitary wastes from the plant water supply system.

(3) Environmental and-Other Considerations

In addition to the resource requirements discussed above, there are
several additional factors that enter into a facility siting decision. -One.
such factor is the availability of sites previously acquired by the utility.
Major utilities keep an inventoryof facility sites purchased in the past for
future plant development. Then, as new capacity additions are req Iuired, the
utility will look first at these sites to determine which,,if any, are suited'.

to-the proposed addition. It is important to remember that many of these sites
were purchased ten or more years in the past, when site selection criteria.and
plant design were somewhat different than today. Thus, it is likely that some
of these available sites might not be suitable by today's standards.
Another factor.that is especially.important in siting fossil-fuel
plants is ambient air.quality. The construction of new base load capacity will
be limited only to those areas where ambient conditions with the new facility

meet national standards.

Overall environmental impact of the facility will also influence the
location decision.process. A site will be selected that minimizes impacts on
aquatic and terrestrial ecosystems. This includes avoiding (or preservifig)
fragile habitats, locating away from sensitive areas, etc.. Clearly, this..
policy has not been followed in all cases in the past. However, as'environ-
mental reporting and analysis standards became more defined and stringent,.
these considerations will become more important. One result of this effort has
been the increase in multiple purpose site planning by the utilities, pr ovid-
ing public access to certain areas of the site.for recreational activities
(this is more common on nuclear power plant sites).

.See discussion of EPA for details of air pollution control program, Chapter III.

136

A final consideration is public acceptance of the proposed facility.
This aspect of the facility planning process is becoming more and more important.
To a large extent, the mitigation of public opposition is tied to the environ-
mental sensitivity demonstrated in selecting the site and preparing the site
plan. Opposition can also be reduced by public involvement in the pite selec-

tion process. Many of the policy options described in this s tudy are designed
to minimize this opposition, resulting in a better, more holistic facility
siting process.

(4) Emerging Technologies
Within the time span of this study (15-20 years) there are not expected
to be any major new technological breakthroughs in the generation of electricity
from fossil fuels. Those technological advances that do occur will be based on
presently demonstrated technology applied to large-scale operations.. Even then,
these changes would not be seen until the mid-1980's.

Areas in which.changes can be expected to occur in the near- to mid-term
are fuel combustion,.power conversion, and air quality control. Fuel combustion
technology is related to the manner in which the fuel (coal, in this case) is
burned. Power conversion is related to the manner in which the energy released
by the combustion process is used to generate electricity. Air quality control
refers to the alternative techniques available to reduce air emissions (pri-
marily sulfur dioxide) from the combustion process. Any given change in tech-
riology may affect all three areas. For ease of discussion they have been
grouped as follows:

Fuel combustion fluidized bed
low Btu coal gasification
combined coal-solid wastes
See Scenario Four, Applied Emerging Technologies, in Chapter V.

A completely new technology that may be available in the next 20-50 years is
the fuel cell generator. The fuel cell is a sandwich-like device.with two
electrodes separated by an electrolyte. A'fuel (low Btu synthetic natural
as, for example), is fed to one, and an oxidizer to the other. A DC current is
produced by the resultant oxidation reaction. Efficiencies near 70 percent
are projected for a 1000-MWe central station unit using one process currently,
under development [222]. Such a unit would produce chemical pollutants similar
to those produced by conventional processes, except that NOx emmissions would
be reduced due to the lower operating temperatures. "However, the fuel cell
is particularly sensitive to pollutants, such as sulfur, now causing concern
in conventional steam turbine plants. Thus, the pollutants must be removed@
prior to the fuel cell system" [222; pp.12-33).

137

.Power conversion combined cycle generation
Air quality conirol (too numerous to identify
individual.processes)

Although the above list does not include all potentially important tech-
nological advances, it is arepresentative sample of what is available.

(a) Fuel combustion

(i) Fluidized bed combustion
The following description [222; pp.12-18] summarizes this process and
its advantages:
A fluidized bed boiler involves passing air upward through a
grid plate supporting a (several foot).thick bed of granular,
noncumbustible material such as coal, ash, or lime. The air
fluidizes the granular particulates and, with the relatively
small amount.of air used to inject the fuel (usually coal but
possibly residual oil), serves as the combustion air. The heat
transfer surfaces or boiler tubes can be embedded in the
fluidized bed directly because-combustion takes place at iem-
peratures (approximately 1,500'F.) that will not damage the
tubes.

The fluidized bed boiler has two basic advantages: the ability
to burn high-sulfur coal with low-sulfur dioxide.(S02), par-
ticulate,.and to some extent, NOx emissions;.high heat release
and heat transfer coefficients,that can drastically reduce
boiler size, weight and co st. This means that fluidized bed
boilers.can.be built as factory-assembled, packaged units,
shipped to sites, and arrayed as required. These factors
will considerably reduce construction times for new power
plants..

study by the Battelle Columbus Lab [545] estimated that a 600-MWe
unit (operating at atmospheric pressure) might be one-half to two-thirds the
size of a conventional boiler unit. Pressurized units (up to 10 atmospheres)
might be even'smaller. Data developed by Hittman Associates .[cited in 2221
indicate'an even greater reduction in land required. Other potential advan-
tages [545] include: lower capital costs (10-20 percent reduction) and opera-
ting costs (5-15 percent reduction), possibly higher supercritical steam,,con-
ditiIons (1,200*F. at 4,000 pisg), and reductions in ash fouling, high tempera-
ture corrosion and thermal discharges..
.The major disadvantage perceived at this time is the disposal of large
volumes of spent bed material (limestone-or dolomote). However, because this.

138

is a problem shared with other new (and existing) technologies, it may not be

significant.

(ii) Low Btu coal gasification
'A large part of the present energy research effort is directed toward
perfectingmethods of converting coal to a substitute natural gas (SNG). Many
of the methods presently under study are described in Reference 222. Of con-
cern here are those methods which can be used to produce a low,Btu gas (heat
value of 100-300 Btu per 1,000 standard cubic feet). Because it is generally
not economical to transport such low quality gas [203] it must be produced at
th6@'point of its use. In this context we are concerned with a combined coal
gasification/electrical power generating plant. The gas produced by the gasi-'
fication process can then generate electricity by using gas-fired boilers, com-
bined cycle turbines, or gas turbines. (See references 203, 222, 545, and 400
for detailed descriptions of the various processes and their associated resource
requirements and environmental impacts.)_'

(iii) Combined coal-solid waste combustion

A potentialsource of fuel in the future may be found in solid wastes.
Because the energy value of such material is so low (generally 4,000-4,500 Btu/
lb. as compared to 9,000-12,000 Btu/lb. for coal) the potential of 100 percent
solid waste-fueled plants is quite low, especially for the size c onsidered
here. However, it may be possible to utilize a mixture of coal and "clean"
solid wastes (non7combustibles removed prior to burning). One report [5451
indicates that use of wastes to provide 10-20 percent of the total energy input
would not interfere with boiler operation. Potential problems relate to
chloride corrosion in the boiler/generation system and potential leaching,

of incinerator solid wastes.

(b) Power conversion
The only method considered for this phase of the power generating system

A 1000-MWe power plant using only solid waste would require 24,000 tons/day
based on the figures given above.

The Union Electric Company of Missouri has completed a demonstration program
and has decided to go ahead with a program to convert its plants for burning a
90 percent coal, 10 percent refuse mixture [Communication with NPCC].

139

is the use of combined cycle power plant. While there are severaltypes of com-
bined cycle units presently under development, a typical configuration using gas
and steam turbines is shown in Figure 5. It is essentially a combination of a
standard gas turbine (similar to jet engine) powered by hot gas (SNG) which is
then,used to heat water in a boiler to power a conventional steam turbine. It
is estimated that a system likethis could achieve an efficiency of 40-42 per-,
cent in the near future [2221.1 The Battelle Lab's report [545] projects effi.-
ciencies of up to 50 percent.

(c) Air quality control
One of the major technological problems faced by utilities in expanding
their coal-fired generating capacity is meeting national air quality and
st ationary new source performance standards, especially with respect to sulfur
dioxide emissions. In response to this problem, a great deal of research has
been carried out on sulfur dioxide removal.systems. Unless the present re-
gulatory posture is substantially altered, it can be-expected that one or.more
or these systems will be used in the near future as new plants come on line.
Of the many sulfur dioxide removal methods presently under development,
11the.most effective appear to be 'scrubbing' processes in which the stack gas
11
is passed over or through a material that. reacts with SO to form a compound
2
[222; pp.12-13]. There are two@_ways to deal with the resultant compound: dump-
ing it.at a disposal sit-e, which changes an air quality problem to one of solid
waste handling and disposal "throw away'! method; or conversion to a useful
sulfur product.with possible recycling of the absorptivematerial. This latter
method involves the added expense of installing a costly sulfur recovery plant.
Figure 6,illustrates three sulfur removal methods using lime'or lime-
stone as the reacting material. Present indications arethat the electric util-
ity industry favors-lime and limestone throwaway processes for several reasons:
f1relative simplicity, relatively low investment, and freedom from the problems
of marketing and making a by-product" [222; pp.12-131. The three methods in
Figure 6 are:
Introduction of limestone directly into@the scrubber. This is the
simplest route and seems to be the one favored by the power indus-
try.at present. The main drawback is that limestone'is not as

Alternative sulfur control technologies not discussed in this report are-the
techniques of coal cleaning and beneficiation used to remove'sulfur and ash
prior to combustion.

140

FIGURE 5

SCHEMATIC DIAGRAM OF A COMBINED CYCLE

GAS-STEAM GENERATING PLANT

Exhaust Gas
Stearn
Turbine
Generator
WWI' Cooling Water
c 331
Boiler
Condenser

Pump

Combustion
Fuel Chamber

Generator

Gas Turbine
Compressor

[Source 222]-
Air

141

FIGURE 6

SIMPLIFIED DIAGRAMS OF THREE LIMESTONE/LIME
STACK GAS DESULFURIZATION TECHNIQUES

Gas to stock

Stock
gas
COC
Scru er 03

Settler

Pum COSO 3+ Co S04
tank to waste
METHOD I.' SCRUBBER ADDITION OF LIMESTONE

Gas to stack

Stack Co (0 H)
gas .4
Pump
Scrubber tank

Coco 3 Calciner Settler
coo aSO3+ COS04
to waste

METHOD 2. SCRUBBER ADDITION OF LIME

Gas to stack

coo +gas

Pum
Boiler Scrubber tonkp
Coco =>
5 > Ju Set t ler

CaSOA + CaSOj
t6- waste
METHOD 3. BOILER INJECTION
@Ga s t,
bb

[Source-2221

142

reactive as lime, which makes it necessary to us e more limestone,
install a larger scrubber, recirculate more slurry, grind the
limestone finer, or otherwise offset the lower reactivity..

� Introduction of lime into the scrubber. Scrubbing efficiency can
be improved by first calcining the limestone to lime (CaO) and
introducing-the.lime into the scrubber. However, the cost is
increased greatly over that for limestone slurry scrubbing,
since a lime kiln installation is expensive to build and operate.
Use of lime also increases the problem of deposit formation in
the scrubber (scaling).

� Introduction of limestone into the boiler. The cost of calcina-
tion canbe reduced in power plants by injecting the limestone
into a boiler furnace. The gas then carries the lime into the
scrubber. Problems include possibility of boiler fouling, dan-
ger of over-burning and inactivating the lime, and increased
scaling in the scrubber when the lime enters with the gas
[222; pp.12-131.

Table 9 summarizes the status (as of January 1976)-of the present.and
projected development (by megawatt capacity) of flue gas desulfurization (FGD)
systems in the U.-S. B y the end of 1976, approximately 10,000 MWe of FGD is
expected to be installed. The efficiencies for removal of SO 2 range from
approximately 40-90 percent and particulate removal efficiencies generally are
above 99 percent for those units designed for particulate removal. Most sys-
tems are being designed to operate at 80-90 percent efficiency [3361.

.TABLE 9

STATUS, NUMBER AND CAPACITY OF FLUE GAS DESULFURIZATION SYSTEMS

No. of
Status units F:_
Operational 21 3,796

Under construction 20 7,026

Planned

Contract awdrded 10 3,761

Letter of intent 10 3,911

Requesting/evaluating bids 7 3,837

Considering only FGD systems 40 19,797

Total 108 42,128

13361

143

The major resource requirement related to power plant siting that will

change if these techniques are used is the amount of land,required. As dis-
cussed earlier, the amount of land needed for throwaway system waste disposal
can be up to 200 acres beyond the normal plant requirements. In addition,
facilities will be needed for scrubber material (limestone) delivery and storage
at the site. If deliveries are.made by water, this may increase the desirabil-
ity of coastal locations. Presumably, the same considerations as those related
to fuel delivery would be important.

b. Nuclear Power Plants

(1) Description
Nuclear power plants on-line at this time or planned for construction in
the next ten years are almost uniformly light water-reactors (LWR). Figure 7
shows diagrams of the two common LWR types presently in use. In the boiling
-water reactor (BWR) water is converted to' high temperature/high pressure steam
(5450F./1,000 psi) by the core and is used directly t ,o drive the turbine, The
pressurized water reactor (PWR), on.the other hand, has two heated water sys-
@ems. Heat is picked up from the core by the primary,system (600'F./2,250 psi)
and is transferred to the secondary system via a heat exchanger (the steam
generator). Steam carried in the secondary system is then used to drive the
turbine/generator system.
For purposes of comparison, a 1000-MWe nuclear power plant has be,en
Selected as the unit, of analysis. It has been assumed that this plant operates
at an efficiency of 32 percent with an average annual plant capacity of 65
percent. Average operating life is assumed to be 30-35 years.
Use of a 1000-MWe plant size does not take into account the potential
for multiple-unit facilities with combined nameplate capacities of 3000 Mwe and
above. Because this clustering of 2-4 units on one site seems to be the pre-
sent trend, it is important to recognize this practice and examine its effect
on the resources required. Efforts will be made, therefore., to indicate how
resource requirements change as capacity is raised above 1000 MWe.

Nameplate capacity is the power production at 100 percent output; actual out-
put is nameplate capacity multiplied by load factor, generally about 65-percent
of this (as assumed above).

144

FIGURE 7

LOW
PRESSURE
SEPARATORS JUR INE .GENERATOR
DRYERS
......... ...........
......... .

HIGH
PRESSURE COOLING
TURBINE WATER PUMP
REACTOR
PRESSURE '.FUEL.
VESSEL CONDENSER WATER
............
..........

FEED
REACTOR WATER CONDENSATE PUMP
FEED HEATER
CONTROL RODS PUMP
DRIVES

FUEL Slightly enriched uf3nium oxide c1A with zirconium allay
MODERATOR Boiling water
GENERAL ELECTRIC COOLANT Wling water
PRESSURE OF PRIMARY SYSTEM 1.000 p!d
OUTLET TEMPERATURE 550P F

Boiling Water Reactor Power Plant

LOW
PRESSURIZER PRESSURE
SEPARATORS TURBINE GENERATOR
CONTROL RODS & DRYERS
& DRIVES

HIGH
PRESSURE COOLING
TURBINE WATER PUNIP
REACTOR STEAM
PRESSURE GENERATOR COOL114G
CONDENSER
VESSEL FUEL WATER

FEED
FEED WATER
WATER HEATER CONDENSATE PUMP
PRIMARY PU."IP
COOLANT
PUMP
FUEL Slightly enriched uranium oxide cl3d with zirconium v,'Ioy
MODERATOR Water
BABCOCK & WILCOX COOLANT Water
COMBUSTION ENGINEERING PRESSURE OF PRIMARY SYSTEM 2,25Dpoundi per iquve inch
WESTINGHOUSE REA CTOR.OUTLET TEMPERATURE 60.5e F
&
UF@

Pressurized Water Reactor Power Plant

[Source 203]

145

(2) Site Requirement7s

(a) Land requirements
An analysis of 75 existing and proposed nuclear power plant sites shows
a size range from 84 acres to 30,000 acres, with an average of 2,730 acres [data
in 208]. Further analysis of the same data,indicates that the average station
size (including power house, reactor, and related buildings, cooling structures,
but not including ponds or canals and onsite switching and transmission equip-
ment) is 1.35 acres, or roughly 5 percent of the total site area. Excluding
those facilities using cooling ponds or canals for cooling the average total
site and station sizes are 1,335 acres and 123 acres, respectively. This
indicates that, even without cooling systems requiringa large land commitment
(i.e., ponds and canals), nuclear sites are much larger than strict generating
requirements dictate.
A large part of this additional land requirement is for the provision of
an exclusion zone, within which the operating utility has "authority to det er-
mine all activities including exclusion or removal of personnel and property
from the area" [442; p.20]. This requirement will be dealt with more fully in

the next section.

Because the conversion efficiency of a nuclear power plant is 32 per-
cent, as compared to 38 percent for fossil fuel plants, the total heat rejec-
tion per kilowatt hour is substantially higher. In addition, while 10 percent
of the thermal waste produced by a fossil plant is lost up the stock, essen-
tially all goes into the cooling water system from a nuclear plant. Thus,
9
total heat rejected by the nuclear facility considered here would be 4.71 x 10
Btu/hr, as compared to 3.26 x 10 9 Btu/ hr for a similar size fossil fuel plant.

This higher heat rejection rate results in an increase in.cooling sys-
tem requirements, both in terms of flow across the condenser [discussed in Water
requirements, Section IV.A.3.b(2)(a)] and land required for the system compo-
nents. Table 10 lists the land required for cooling systems of both nuclear and
fossil fuel plants. As can be seen from these figures, a nuclear plant re@
quires 50 percent more.land for its cooling system than does a similar capacity

fossil fuel plant.

There are several additional considerations which determine the size
of the site required. For example, additional land may be needed to provide
adequate noise buffering, especially in the case of mechanical draft

146

cooling towers. Another important consideration is the necessity to limit the
potential impact of water vapor plumes from the cooling system. Although this
aspect of plant siting is not specifically subject to federal or state regula-
tion, it must be considered by the utilities in their site selection procedure

and envrionmental report preparation.

There are other considerations that are not included above. For exam-

ple, multiple use areas for controlled public access to shoreline areas and
cooling ponds, farming and grazing, and use of other inactive areas on the site.
In.moving fiom a single 1000-MWe plant to a multiple unit facility of
2000-4000 MWe, several factors related to total land required will increase.

First,,it is important to note that the exclusion zone requirement is not based
on total plant capacity and willnot change for a given site as that capacity
isincreased. Land requirements that may change include those for cooling,
noise abatement, plume dispersion, and the plant itself. The degree of this
change is not known and probably is site-specific.

Based on the,material given above, it is difficult to postulate a
11typical" site size for nuclear facilities. Given the figures for the various
components that determine site'size, a range from @20-3,500 acres wo, Iuld seem
reasonable. Multiple unit sites could range up to 10,000 acres if cooling

ponds were used.

(b) Location with respect to population
As mentioned in the previous section, there have been regulations pro-
mulgated by the AEC, now administered by the NRC, regarding the location of
nuclear power plants with respect to population. In general, "long standing
policy of the Atomic Energy Commission [now Nuclear Regulatory Commission] has
encouraged siting nuclear power plants away from densely populated areas...
[2071. Title 10 CFR Part 100.(Statement of Consideration, Reactor Site Cri-
teria, published in the Federal Register, April 12, 19621 specifies a three.-
tiered system of population-related locational criteria that must be,met in

off-site effects of water vapor plumes are also considered by utilities in
selecting fossil fuel plant sites, although environmental reports are not
required.
An. exception to this is New York State-, which regards cooling tower drift'as
a settleable particulate, subject to numerical regulatory criteria.

Assumes a minimum exclusion area radius of 0.4 miles [570] and a plant size
of 100 acres. The only explicit variable is cooling system size.

147

siting a nuclear facility. The three criteria,illustrated in Figure 8, are:

An exclusion area, which is that area surrounding the reactor in
which the reactor licensee must have theauthority to determine
all activities including exclusion or removal or personnel and
property from the area. Activities unrelated to operation of the
reactor may be permitted in an exclusion area under appropriate
limitations, but the licensee must be in a position to clear the
area promptly i'n the event of an emergency.' For example, the
area may be traversed by a highway., railroad, or waterway, pro-
vided these are not so close to the facility as to interfere
with normal operations of the facility and provided appropriate
And effective arrangements Are made to control,traffic on the
highway, railroad, or waterway in case of emergency.

e A low population zone., immediately surrounding the exclusion area
in which the total number of residents And the population density
are small enough to provide a reasonable probability that appro-
priate protective measures could be taken it their behalf in the
event of a serious accident. AEC's regulations do not specify
a permissible population density or total population within this
zone because the situation varies from case to case. Whether
a specific number of people can, for example, be evacuated from
a specific area, or instructed to take shelter, on a timely
basis will depend on many factors such as location, number and
size of highways, scope and extent of advance planning, and
distribution of residents within the area.

A population center distance, which is the distance from the
reactor to the nearest boundary of a densely populated center
containing more than about 25,000 residents.
[442;@p.201

(c) Water requirements
Because of the significantly higher heatrejection rate, the cooling
water requirements for a nuclear power plant are substantially higher than
those of a fossil fuel plant of similar capacity. Table 11 compares the flow
required across the condenser for the fossil fuel and nuclear plants considered
here for different temperature rises. As can be seen, flow requirements are
two-thirds higher for nuclear plants for a given temperature rise.
Estimated water-consumption rates for cooling system alternatives have
been compiled from various sources and are shown in Table 12. Because of the
wide range of values and a lack of uniformity in assumptions among sources, it
is difficult to estimate an average consumptive rate for any given cooling
alternative. A range-of 0-30 cfs would not seem unreasonable.
There are, of course, other water requirements for a nuclear facility

148

TABLE 10

COOLING SYSTEM LAND REQUIREMENTS

Nuclear Fossil Fuel

Once-Through 1 1
Natural Draft Cooling Towers 15 10

Mechanical Draft Cooling
Towers 68 45

Spray Canals 150 100
Cooling Ponds 3000 2000

[Source 203]

FIGURE 8

DEFINITION OF EXCLUSION AREA LOW POPULATION ZONE

AND NEAREST POPULATION CENTER

'NEAREST POPULATION
CENTER, POPULATION
GREATER THAN
25,000

Z DWANCE C MUST BE GREATER THAN
4/3 DISTANCE Z

IN LOW POPULATION ZONE
REACTOR PERSONS SUBJECT TO PROTECTIVE MEASURES
EXCLUSION AREA b) MAXIMUM BODY DOSE 25 REM, AND MAXIMUM
DOSE TO THYROID 300 REM FROM EXPOSURE
DURING TIME OF PASSAGE OF RADIOACTIVE
CLOUD RESULTING FROM ACCIDENTAL
LOW POPULATION ZONE RELEASE

IN EXCLUSION AREA
a)HIGHWAYS, RAILWAYS, WATERWAYS SUBJECT
TO CLOSURE
b) PERSONS SUBJECT TO EVACUATION
c) PERSON MUST NOT RECEIVE MORE THAN 25
REM'TOTAL BODY DOSE OR MORE THAN
300 REM TO THYROID FROM TWO HOURS'
EXPOSURE.

[Source 451]

149

TABLE 11
REQUIRED C50LING WATER FLOW RATES*
Change in_.Temperature (OF)
30 20 10
cfs!
gpm cfs gpm gPm cfs

Fossil Fuel 269,400 600 4
04@100@1 900 808,200 1800
Nuclear 449,000 1000 673,500@ 1500 1,347,000 3000

Figures from Figure 2

beyond cooling. An example of a water flow system through a nuclear facility,
proposed Enrico Fermi Units (1075 MWe), is given in Figure 9 and Table 12 [from
5511. As can be seen, these other flows are not significant when compared to
cooling needs. Total withdrawals are 22,545 .gpm (50.2 cfs) on an annual average
basis,.with a total consumptive loss of 11,610 gpm (25.9 cfs).
In summary, nuclear power facilities require significantly more water
than do similar sized fossil fuel plants, due primarily to differences in ther-
mal efficiency. A lower bound of .13 9 4 7 0 to 17, 960 gpm (30-40 cf S) withdrawal
rate with a consumptive rate of about-11,225 gpm (25 efs) is not unreasonable
for an efficient closed-cycle. system. A withdrawal rate of one million gpm
(2,230 cfs) for a once-through system with some consumptive loss prov .ides
an upper bound (assuming a 15'F temperature rise across the conden ser).
The above discussion is based on a single unit 1000-MWe reactor. For
each additional unit added, the water requirements given above should be in-
creased by a similar amount. This does not, take into account possible water use
economies of scale that may be available, although it does provide a reasonable

rule of thumb.

(d) Transportation access

Good transportation access to a nuclear facility site is required for
movement of fuel and wastes, and delivery of large components during the con-
struction phase. Unlike the case of a coal-fired plant, large volumes of fuel
are not required on a continuous basis; figures from the Fermi 2 unit are shown
in Table 13. In addition, nuclear waste materials (primarily spent fuel) must be

The same is true, of course, for fossil -fuel plants, although it was not
discussed at that point.

150

TABLE 12.

NUCLEAR POWER PLANT CONSUMPTIVE WATER USE

gpm cfs

4520 1 10.1 1
Once-Through 3590 2 82
3 3
5840 @13
04 04

7240 1 16.1 1
Natural Draft Tower 8530 3 19 3
12030 4 26.8 4

7240 1 16.1 1
2 2
12570 28
Mechanical Draft Tower 3 3
8530 19
12030 4 26.8 4

Spray Canal-' 11670 2 -262

5440 1 12.1 1
Cooling Pond 6290 2 14 2
3 3
9880 22
4 -4
.17740 39.5

1
[781
2 [207]
3 [511, assumes 1200 MWe
4 (2221

FIGURE 9

FERMI 2 (DETROIT EDISON) WATER USE SYSTEM

7 WAI n 7,@._E., [email protected] TO MAXEVP TODEMINERALIZEDWATER SYSTEM
PLAN . A 'E -TEN
(FERMI 11 SYSTEM PO ABLE WATER
SYSTEM A..-

DISCHARGE FROM SEWAGE rSEWAGE1
TREATMENTPLANT TRIAT- 1_.. 2
Ul 11 10 it 265
0.
IFERN111 I$
RHRSWS R"RSWS
MECH ' NEG..
DRAFT DRAFT
COOLING CODUN
IOMR TOWER

n
SLOWDOWN TO
CIRCULATING
12
WATER RESERVOIR
"News RESERVOIR
0

RH Sm to PLAN UP
"HASINS
S RESERVOIR
IL
SANITARY WASTE
XIL=. MAKEUP TO PLANT SYSTEM
BOOLE PLANT
GSW 0 ISCHAFIGE
FALL
AGOGIN
CHIC. WATER DISCHARGE I
F_

LA F
EFHE 14
TION
FERMI 1 3
INTAKE CANAL
CHLORINE
as" LINE ADDITION

MAKEUP ONE

CIRCULATING WATER
DECANT LINE NOW HOUSE
NATURAL NATURAL
DRAFT AIT
CIRCULATING COOLING C LING
WATER TOWER --ill T 'R
RESERVOIR
11.5 ACRES DISCHARGE FROM C T@ BASIN

a GENERAL SERVICE WATER SVITEM ENF31CO FERMI ATOM IC POWER PLANT
RHRSM-REDDUAL HEAT REMOVAL SERVICE WATER SYStEM t DEMINFRALIZER WASTE SOLUTIONS 11% UNIT 12
CIRC-CIACULATING ENVIRONMENTAL REPORT
CT.-COOLIMO TOWER
(Do Gen" I-
(D&D ... O'COIRATIVIC L-1111M. iiy
PLANT WATER USE
(SHEET I OF 2)

OEFS-K
MIF

TO PLANT 5-MISZWKSE
VR.II.T
N
Al
.E.,

C.L_R III
AGO

NATURAL
D.AF.N.
COOL
-7

[Source 551]

-TABLE 13

KEY TO FIGURE 9

FLOWS OF MAJOR PLANT STREAMS

A erage Flows Under Full Power OReration, gpm Average,
Minimum Maximum Annual (a) Shutdown
Point: Monthly Avg. Monthly Avg. Average Flow, gpm

(1) Required reservoir makeup
in addition to GSWS flow 0 7,900 3,580
(2) Reservoir evaporation rate 110 150 130 110 - 150
(3) Condenser cooling flow (b) 840,000 840,000 840,000 0

(4) GSWS flow 12,000- 27,000 18,950 10,000 - 12,000
(5) Drift loss from cooling-towers (c) 900 900 900 0

(6) Evaporation loss from
cooling towers 8,740 12,220 10,560 0

(7) Makeup to water treatment plant 12 17 15 12 - 17
(8) Makeup to RHRSWS (c) 0 0 0 430
(9) RHRSWS flow to plant (c) 0 0 0 9,000

(10) Drift loss from RHRSWS
cooling towers(c) 0 0 0 20

(11) Evaporation from RHRSWS
cooling towers(c) 0 0 0 220
- (c)
(12) Blowdown from RHIRSWS 0 0 0 200
(13) Blowdown from circulating (c)
water reservoir 10,000 12,200 10,900 10,000
(14) Total flow to cooling towers(c) 900,000 900,000 900,000 0
(15) Ion exchange regenerant waste flow 0.7 0.7 0.7 0.7
(16) Blowdown from auxiliary boilers <1 1 0.8 1
(a)Calculated at 100% plant capacity. Expected plant capacity factor is 80%.
(b)Rated flow.,
(c)Approximakte.

EF2-CR-148-0
B-15-74

f-Source 551]

153

removed from the plant site for reprocessing or disposal; figures on expected
waste shipments from Fermi 2 are also included in Table 14. However, while.,the
annual tonnage of materials moved may be relatively small, the potential (and
realized) problems can be quite significant, especially with regard to waste

transport:
Shipment of spent fuel from the reactor to nuclear fuel repro-
cessing'plants is the most complicated and expensive shipment
in the nuclear fuel cycle. The large amount of shielding needed
for a shipping cask designed to carry a single pressurized water
reactor (PWR) fuel element brings the cask's empty weight to
about 50,000 pounds. The tractor, trailer, and clask will
have a gross vehicle weight in excess of the 73,000 pound
highway limit which most states impose. Thus, special over-
weight permits will be required in many cases for shipment of
spent fuel by truck. On the other hand, rail,transported
shipping casks are envisioned which will carry seven elements
per cask and will have a loaded weight close to 200,000 pounds.
However, not all reactor sites have rail facilities immediately
available at the fuel storage area and some reactor sites
equipped with rail facilities cannot obtain rail service
because local railroads have refused to transport fuel [203; p.127].

Because of the potential for long-term catastrophic impacts if an accident should:"
occur during transit, it is important that safe routes be,guaranteed over the
life of the plant. Careful consideration of the long-term implications of an
accident (such as a container leak) should be made before a transit plan is

approved for a specific facility, especially if all or part of the route in-
volves waterborne movement [6251.
The second aspect of nuclear facility siting concerned with transporta7
tion access is related to the delivery of construction materialand major plant

components:
The site should preferably be convenient,to ei.ther bodies of water
or rail,or road corridors of sufficient width and load-carrying
capacity to enable the de livery of construction materials and
,equipment amd major reactor an 'd turbine components without unac-
ceptable disruption of the surrounding environment [207; p.107].

Many of the plant components are very large and massive, so that "water
access is espcially de sirablefor deliver of large shop-fabricated and assem-1
bled reactor vessels, although field assembly is becoming more common" [442: p.81.
For example,
For a PWR the reactor pressure vessel itself may be a steel con-
tainer 17 feet in diameter and 42 feet long with 9-inch thick
walls and a weight of 450 tons... The turbine-generator train may

154

TABLE 14

EXPECTED FUEL AND WASTE SHIPMENTS FOR FERMI 2

FMSH FUEL

Assemblies Truckloads Enrichment Total Wt.
Year Load Per Year Per Year (Wt% U) 7@ (KG)

1977 1 (1st Core) 764 24 1.90 142,000

1980 2 Ust reload)- 276 9 2.61 51,300

1981 3 208 7 2.61 38,700

1982 4 176 6 2.61 32,700

1983 5 180 6 2.61 33,500
1984(a) 6 188 6 2.61 34,900

(a) and annually thereafter

SPENT FUEL

Shipment Total Truckloads Total Wt. Ave. Burnup
Year Number Assemblies Per Year U (KG) (MWD/MTU)

1980 11 276 138 50,400, 12,000

1981 2 208 104 37,700 18,200

1982 3 176 88 31,800 22,000

1983 4 180 90 32,400 23,500

i984,(a) 5 188 94 33,700 26,700

(a) and annually thereafter

155

be as much as 18 feet indiameter by 200 feet long and weigh
3,900 tons. This component, too,.must be-shipped to the site
in major segments weighing'up to 500 tons [207; pp.107-1081.

(e) Seismology and geology
Specific regulations have been published regarding seismic and geological
protection and.assessm'ent of risk for nuclear power facilities ("Design Bases
for Protection Against Natural Phenomena," U.S.A.E@C. 10CFR, 50, Appendix A,
and "Seismic. and Geological Siting Criteria for Nuclear Plants, "U.S.A.E.C.,
10 CRF 100, Appendix A).

Natural disasters such as earthquakes, volcanic activities,
landslides, floodings, and tsunamis are potentially so
catastrophic that their possible occurrence at any site.
could be considered as sufficient cause to exclude the site
from further consideration" [207; p.14].

However, sites subject to flooding, but properly protected, can and have
been used. Site characteristics related to soil stability and topography must
also be considered. In general, however, slope instability will not "pose any
direct hazard to a nuclear power plant that has been well engineered to the
environment" [207; P.151. Also,
Areas of actual or potential.surface or subsurface subsidence,
uplift, or collapse.that can result in such phenomena as ground-
water withdrawal or recharge, mineral extraction, cavernous or
karst terrain, and regional warping should be avoided [207; p.17].

Finally, the potential for site inundation by seiches should be considered care-
fully before siting of a nuclear facility.

(f) Hydrology and meteorology
Among the factors important in determining "the magnitude of the radio-,
active dose received by individuals and the population within 50 miles are...
meteorology, and hydrology of the site and its surrounding environs" [203; p.1251.
Criteria related to the hydrological and meteorological conditions,of a
potential nuclear power plant site have been published [see, for example 207]
and in some instances codified into the federal regulatory structure.
The most significant meteorological concerns are related to the potential
problem of plume formation from a closed-cycle cooling device. As a

156

general rule, the plume from a natural draft tower will rarely extend to the
ground, but rather will merge with existing clouds or evaporate before reaching
ground level. On the other hand, plumes from mechanical cooling towers, ponds,
and spray canals are more like ly to cause ground-level fog [207].
Specific consideration should be.given to the site dispersion clima-:-
tology during the site selection and evaluation process:
A site should provide atmospheric dispersion of radioactive
effluents and wate heat sufficient to protect the surrounding
environment [207; p. 21].

Specific annual average Atmospheric dilution factors have been suggested
by the AEC [207; p.2]]. It is also recommended that specific consideration be
given to the cumulative effect of "wind trajectories passing over several scat-
tered heat sources'! [20.7; p.22] on localities near the proposed site.
More specific recommendations are made with regard to shoreline sites:

.If cooling tower plumes or other atmospheric emissions could
deleteriously affect the residential, recreational, or other
human resources, then shoreline sites which have low over-
water diffusion rates and high over-land turbulent mixing
should be avoided. This especially applies to shorelines
where there are cold currents [207@; p.25].

Two important factors have been identified in evaluating a shoreline site: the

change in atmospheric stability that occurs at the land-air interface, and the

change in wind trajectory that'occurs when air moves from the smooth surface of
the water to the irregular land surface.

The major concerns related to plume dispersion are potential increases.
in fog and ice formation in the area surrounding the plant site. Plumes are
formed when the effluent from the water-saturated cooling device fails to mix
effectively with the.drier ambient air. The degree of plume formation an d
stability is determined primarily by air mixing (mech anical and convective),
temperature, humidity, and ambient air pressure.
At sites where the prevailing atmospheric conditions are less
favorable for thedissipation of visible water droplet plumes,
visibility hazards to transportation and navigation may result.
In particular, environmental hazards may occur where water
droplet plumes from cooling towers or ponds result in fog
formation over corridors of land, sea, or air transportation.

Additional hazards caused by icing may result in areas under
the influence of cooling towers if ambient air or surface
temperatures below freezing are prevalent [207; P-311.

157

As mentioned before, fewer.fogging and icing problems can be expected from natu-

ral draft towers than from other closed-cycle devices.

In the Great Lakes Region, there are several important hydrological as-
pects of a potential site than must be considered. There must be assurance of
along-term uninterrupted water supply in amounts sufficient to meet the plant's
needs. Careful consi.deration must be given to future development in the plant
locality which could change the quantity of water available either for in-plant
use or as a receiving body for thermal and chemical effluents. For streams in
the Great Lakes Basin supplying principal consumptive requirements, lithe con-
sumptive withdrawal should not exceed,50 percent of the lowest monthly mean
flow of record unless reservoir capacity is included" [207; p.401. In addition,
water withdrawals must be related to regional withdrawal agreements, where appli-

cable.

With respect to ground-water resources, the AEC has stated:
Protection of groundwater [sic] supplies is needed for the
.qualification of a site as suitable for a nuclear power plant.
If groundwater is used by the plant, the sustained yield of
the groundwater,system should not be,exceeded, i.e., ground-
water mining would require special evaluation.

The location and use of groundwater at the potential site must
be considered in the selection process if any discharge of water to the
groundwater system, planned or inadvertent, may occur [267; P.431.

Statutory re quirements related to water quality are defined in sections
401 and 402 of P.L. 92-500. All water effluents discharged from a nuclear power
plant must conform to the limitations established under P.L. 92-500. Thus,
@"designs associated with site options should in all cases minimize the discharge
of any materials which contribute to lowering of water quality" [207; p.511.

There are several other important requirements in site selection

decisions:

"Potential sites on waterbodies subject to heavy icing and blockage
need special consideration in order to assure continuity of water
supply. Because ice can impact upon structures, causing plugging
or structural failures, this factor should also be considered in
the selection of a site [207; p.541.

The site must accomodate a power plant design such that the mixing
of all heated or otherwise thermally modified discharges to
receiving'waters can be carried out within the formal mixing zones
established by applicable Federal or State regulations [207; p.57].
Waterbodies which are stratified at any time of the year need

158

special consideration of their vertical mixing characteristics
if they are to be used for cooling water" [207; p.59],

(3) Environmental and Other Considerations

There are a number of further considerations that must be included in a
site selection and evaluation process. A general-consideration is the total
impact of construction and operation on the terrestrial and aquatic ecosystems

in the vicinity of the site. While there are several important specific aspects
to this problem (see discussion below) the overall degree of disruption and
change engendered by the plant must be explicitly discussed. The importance of
these impacts will, of course, depend on the importance (as measured by scarcity,
system function, etc.)'of the ecosystems disrupted and the degree of the impact.

Related to this is the question of the long-term effect of low-level
radioactive emissions on the plant and animal (including human) populations in
the plant vicinity. All nuclear power facilities produce some radioactive
effluents, both gaseous and.liquid, that are released into the environment. The
major concern is that these emissions will be taken up by plants and animals and
will become concentrated through the food chain (see Figure 10). The generic
issue of.long-term low-level emission affects are unresolved and are presently
under -study.
FIGUFE 10
PATHWAYS OF RADIATION THROUGH THE ENVIRONMENT

Critical e Pasturage ------ @6- Animals Dairy
Pathway for Products

Discharge of
Radionuclides Farm
In Gaseous Air Crops 10 Products
Effluents

Nuclear Fish & Fish & Shellfish Human
Reactor Shellfish Processing Population

Recreational
Exposure
Discharge of urf c
Radionuclides Surface Water Edible
In Liquid Water Supply Waterfowl
Effluents

Ground
I
I
I
I

h &
'is
She @ish a 1@7
n

u r. ce

Ground Drinking
Water
water Supply Water

[Source - 451]

159

While this report has not dealt with the-nuclear fuel cycle and the
problems of waste:handling and storage, these,factors are important in the
general decision to authorize or encourage the,development of nuclear 'power
plants. Resolution of problems in these areas is paramount if a major commitment
to nuclearenergy is to be made. Consideration of these problems must be a part
of the decision to permit the continued shift to.a higher nuclear share in the
electric power fuel mix.

One problem that has not been dealt with extensively to date concerns
the eventual decommissioning of nuclear power plants. With a life expectancy of
30-35 years,.utilities and the public at large will have to face this problem in
the near future and consideration should be given to it now. One report [551]
stated that a mothballed period of up to 50 years would be required before "all
areas of the plant site will be available for unrestricted access" [551; p.59-62].
This means that at least a portion of the site would be committed to the facility
for 80 years or more, a long period in terms of land,use change and socioeconomic
development.
Another consideration is whether there is a need for continuous cooling
of the reactor throughout the period prior to final decommissioning. If there
is, then consideration should be given to providing sufficient cooling water to
meet this requirement. Ifa closed-cycle system is used then potential problems
.with maintenance of the system through this period of inactivity should be dealt

with.

As with the other facility types dealt with in this study, perhaps the
most important determinan t of siting and site requirements is public opinion.
However, in the case of nuclear power plants, the public acceptance factor is
even more significant as there, are basic questions being asked about the d.esir-
ability of.using it at all, as evidenced by the many recent State nuclear power

referenda.

(4) Emerging Technologies
There are two principal technological alternatives to the light water.
reactors presently in use: the high temperature gas-cooled reactor (HTGR), and
the liquid metal fast breeder reactor (LMFBR). Only the HTGR is considered to
be feasible (i.e., potentially applicable as a major producer in the commercial
electrical energy market) during the period covered by this study. While the

160

LMFBR may-see some commercial use by the end of the study period, there are too
many technological and political problems with it to make widespread use feasible.
The HTGR was available commercially,for a period although it has seen
only limited use. Research and development on the process is continuing.
Figure 11 shows a cross-sectional view of the major components of a
typical HTdR generating system. As opposed to the LWR system, the HTGR uses
helium as a coolant and heat transfer medium. Because helium can be heated to

higher temperatures and pressures than water, HTGR can achieve efficiencies of
40 percent. The,fuel., -a mixture of uranium 235 and thorium 232, is formed into
microspheres and embedded in a matrix of graphite blocks. While large quantities
of thorium are not available today (primarily due to a lack of demand), economi-,
cally recoverable reserves are thought to be available in sufficient quantities
to supply a 100,000-Me capacity for.400 years [222]
HTGR proponents claim significant safety advantages over available LWR
systems [222]. First, los's of the helium coolant does not represent as severe
a problem as does the loss of the coolant water in a LWR, because the graphite
core can absorb substantial amounts of heat. Second, the use of a prestressed
concrete reactor vessel (PCRV) adds to the overall safety of the reactor by
eliminating the worry of a primary pipe rupture. Third, the use of small,
coated fuel pellets instead of large fuel rods reduces,the amount of radio-
active material released to the coolant should a fuel pellet rupture. Finally,
the graphite core reduces the chance of a major core meltdown.
Use of a direct-cycle system in which the helium is expanded through the
turbine could raise HtGR efficiencies to 50 percent.

C. Fuel TransshkEent and St@qrage Facilities
Ports and terminals are being co nsidered as energy facilities insofar
as they relate to the transshipment and/or storage of fuels and materiala
associated with power plants, conversion facilities, and refineries. Because
this category is represented by a wide variety of facilities, it serves no use-
ful purpose to attempt to establish a generalized definition of any one facility.
However, these facilities may be classified according to the type of fuels or
materials which they handle, e.g., coal, oil, or nuclear fuels and.wastes. Fur-
thermore, the six general siting considerations established at the outset of
.this report may.be expanded-as they apply to ports and terminals. These facili-
ties include harbors, associated storage areas, and combination rail-harbor

FIGURE 11

HIGH TEMPERATURE GAS REACTOR

containment structure

helium circulator
control steam
rods gen erator

q;.@f 04.

Tj
XOM".
Z.
F"

steam line

turbine
N-RN. !;A.
rator
2N "n

:V @tgi
A
-IN N
MNA

Nn 05

condenser
purn
P
cooling
water

prestressed concrete reactor vessel

[Source 222]

162

transshipment facilities.

(1) Facility'Types

(a) Coal

Development or expansion of coal handling and storage facilities depends
directly on projected increases of coal.utilization within the Great Lakes Basin

and changes in mode of transportation. Furthermore, increased use of low sulfur
western coal has necessitated a change in coal traffic flow on the Great Lakes
,and corresponding development of new storage and handling facilities. The gen-

@eral considerations associated with the development or expansion of these facili-
ties are demonstrated in such specific cases as the coal transshipment facility at
the Duluth-Superior harbor and the unloading facility at Marquette, Michigan.
In the case of the Duluth-Superior facility, a detailed report [3911 was
published outlining the site selection process and the impacts associated with

the final propsed site. Paramount in the location analysis was the need for
multimodal transshipment capabilities (e.g., ship.and rail); rail lines capable
.of supporting unit train.transport; and potential for adequate docking facilit
ties for large lake freighters. Furthermore, relative proximity to coal source
and load center was a major consideration.
After selection of the location at Superior, Wisconsin, attention was
shifted to defining the impacts.of the proposed facility and designing controls
to reduce or preclude any negative impacts. The impacts most directly associated
with the, construction and operation of such a coal transshipment facility are the
effects of coal,dust on ambient air and water quality. During the process of
moving coal -from unit train, to storage pile, to conveyor belt, to ship, large
amounts of coal dust may be generated and controls must be implemented to reduce
the amount of dust which escapes into the air or water. Some controls include
wetting down the coal with special suppressants, and the use of restricting bag

chutes on the conveyor systems.
Other impacts are those generally associated with construction and
operation of.a major facility. These include dredging, dredge spoil, and land
alteration impacts on surrounding air and water quality. Also, magnitudes of
community disruption, noise, and aesthetic impacts are considered in the assess-
ment of the Superior facility development.
The coal unloading facility at Marquette, Michigan [299] is designed to

163

supply coal directly to the Presque Isle generating station at Marquette. Its

development was related directly to projected increases in coal requirements by
the power plant and a desire to modernize the existing facility. This,moderniza-

tion included the elimination of a short haul rail line and overall decrease in

personnel requirements due to automation. According to the environmental impact

statement:

Consideration of siting the proposed unloading facility must
acknowledge the presence of existing facilities in the
vicinity of the site. The immediate environs surrounding the
Presque Isle site are presently committed to industrial use.
Since the site west of Lake Shore Boulevard has-already been
dedicated to power generation, the unloading facility 'can be
considered a reasonable adjunct to this enterprise [299].

From the above two examples and others, it is possible to summarize the
general resource requirements and the major impacts which are specific to this

type of facility.

Of primary concern is the availability of land adjacent to existing rail
and harbor facilities- Acreage@ requirements for coal storage and related han-
dling equipment vary greatly depending on the configuration of the coal p ile and
the length of reserve time-required. Based on figures from specifications in
project reports [391, 203, 299, 526] and communications with coal dock personnel,
an approximate figure of 35,000-40,000 tons.per acre is reasonable for a coal
storage land-requirement.,-assuming a 40@-50-foot pile height. This figure can
vary greatly depending on the customer-pile relationships and the type of mech-
anical stacking,equipment employed.
Major impacts of.coal handling facilities as evidenced in the previous
discussions include -disruption of communities during construction, increase in'

noise levels as a result'6f heavy equipment use, health-and cleaning problems
associated with toil dust as a result of coal handling, water quality problems
associated with runoff from coal piles, and removal of land from multiple use
for storage.

@(b) Oil
Oil storage facilities are utilized at almost all the major ports on the
Great Lakes [535]. This includes both crude oil and refined products storage
and related transshipment facilities. Future development of storage and hAn-.
dling capacity :Ls expected to take,place primarily in the form of expansion at

164

existing facilities. This, of course, is highly dependent on decisions regarding
potential future development of major pipelines capable of bringing crude oil

into the Great Lakes Basin from sources in the West.

Considerations of particular importance to the siting of new facilities

or expansion of existing facilities which store or handle oil are primarily in
the areas of systems requirements and environmental concerns. Presently, most
storage facilities contain refined petroleum products and are situated at Great
Lakes ports to facilitate ship loading, which in turn insures a wide variety of
distribution points without the restrictions of a permanent pipeline. Crude
oil on the other hand is routed by pipeline directly to the regining facility.
(In 1974, crude oil represented only .2 percent of the petroleum products ship-
ped on the Lakes [536]). A discussion of the crude oil-refinery relationship
is contained in the following section.
Storage and handling facilities are located with-regard to existing and
potential product distribution systems. Consequently, most oil storage tank
farms are located at Great Lakes ports, particularly those ports which have re-
fining capacity and, thus, short distance product transport capacity. From a
systems planning standpoint, the location of storage facilities at ports and
utilization of the extensive shipping network provides for the widest distribu-
tion of refined products.
A review of some of the important environmental.considerations associated
with the development or expansion of an oil storage and handling facility is pro-
vided by the Lakehead Pi pe Line Company for their proposed Refined Products
Terminal in Superior, Wisconsin (1581.
As might be expected, the primary concern regarding the facility is safe-
guarding against potential spills in storage and handling. This would include
,tank construction, pipeline integrity, and any special precautions required for
the loading manifold (pipeline-ship hookup). Clay dikes surrounding the oil
storage tanks are proposed in order to insure control of potential spills in,
the case of tank leaks. The negative effects of oil on water quality and aqua-
tic ecology are well documented; consequently drainage controls and leak security
are important considerations. Other considerations for oil storage facilities
are those.associated with hydrocarbon emissions from storage tanks. Ambient
air quality may in some cases prohibit further expansion of oil storage capacity,
if this expansion is projected to raise hydrocarbon levels above acceptable
standards. Emissions during vessel loading are a particular problem.

165

The scope of this study did not allow a complete investigation of the
nuclear fuel cycle, nor of the controversial issue of nuclear waste disposal.
However, becauseof the extent of planned nuclear-power development in the Great
Lakes states, it is necessary to comment at least on handling and storage of the
fuels required by these plants and the.waste generated from them.

Because of the comparatively small volume of fuel required by nuclear
power plants, transshipment and storage facilities such as those associated with
coal and oil are not a necessary component in the fuel,delivery system of nuclear
plants. Arrangements for delivery of nuclear fuel involve truck..transport from
the fuel processing plant directly to the power plant site [379]. Transport
and/or storage of wastes remain uncertain at this writing but are anticipated to
involve either truck or rail transfer from the generating plant directly to a
disposal site or fuel reprocessing center. Consequently, without dismissing the
safety and disposal problems associated with nuclear fuels, the role of nuclear

fuel transshipment facilities is small or non-existent.,

(2) General Considerations

(a) Systems requirements

Expansion of harbor or harbor-rail facilities necessarily depends on com-
parable expansion or development in power production or changing emphasis in
transporation modes. In addition to new facilities, existing developments, such
as harbors, docks, and rails, provide areas for continued expansion. Other sys-

tems considerations are the relative distances and related transportatio n costs

between proposed storage or handling facilities and'ultimate usage locations.

(b) Safety
The considerations within this category apply primarily to the environ-
mental aspects associated with the storage and handling of-fuels. These would
include the affects of spills or leaks of rad ioactive fuels or wastes, the
affect of coal dust and other particulate matter associated with coal storage
and handling, and the problems with hydrocarbon emissions from oil storage tanks.

Engineering
Development or expansion of storage and/or handling-facilities entail
many engineering considerations similar to those discussed for other energy

166

facilities. Most important of these are the feasibility of the land-water inter-

face and the design of harbor breakwaters-and docks. Likewise, consideration

must be given to,foundation stability and soil properties. Finally, pollution
abatement and control is an important consideration when associated with the
preceding and following sections.

(d) Environmental

Determining site locations for development or expansion of fuel storage
and handling systems relies heavily on the potential environmental impacts of
the facility: possible water pollution from runoff, spills, and ship activity;
air pollution from emissions, hydrocarbon leaks, and coal dust; increase in
ambient noise levels due to unloading operations and related industrial activity;
aesthetic considerations such as visual impacts of coal piles, tanks, stacks,
dust, and railways; decreases in nearby residential land values due to industrial
development; anddisruption of terrestiral and aquatic ecology.

(e) Institutional
Regulating and permitting procedures by state and federal agencies must
be met in some phases of siting of storage and handling faciltie s. These would
include filing of environmental impact reports with the proper administrative
body, application for construction permits with agencies such as the Corps of
Engineers or state departments of natural resources, and meeting various state
and federal air and water quality standards. In addition, specific safety
regulations regarding the storage and/or handling of radioactive wastes would
be a special consideration for the placement of these particular facilities.-

(f) Economics
Costs of the above considerations are a majo r determinant of the loca-
tion and mode of storage and handling facility to be constructed. The costs of
land acquisition, construction, and operation will vary depending,on the type
of facility planned and the kind of fuel to be considered, Likewise, pollution
control and abatement costs are dependent on the materials and the areas in
which they are handled but are major considerations in the planning phase.

167

d. Refineries

(1) Description
Present petroleum refining facilities in the Great Lakes Basin range
from small, less than 10 mbd (I mbd = 1,000 barrels per day), to plants with
capacities greater than 350 mbd. At the present time, there are no new refin-
eries under construction in the Basin although several existing facilities are
being expanded. The largest expansion identified at this time is one of 27.5
MBD. The only new "grassroots" refinery being considered in the Basin would be
a 200 MBD facility at Oswego, New York, although no decision has been made as
yet as to whether or not it will be constructed. Further discussion of present
and future refinery activity in the Great, Lakes Basin can, be found in Section IV.B.,
I'En ergy Consumption and Movement in the Great Lakes Region."

Refineries are by nature very complex systems with many components. As
such, it is difficult to characterize a "typical" configuration, size and pro-
duct mix. Generally, complexity and associated resource requirements increase
with product mix diversity. As will be discussed below, refineries specializing
in one or more of the four "standard" products (gasoline, jet fuel, diesel fuel,
and fuel oil) are relatively simple and require less area than a diversified
refinery producing a wide range of products and petro-chemical feedstocks [2921.
Contact with several of the refineries in the Basin has indicated that they pro-
duce a broad spectrum of producrs with little evidence or regional specialization.
'Figure 12 shows some of the major components and feedstock flow patterns
used in modern refineries. The configuration of these components and flow rates
will vary from refinery to refinery, depending on crude oil supply source and
product mix. For a more complete discussion of these components, including
their potential environmental impacts, the reader is referred to 370.. In addi-
tion, reference 135 provides concise descriptions of several refinery
co n f i gurat ion s.

(2) Site Requirements
General siting considerations for refineries can be broken into two
groups: economic criteria and environmental criteria [292]. While both will be

For the purpose of this discussion, no distinction has been made between bar-
rels per calendar day (annual capacity divided by 365) and barrels per stream
day (annual capacity divided by the days the refinery is actually in operation).
Generally, calendar day capacity is about 95 percent of stream day capacity.

Fu,@l Gas >
Gas L iquified Pelroieum GCS(LPG4%
Recovery
Plant

lsomerizotion
Purchased Buinne lsobutone
unit

Aviation
Light Straight Run Gasoli IF) Motor arid
Aviation Premium
To '7,os Recov
0 Requior
i-= 0 Fuel Blending
.010 Naptha Catalytic Reformate
all,
- - Hydro- Reforming
(@5 0
Li:@4' a on >'N
Crude Oil >,- desulfjr-i2er Unit Alkylets
Fuel
:cx Turbine Fue I

CN
Kerosine
Gas
0 te No. I
0 Alkylotion Disii1la,
LO Kercsine Catalytic Recovery Heating Oil
000 Hydro- --i' Cracking Plcnt Unit Blending
-00 k' IDiesel Fuel
co desulfurize" Unit P G > No-2 Heating Oil - >
Gasoline
(s5o-noooF) Catalytic Cycle Oil
Ca+clytic Heavy Cycle Oil No. 5 a 6 Fuel Oil >

Vacuum Residuum
Rood Oils and AsDholt
Distillation LO Hydro-
Topped Crude Unit W desulfurizer
(850-150oo F)

MAJOR COMPONENTS OF A REFINERY
FIGURE 12

169

discussed at greater length below, some general observations can be made at this

time. The two most important economic criteria areavailability-of crude.oil
and access to product markets. The most important environmental criteria con-
sidered in the Great Lakes.Basin region relate to air and water quality regula-
tions. Also important are,problems related to visual intrusion (aesthetics) and
socio-economic impacts to the local area.'

(a) Land requirements
Estimates of land required for refineries of varying sizes and complexi-
ties are shown below in Table 15. Because major Great Lakes refineries would
generally fall into the."diversified" class, the acreage estimates given for

that class are the most important for this study.

TABLE 15

REFINERY LAND REQUIREMENTS (ACRES)

C'O M P L E x I T Y
CAPACITY (MBD) SIMPLE MAJOR PRODUCT 2 DIVERSIFIE3

6 6
700 800 1860-21054
100 6
1000
14006 1600 6 3720-42104
200 18007
14008
20006
1750 6 2000 6 4650-52654
250 10005
25006
1 Gasoline and fuel oil (2921
2
.3 Gasoline, fuel oil, jet fuel, and diesel fuel [292]
Widd range of distillates
4
Reference 222 - Room for expansion buffers. Accurate within
a factor of 2.
5 Reference 505 (New Eng. Vol.II)
6 Reference 292 - Includes doubling, 60'day storage
7 Reference 370 -Includes doubling,, buffers
8 Reference 285 -15 days stor .age
8 00

6
1
8

0
6

160 372
0

2OOC

0006 C
@2 465
1OOC

500

170

In a report on refinery siting considerations [370], estimates for land
required for 200 mbd account for 1.27-3.73 percent of the total facility cost
(estimates based on 1973 dollar costs). As a result
... refineries have an incentive to buy as much land as possible
for use as a green belt and for storage. The green belt is
important for aesthetic reasons and so that emissions measured
at the fenceline meet standards [370; p.13].

if it is assume4 that future refineries would allow sufficient space to
double production capacity as well as provide a green belt to isolate the plant
from surrounding land uses, flaverage" site sizes might be:

100 mbd 1,500 acres
200 mbd 2,200 acres
250 mbd 2,-700 acres

(b) Location with respect to population
When selecting a site for a refinery, there are two countervailing forces
considered. One is the necessity of being located close to.the finished product
market or distribution system to reduce transportation costs. The second is to
meet environmental criteria related to reduced air quality impacts, aesthetic
and noise impacts, etc. As indicated above, companies are balancing these two
criteria by locating on large sites in which it is possible to isolate the
plant from the surrounding population. How these two forces balance in a given
plant location decision depends on the specifics of the situation and cannot be

generalized.

(c) Water requirements
Water use by a refinery can be partitioned into process water used in
producing the distillates (usually an insignificant fraction of total consump-
tion) and cooling water. The amount of cooling water'required will depend on
the component configuration and the extent to which air cooling is used. Typi-
cal values are given in Table 16.
Reductions in water consumption for cooling are possible using a higher
level of air cooling. However, it would increase capital costs and the land
required as well as the level of noise produced [505]. Even without a total
shift to air cooling, however, refinery dependence on easy water access has
been decreasing. This conclusion is best summarized as follows:

171

TABLE 16

REFINERY COOLING WATER REQUIREMENTS

WATER REQUIRED
CAPACITY (MBD) MGD CFS

4131 6.2/4.6
2
100 5-10 7.3-15.5

8/6 1 --12.4/9.3
200

10/7.51 15.5/11.6
250 4.5-5.43 7.0-8.4

Estimated 1985/2000 make-up requirements [285]
2
(292], 40-50i air cooling
3 [506], 40% of total flow consumed

Historically, siting was dependent upon water supply and waste-
water disposal considerations, but this dependence is weakening
as 4ter makeup' and discharge both decrease with increasing
water recycling practices [-370; p.63].

(d) Transportation access
As indicated above, the two most important economic criteria considered
in refinery siting are crude oil supply and product distribution. In terms of
crude-oil supply to the plant, there are two principal modes available in the
Great Lakes Basin: tankers and pipeline. The extension of the nationwide crude
oil pipeline system into the Great Lakes Region has made it unlikely.that future
refineries will be dependent on tanker-supplied crude oil. This conclusion was
reached in a study of the Great Lakes transportation system [14-7], which stated
that, "consideration of oil and gas in relation to the Grat Lakes shipping does
not involve to any significant degree either crude or products as cargoes to,
from, or within the Lakes." Support for this conclusion came by contacting
several of'the refineries in the Great Lakes Basin; most crude was received by

172

pipelines from either the southern U.S. or Canada.
The product distribution question is somewhat more complicated. Because
product transport is more expensive than crude oil movement, this may lead to a
situation in which refineries are located close to their potential product mar-
kets, with crude oil supplied by pipeline or tanker. -In this way, crude oil
source is less determinative of site location than is product market location
[370]. This view of the site selection process can be summarized as follows:
Petroleum refining is rapidly becoming "market oriented" rather
than "raw material".oriented. This trend stems from the general
concession that transportation of crude to the refinery is less
costly than transportation of products to the market....There-
fore, it is very likely that new refineries4will.be located in
the vicinity of the large metropolitan markets such as the East
Coast, along the Great Lakes, the West Coast, and the Gulf Coast
[370; pp.53-541 (emphasis added).

Under this view, one would expect to see major new refining capacity, either as
new plants or large-scale expansions of existing facilities, come into being in
the Great Lakes region in the near to mid-term future.
There are, however, certain constraints that modify this market-oriented

site selection model. Some of these constraints were discussed previously: land

and water availability in the quantities required. Others, related to long-term
protection from natural disasters, are discussed briefly in subsequent sections.
Constraints related to potential environmental and public-acceptance problems
will also be discussed in the section,".Envi.ronmental and Other Congiderations."
Of particular importance to this study is that most of the large re-
fineries in the Basin are connected to a regional/national product pipeline
system (see Figure 13). For this reason, refineries do not have to be located
in the vicinity of their potential product market. Instead, the national re-
finery system can respond to regional demands and ship products to the points
where they are needed. The existence of this demand-responsive system obviates
the need for locating r'efineries in each,product market area. Indications at
this time are that major new.refining capacity will be located outside of the
Basin (most likely on the Gulf Coast) and the products moved through this sys-
tem to the Great Lakes market. Thus, refineries are not expected to be a major
concern in the future energy facility siting in the Great Lakes region.

(e) Seismology and geology
Requirements for refineries are much the same as those for coal-fired

04 1. Duluth

FAMAn

cm- Ply I

A.? La city
si- r.11.

7 PiT@"-'
Choy".. N,rt*. Do, x0i.e.
6
Una 0 k
% %0
& Ult [Ak. city
cite v e RiVer
411
Mt. VeMaM

S, T"A
14, VA.-It"

L.'s V.ps

C. City
okIlah." City nio- ro@% @00 12

$0. r1cl 12 A
.7m..Lx

o*
Z.
T P.,I. r-t v-
pipalln's
11b i1c
o

40 orl
go.

Am.nio

C.,pu@b choi.tl

[Source 493]

FIGURE 13

MAJOR NATIONAL PRODUCT PIPELINE SYSTEM

174

generating plants--i.e., they be located in areas with suitable foundation condi-
tions outside of areas withactive faults or other types of geologic hazards.

M Hydrology and meteorology
As is the case with the coal-fired power generating facilities, refiner-
ies should be located outside of areas prone tolflooding and where plant opera-
tion will not adversely affect surface and ground-water quality.

(3) Environmental and Other Considerations

There are several further criteria to be considered in the siting of new
fuel processing facilities. The most important relative to*the Great Lakes Basin
are those concerned with environmental quality. In particular, air pollution
emission standards may prove to be the most.restrictive in terms of limiting
new plant construction (and possible expansion of existing plants). While

most air quality problems can be solved, reducing hydrocarbon emissions to
the levels specified in the national standards presents major technological
difficulties. This problem has been highlighted in several reports dealing with
refinery siting [506, 285, and 370], indicating "the need for careful attention
to hydrocarbon emissions in refinery siting decisions" [506; pp.II-50]. How-
ever, care must be taken to assess refinery effluent impacts with respect to
existing water quality conditions in the receiving stream. Also, low-flow
conditions of the receiving waters must be considered in a refinery siting
decision. Finally, the state water quality control agencies should be contacted
since states have the right to impose water quality standards more stringent

than those established at the federal level.

The final site selection consideration discussed here, public acceptance,
is perhaps the most important of all. It has become increasingly obvious in:the
past couple of years that public sentiment can be the final determinant of where
new refining capacity will ultimately be located. An'excellent example of this
is the case of the Olympic refinery (400 mbd) proposal for Durham, New Hampshire
that was rejected by local residents in 1974 [505]. Th US3 it is important that
public opinions and attitudes be assessed early in the site selection process.
In addition, the issues causing greatest concern, air and water quality degrada-

tion, aesthetics, conflicting land use, etc, must be addressed directly at the

See discussion of EPA for details of air pollution control program, Chapter III.

175

outset. (Some of these impacts are discussed in a subsequent section.)

(4) Summary
The process of selecting a site for a major new refinery is. complex-,'
superceding simple regional boundaries. Because the U.S. refinery system is
tied together via an extensive crude oil supply and product shipment pipeline
system, the decision of where to locate a new facility is made at the national
level, in conjunction with various regional considerations related to crude oil
supply aind environmental quality limitations.

4. ENVIRONMENTAL AND ECONOMIC IMPACT ANALYSIS

a. Introduction

This section presents both adiscussion of the environmental and economic
impacts of the energy facility types considered in this report and a framework
within which these impacts can be organized. Because of the specific nature of
the data required, this framework cannot be used to perform a regionvide general

facility analysis. Rather, it has been included to provide the coastal zone
management programs with a concise framework within which they can evaluate pro-
posed energy facilities. In addition, it provides a useful summary of the major

facility activities as well as the potentially affected environments. Finally,
.it has been used as a guideline in development the accompanying text material.

(1) Framework Approach
For each'facility type, there is a general discussion on potential im-

pacts to both the natural and cultural environments. Following this, there is
an activity impact matrix specific to each facility type. On this matrix,
activities associated with a given facility are listed on the left-hand side and
are cross-referenced with potentially affected environments. There is a separate
matrix for each of the major facility types:
e Fossil-Fuel (Coal Power Plants

e Nuclear Power Plants

e Coal Transshipment and Storage Facilities
0 Oil Transshipment and Storage Facilities

a Refineries

176

The degree of impact would be indicated by a numerical entry at the intersection
of the appropriate activity and environment. An impact scale of -3 (major nega-
tive impact) to +3 (major benefit) is suggested. There would also be a'@special

entry for those potential impacts that are inherently immeasurable. It is
important to emphasize again that this system will not and cannot be used in a
regionwide analysis. It is, instead, intended to be used by the states in
evaluating specific facility proposals.

(2) Facility Activities
The energy facilities consideredin this study have been characterized
in terms of activities associated with them. F8r the purposes of this report,
an activity is defined as follows:

Activity--The major actions associated with the construction and opera-

tion of major energy facilities.

These activities have been further subdivided into one or more impact vectors,

which are.defined as follows:
Impact vectors--Those asp ects of an activity w.hich may result
in a significant change in the existing environment. In some cases, they repre-
sent actions, such as ground clearing and reshaping, -equipment use, channeliza-
tion, and shoreline modification, etc. Others are the resul-t of an activity,
such as in-flux of temporary work force, wastewater discharge, thermal effluents,
etc. It is important to note that they are not potential impacts themselves but
rather are elements of facility operation or construction that may cause impacts
on certain aspects of the natural and cultural environment.
The following material presents definitions of all activities and impact

vectors used in the five facility-type matrices.
(a) All facilities
Construction--That activity associated with the actual development of
the energy facility. It is common to all facility types and is found on each

matrix.
9 Ground clearing and reshaping--Those operationsinvolving a
physical disruption of the ground surface, including stripping of Vegetation,
grading, excavation, road building, and site restoration.
9 Equipment use--Those impacts directly attributable to the use
of construction equipment, such as noise, dust, air pollution, etc.

177

e Channelization, shoreline modification, and other water-

related activities--All construction activities.associated with the water, in--
cluding channelization of harbors for moving heavy equipment and material to
the site, construction of breakwa.11s, jetties, and other shore protection de-

vices, construction of docks and terminals for fuel and product transshipment,

and the construction of water intake and outlet structures.

e Material movement to site--Those impacts related to the move-
ment of construction materials to the facility site, e.g., disruption of local

traffic patterns, deterioration of.roads, dust, and noise.
9 Influx of temporary work force--The impacts of moving a large
(1,000-3,000-person) work force into a local community during the construction
of a major facility. These impacts may be expressed in terms of increased
demand for housing, increased local business activity, increased local inflation,
increased demand for public services, etc.
9 Public service requirements--The impact that construction of
a major new energy facility would have on levels of public services required in
the local area (independent of those above), including public safety (fire,
police, and medical protection), water supplyand wastewater treatment facili-
ties, government services, etc.
e Land committed to facility--The impact of the lost opportun-

ities for potential uses of the land committed to the development of major
energy facilities (several hundred to several thousand acres).
Other--Facility or site specific construction activities,
specified on a case-by-case basis.

(b) Nuclear power plant operation
Reactor Operation--Those impacts associated with the production of power
from a nuclear reactor facility. This does not include those impacts generated
by the cooling system, by fuel and waste handling, or by the transmission of
the electric power.
0 Rad emissions--Those impacts generated by the emission of
radionuclides to the air and water. While a portion of these radionuclide emis-
sions are associated with the cooling system, they have been included here to
provide for the more general case of overall plant operation.
Wastewater discharge -Those wastewater effluents not associ-
ated with the cooling system nor containing radionuclide emissions (e.g.,

178

stormwater runoff, sanitary sewage, and other non-process water uses).
Human service requirements--The long-term employment and
public service requirements of operating a nuclear power plant facility. This
includes plant operating personnel, public safety requirements (possibly includ-
ing disaster training for police, fire, and medical personnel), increased gov-

ernment services, etc.
e Accidents--The potential for major disaster occurrences (e.g.,
core meltdowns and radioactive gas emissions). Because of the potentially cata-
strophic nature of such an event, its impacts are immeasurable. This category
has been included primarily to emphasize that such events should be considered
when judging a proposed nuclear facility.
Fuel and Waste Handling--Both an activity and an impact vector. For the

purposes of this study consideration of fuel and waste handling problems has

been limited to those aspects directly related to the energy facility site; it
is beyond the scope of the present project to consider problems related to waste
reprocessing and ultimate disposal.- While such problems are not explicitly dis-
cussed in this report, they must be considered as part of an overall site approv-

process.

Cooling--Those impact vectors directly related to the operation of the

facility cooling system.
o Thermal effluent--Those environmental impacts related to the
release of heated water from the cooling system into the environment.
o Chemical additions--The impact of the various chemicals, such

as chlorine, added to the cooling waters to prevent fouling, scale formation, etc.

e Blowdown water--That fraction of the cooling water removed to
prevent the Ibuild-up of an undesirable levels of dissolved solids in the cooling
water system. It does not include water removed from the boiler-turbine system.
o Makeup water requirement--The impacts resulting from cooling
system consumptive water use.
o Fog/drift -The impacts of the production of a Visible water
vapor plume (fog) and the deposition of dissolved solid material on the ground
surface (drift).
o Entrapment/impingement--The physical impact or damage that
the cooling water intake has on aquatic organisms (primarily plankton and fish).
0 Visual intrusion--Those impacts associated with the physical
presence of a major structure as they relate to the surrounding environment.

179

Transmission--Those impacts related to the transmission of electrical
energy via EHV and UHV transmission lines. Also included are those impacts of
maintaining these large bulk transmission systems.
0 Visual intrusion--(See previous definition.)
e Disruption of human activities--Those impacts related to a
limitation on the use of land or the movement of people across it. Examples are
the fractionation of property by rights-of-way, and the limitation of the use

of lands within a right-of-way.
e Natural system disruption--Those impacts affecting the ecology
of an area. They may be reflected in changes in the species diversity of the
plant and/or animal communities in and around the area of interest.
Electric field ef@ects--Potential impacts of high energy
electric fields, especially those associated with UHV (765 KV and larger) trans-
mission lines. Examples of these potential impacts include-radio noise (RN),
television interference (TVI), audible noise (AN), induced voltages, and pro-

duction of ozone near the lines.

(c) Fossil fuel (coal-fired) power plant operation
Fuel Transshipment and Storage--The receiving, movement over short dis-
tances, and storage of coal at fossil fuel power plants.
� Noise-- The impacts of noise generated for a given activity.
� Particulates--- The impacts of fine.solid materials given off
to the atmosphere during fuel processing and storage or combustion.
e Leachates and runoff--The impact of material leaching and
washing off of stored coal and surface wash from plant site in general.
* Visual instrusion--(See previous definition.)
o Human activity disruption--(See previous definition.)
* Equipment use--Impacts associated with the use of fuel-hand-

ling equipment.
Plant Operation--That activity directly related to the operation of a
fossil fuel power plant to produce electricity.
e Wastewater discharge -(See previous definition.)
o Particulates--.(See previous d&finition.)

0 SOx emissions--The impacts of sulfur emissions from plant

operation and fuel processing.

180

NOx emissions--The.impacts of nitrogen oxide emissions from
fuel processing or combustion.
@ Human service requirements--(See previous definition.)
0 Accidents--(See previous definition.)
@lin@--(See previous activity and impact vector definitions.)
Waste Handling and Storage--An activity associated with the disposal and
storage of waste from fuel combustion or processing. This may include fly-ash
and spent sulfur dioxide control materials (limestone, dolomite, etc.). Impact
vectors included under this activity have been satisfactorily defined previously.

Leachates and runoff--

Particulates---
e Visual intrusion-- (See-previous definitions.)

e Human activity disruption -
e Natural system disruption -
Transmission--(See previous activity and impact vector definitions.)

(d) Fuel transshipment and storage facilities

General--Activities common to both coal and oil transshipment facilities.

Harbor maintenance--The impact of additional harbor mainten-
ance required to service fuel transshipment and storage facilities, including
such operations as dredging, dredge spoils disposal, breakwater construction, etc.
0 Waterborne material movement--The impacts of additional harbor
traffic related to the development of a fuel transshipment and storage facility.
It only deals with impacts in the harbor area, not on the lakes in general.

9 Overland material movement--Impacts of material movement in
the vicinity of the facility. It does not include impacts of the movement of

material from the point of extraction to the facility.
Coal Facilities--Those impact vectors specific to coal transshipment.and
storage facilities. All impact vectors included under this activity have been
defined previously.
0 Human service requirements--

o Particulates---

e Leachates and runoff--
(See previous definitions.)
* Visual intrusion--

* Human activity disruption--

e Equipment use--

181

Oil Facilities--Those impact vectors specific to oil transshipment and
storage facilities..

9 Hydrocarbon emissions--Those impacts associated with the dis-
persion of hydrocarbon vapors into-the-atmosphere.
Leaks and spills--Those impacts that occur through the re-

lease of small-amounts of oil into the environment.
* Visual intrusion--(See previous definition.)
9 Human activity disruption--(See previous definition.)
* Accidents--(See previous definition.)

(e) Refineries
Crude.Oil Receiving and Storage--Those impact vectors related to the
movement of crude oil from its arrival point (e.g., pipeline, tanker terminal,
or rail terminal) to the refinery complex and its storage onsite. All impact
vectors included in this activity have been defined previously.

* Hydrocarbon emissions--

e Leaks and spills--
* Visual intrusion-- (See previous definitions.)
9 Human activity disruption--

* Accidents--

Plant Operation--Those impact vectors related to fuel processing at a
refinery. (The following have been previously defined.)

e SOX emissions--
* NOx emissions--

9 Particulates---
* Hydrocarbon emissions--
* Other emissions--Impacts associated with the emission of
other refinery residuals to the atmosphere, including aldehydes, carbon monoxide,.

and ammonia.

* Leaks and spills--(See previous definition.)
* Solid wastes--Impacts stemming from handling and disposal of
refinery waste materials,. such as sludges and biological solids.

9 Cooling water consumption--(See Makeup Water Requirement.)
e Process Water Consumption--Water consumed in processing crude
oil and feedstocks independent of the cooling system requirements.

182

9 Wastewater effluents--(See previous definition.)
Visual intrusion--(See previous definition.)
Accidents--(See@previous definition.)
Product Storage and Shipping--The activity with the impact.vectors re-
lated to the storage of refinery products and their transfer into a shipment
system (truck, train, pipe, or ship). All associated impact vectors have been
defined previously.
Hydrocarbon emissions--
Leaks anq_@@ @ills-
Visual intrusion-- (See previous definitions.)
e Human activity disruption

e Accidents--

(3) Impacted Environments
The environments potentially impacted by the activities associated with
the construction and operation of energy facilities may be.conveniently divided
into two major categories: natural and cultural. The natural environment in
this analysis refers to the existing physical, chemical, and biological charac-
teristics of a site or area which may be altered by a proposed activity. The
cultural environment may be distinguished from the natural by emphasizing the
attributes, uses, and alterations of the environment associated with human

development. These may be divided into the social, economic, and physical
aspects of the human,environment.

(a) Natural

(i) Physical and chemical characteristics
Dividing the environment into its three major,components, terrestrial,
hydrological, and atmospheric, it is possible to describe the existing conditions
and suggest how those conditions may be affected by a proposed activity. Under
terrestrial are included the existing soil characteristics defined in terms of
quantity and composition and landforms which define the natural topography.
The hydrological category includes both the quantity and quality aspects
of the surface and ground-water systems. It is necessary to define the existing
characteristics of water supply and water quality in order to determine the
potential impact of,a proposed activity, such as the development of a cooling

183

system and the associated additional demand for water. Changes in water quality
that result from this activity are potentially important impacts and should be
accounted for in an impact analysis., Examples of such physical and ch emical
quality,changes would include alterations in temperature due to thermal dis-
charges from cooling systems.and increases in chloride content as a result of

chemical treatment.

The atmospheric category includes the local meteorology of a proposed
site and the ambient air quality associated with the area. Because of the
importance of the meteorology to local circulation patterns and affected land
-uses (e.g., agricultural), any potential impacts from energy facility activities
should be outlined prior to implementation. Likewise, any alterations in air
quality, beneficial or detrimental, which may result from a proposed activity
should be noted in an environmental impact assessment. An example of this would
be the increase in hydrocarbon levels associated with the einplacement of a new

oil refinery.

(ii) Biological conditions
The natural,biologic,al conditions can be divided into the terrestrial
and aquatic ecology of a given area.
...The.terrestrial ecology can be categorized in terms of the vegetation
and the wildlife which characterize an area or site for a proposed energy.facil-
ity. Because of the complex interrelationships within these categories, it is
important to outline any potential alterations or disruptions in the vegetation

and wildlife communities as a result of.activities associated with the construc-

tion and operation phases of a proposed facility.
Likewise, impacts on aquatic life, such as disruption of benthic com-
munities due to dredging, entrainment, and impingement of nektonic communities
by water intake systems, and alteration of planktonic life due to thermal changes,
are all potentially significant and should be addressed in an overall assessment.

(b) Cultural

The cultural environment refers to the attributes, uses, and alterations
of the natural environment associated with human development. These can be cate-
gorized into social, economic, and physical headings.

184

M Social

Included in the social division of the cultural environment are the un-

quantifiable aspects associated with aesthetics and human interest and the poten-
tially sensitive areas of public health.
Aesthetics and human interest refer to the prevalent values assigned to
natural features such as scenic views and vistas, wilderness qualities, land-
scape design, unique physical features (e.g., sand dunes), parks and reserves,
rare and unique species and ecosystems, and historical or archeological sites.
It is possible that activities associated with the development of energy facili-

ties may create, enhance, alter, reduce, o r destroy those features to which

value or interest is attached in a particular area and this impact should be

noted.

Factors related to public health which may be affected by a specified
activity include ambient noise levels, quality and quantity of drinking water,
air quality, and safe ty. In this case, safety refers to the degree to which
public well-being may be affected in the.event of a major accident such as
radiation leaks, fires, or terrorist attack on the facility.

(ii) Economic

Included in the economic section are those areas of the cultural environ-

ment related to the framework within which the human community functions: employ-
ment, housing, infrastructure, land value, and local economy.
Impacts on employment can be divided into short-term effects related to
the construction of a facility and any long-term effects due to increases or
decreases in the maintenance and operation staff. Other possible impacts on

employment are the indirect or multiplier effects associated with the increased
demand on related goods and services, and the decrease in employment associated
with new automated technologies.
Housing supply and demand in an area are directly affected by the influx

or workers associated with a construction project on the short term and permanent

staff on the long term. In order to meet housing requirements, this impact must.
be assessed during the planningstages.
Infrastructure refers to the existing transportation network, waste dis-
posal systems, utilities, and public services that are required for support of a
population in a given area. Changes in these requirements as a result of the
.development of an energy facility should be planned for and are thus included in

185

the impact assessment. Safety services in this section refer to police, medi-
cal, and fire services.
Land values may change as a result of energy facility development and
related activities. These land values are divided into residential, agricul-
tural, commercial, and industrial categories and are considered with regard to
their proximity to the proposed facility. In other words, it is possible that
residential land values adjacent to a proposed refinery would decrease for its
present use, whereas, the value of residential land somewhat removed from the
facility would increase due to added demand from added employees.
Finally, the local economy of an are a may be affected by a proposed
energy facility in terms of changes in governmental budgetary or fiscal effects,
and positive or negative impacts on local business activity.

(iii) Physical
Physical aspects of the cultural environment include the existing and
potential land and water uses assigned by humans to the natural environment.

Also included are the recreational values of the natural environment.

Land and water uses have been divided into wilderness-and open space,
wetlands, forests, grazing, agriculture, residential, commercial, industrial, and
designated lands -(i.e.,,state and federal-lands). Impacts of energy facility
development differ greatly depending on the existing land use-of the area under
consideration. This is exemplified in.the decision of whether to develop on
agricultural land, precluding further agricultural use of that land, or to
develop-on land already used by industry. The impacts on land use and potential
alterations in-land use are extremely important in an overall assessment of en-
vironmental impact.
Recreational value assigned to a natural area increases or decreases as
a result of an energy facility development. Such a change in value should be
recognized at the outset. Recreational categories include hunting, fishing,
boating, swimming, and camping..

(4) Application.
The material that follows provides a-general survey of the types of
natural and cultural impacts that may accompany the construction and operation
of a major new energy facility. Because it deals with general energy facility
types rather than with specifically proposed proj,ects, it cannot reach the level

186

of detail necessary in actual project evaluation.. It wi 11, however, focus atten-
tion on certain aspects of each ;acility type that should be addressed in such an

evaluation.

The matrices accompanying each discussion are@intended to be used as
guides in developing a facility siting evaluation process. As such, they can

be used in several ways. The activities and environments listed on the matrices
could be used as guidelines in developing the elements of such a process. In
addition, the matrices themselves could be used as a part of the evaluation pro-
cess. This could be done in one, or both, of two ways. They could be used by
the state site review agency.or agencies in evaluating specific energy facility
siting proposals. Alternatively, they could be used by utilities and companies
in developing reports on the environmental and economic impacts of their pro-
posed projects. Ideally, the stateagencies and the companies would use the
same framework to facilitate a more comprehensive and free-flowing procedure.
Before the analysis of major facility operation.impacts, there is a
general discussion of construction activity impacts common to all.

b. Ene y-Kacility Construction
Because most construction activities are common to all of.the facilities

considered here, discussion of their impacts has been grouped into this one sec-
tion. Where differences do exist, e.g., in period of construction, size of
labor force employed, and,overall project scale, they will be highlighted and
discussed separately. In general, power generating facilities of both types
require the longer time (7-10 years) and a larger labor force (peak of more than

2,000 persons) for construction than transshipment facilities, which require the
les s than 2 years and 100-200 persons. The discussion will first address
impacts to the natural environment and then examine cultural impacts.

(1) Natural Environment
Construction activities represent a major disruption of the local environ-
ment that can result in significant changes in the surrounding air and water
quality. While details as to what those impacts would be and how extensively
they would change the existing environment will vary from site to.site, a certain
amount of generalization is possible. In a report published by the EPA [5991,
three classes of construction-related pollutants were identified: sediment,
chemical, and biological. Of these, very little is known in a quantitative way

187

concerning chemical and biological pollutants. The! principal biological pol-

lutants are associated with poor sanitary conditions at the site as well as soil
organisms released through the physical disturbance of the earth. The major
chemical pollutants associated with construction activities are petroleum pro-
ducts (the largest group), pesticides, fertilizers, synthetic organic materials,
heavy metals, additives used to maintain, desirable, soil characteristics (includ-
ing lime, fly ash, asphalt, phosphoric acid, salt, and calcium chloride), and
construction chemicals (glues, solvents, sealants,.etc.)
Several studies have looked at the effect of construction activities on

erosion rates and sediment loads. One study in the Washington D.C. area found
that, while lands under natural conditions contributed sediment at a rate of
less than 70 metric tons/km2 /yr, land under development contributed 354 to
2
42,350 metric tons/km /yr [cited in 599]. Other studies have demonstrated simi-
lar results: a study in northern Virginia showed that constiuction activities
representing only 6 percent (72.5 ha) of the surface area of a watershed con
tributed 94 percent of the 33,500 metric tons of sediment transported from the
basin during a 3-4 year period of record [cited in 599].
.In a report prepared for the Atomic Industrial Forum [173], four phase s
in the:facility construction process were identified:
e Preconstruction--@-Those activities which closely follow site selection--,
including site inventory, environmental monitoring, and implementation of tem@-
porary impact controls.
a Site Work--Site clearing and construction of temporary buildings,-
access routes (roads, railroad spurs, and channels and docks) and associated

facilities.

e Permanent Facilities--Activities associated with construction of

facility components.
* Project Closeout--Removal of temporary buildings and final landscaping.

The principal pollutants and potenti al impacts associated with each are listed
r
in Table 17 [from 2031.

The distribution and magnitude of these impacts varies.with the type of
facility being constructed. For example, impacts on the aquatic ecosystem, par-
ticularly the benthos, might be greater in the development of a new fuel trans-
shipment.facility for which major harbor and channel modification may be neces-
sary. In similar fashion, water quality impacts stermiing from erosionof

188

TABLE 17 POTENTIAL ENVIRONMENTAL IMPACTS RESULTING FROM CONSTRUCTION PRACTICES

~@~'~@~a~s,~r~u~c~t~:~o~n~ ~?~@~@~S~e C~o~n~s~!r~-~_~,cti~o~n Practice ~r~i~n~a~. ~I~l~u~@~a~2~L~s P~ot-t~ial Environmental ~I~r~o~i~ct~@
a. Site ~i~n-to~r~y Sh~o~rt-t~e~r~n an~,~1 -~m~in~al
(1~) ~V~e~@~t~icul~@ traffic Dust. ~n~n~i~%~c~, ~se~4~i~r~e~nt Dust, s~ed~i~r-~it, and tree injury
(2) Test pits T- -.t ~I~n~j~ery, sediment
~b~. Env, ~r~c-ntal ~n~onit- visual if properly ~e~@r~i~e
-ring
T~c~q_~_~~r~.~'~-~Y ~Shc~r~t-t~e~r~.~ ~a~n~d
~0) ~S~-~o~r-z~e~r Ve~Z~et~ation, water, qu~, lity
(2) ~Er~es~i~.. ~F~. ~s~ed~i- ~S~e~d~i~m~rt~t 'Poll, nutrients, ~Vg ... ~t~i~.~n~. 'at- ~q~a~l~l~t~y
..lid waste
(3) ~q@~q@et~tat~i~v~e Fertilizers in excess
~j4~) ~t~1ust Negligible if properly done

~7. ~S~@~t~e ~'~n~.~;~' Cl~c~-~-~r~g ~n~e ~d~e~m.- Short~term
~l~iti.~n
(1) C~i~earin~g Decrease in the area of protective tree, shrub, and ground
Dust, sediment, noise, $.lid ~a~lt-. covers. stripping of topsoil; ~l~r~r~re~a~s~c~@ soil erosion, ~s~ed~l~i~m~en-
wood ~a~5t~e~s tat~i~on, ~and ~st~or~m-~t~er runoff-, increased s~ir- w~it~e-~, tempera-
t.~r.s; ~m~ed~l fi~c~at~i~o~@ of stream banks and channels, water ~qu~zlit~y
(2) Demolition Increased dust, n~o1a, solid wastes
b. T~e~.~,~p.-~r~y facilities Long-term
~(~1~) shop. ~& ~t ... ~g~e I~cr -d ~s~-Face -~3 i~-p~e~r~v~i... t~o water ~-filtration.
n
I"I ~J~s Gases, o~d~c~@~, f~e~r~i~e~s, particulates, ~I ~c~r~q:~a~s~e~d water runoff, petroleum products
(~2)~c~'~ma~ds ~&dust, deicing ch~e~.~@~Ical~s, noise Increased surface areas i~r~r~pemio~us to w~a~t-~r infiltration,
par~q!~kin~a lots p~etr~ol- products, waste waz~er, increased water runoff, generation of dust on unpaved ~ar~,~e~a~s
(3) Utility tr nch~es solid wastes, aerosols, pesticides Increased visual Impacts, soil erosion. a~n~d ~s~edi-t~at~i~on for
~& b~ack~f~,~I~I: short periods
(4) S~a~sitary fac~il~l- Increased visual impacts, solid wastes
ties
(5) ~re~n~z~e~s Barriers to animal migration
(6) L.y~d~.~v~s areas Visual ~i~@~act~s~. increased ru~s~off
(7) Concrete batch ~S~edi-nt, dust Increased visual impacts; disposal of wastewater~, Increased
plant dust and noise
~(~3~) ~~Z~c~c~?~o~q-~y ~a~n~d N~o~n-de~gra~iabl~e or slowly degradable pesticides ~a~r~e a~c~c~u~s,~ul~at~ed
pe-a~n-t pest by plants and animals, then passed up the food ~cha~i~n~.t~o ~m~on.
~c~?~n~tr~ol. ~(t~,r Degradable pesticides having short biological half-lives a~r~e
~.~1 te~s~. ~v~e~e~d~.~. prefer~r,ed for use
insect-%)

Earth ~pus~i, noise, sediment, debris, Long-term
1) E~. a-t~i~o~n wood wastes, ..lid waste., p.~sti- Stripping, soil stockpiling, and site grading; increased ~er~os-
(2)Grad ~n~g ~c~i~de~s, particulates, bituminous ion, sedimentation, and runoff, soil compaction; Increased In
3) Tr~-~eh~*~,~.~,~, pm~d~ucts, soil conditioner c~hemi- soil level- of potentially hazardous materials; side effects an
4) ~S~@~1~1 treat ... ~t~c~a~l~s living plants and animals, and the ~I~nc~orpo~r~a~l~on ~o~f dec~on~p~o~s~i-
ti~o~n products into food chains, water quality
~d. Site ~d~r~a~ina~i~e Long-term
(~1) ~F-~@~.~t ~i~o~n Decrease in th~e volume of underground water ~f~o~,- short and long
~era~'~.'~n~a~&~e time periods, ~i~s~cr~ea~sed stream flow ~vol~u~i~e~s and ~v~elo~c~@~it~l~cs,
(2)
~-~e-t~eri~ng Sediment downstream damages, water quality
(3)~,~-~.~@~1~1 points
(~4) ~St-~c~' c~n~a~n~n~el
r~e~@~l~oc~at~i~o~,~q
~r. L~. ~n~e. ~3-~g~i~n~;
-~@~p~o~r-~y Decreased soil erosion and overland flow of ~5~t~or- ~at~er.
~q!e~e~d~i~n~g Nutrients~, ~pet~i~c~i~d~- stabilization o~f exposed cut and fill slop- ~, increased water
(2) ~e~r-~e~nt infiltration and underground storage of ~t~a~-~e~r~, ~mi~n~i~m~,~*~?~e visual
~a~n~d impacts
~.~.~J~d~i~n~g

3. F~a,~-~'~I~;~@ ~I~L-~s ~t L~o~r~Z-term
heavy tr~.~ff~ic a- ~S~ed~l~e-~e~n-, dust, ~roise,
larking lots p~ar~t~icu~l~'t~e~s Sto-~,_~water runoff, p~etr~o~le= products
~S~'~i~t~c~h~y~'~r~d Visual impacts, sediment, runoff
~D)~-~.~;~l~r-~d spur ~l~i- Sto~rmw~a~t- runoff
~b. Bull ~@ ~i ~n~g~@ Long-~t~em
(I)~W~.r~eh~ou~ses 1~,~p~e~r~l~,~i... surfaces, ~st~or~r~@at~er runoff, solid wastes, spillages
(2) ~S~.-~i~t-~7 Solid ~.~2~s~t~e~s Odors. discharges, bacteria, viruses
tr t~c~a~nt
(3) C~oolir~,~, t~.~-~w-~s ~V~i .. I ~i~'~p~.~c~t~@
c. Related facilities L~o~@~&-t-
~(~1) Re ~a~c, ~i~nt~A~c~k~e~S Shoreline changes, bottom topography ch~a~i~g~es, fish ~m~i~gr,~i~t~i~o~n~,
~e~i~-h-~g~e ~b~"~'~t~h~i~c ~f~.~u~r~a changes
(~2) ~i~1a~t~e~r -p~p~ly ~f~. Waste discharges, water quality
t~'~e~-t~- ~t
(3) ~S~t~c~q-at~.~r dr.~:~n~- Sediment, water ~q-~I~itY
Sediment, trace e~l~er~l~e~nt~s~, noise.
~V~i~st-~a~-~er tr-t- ~cau~st~,~c chemical wastes, ~s~e~di~r~e~at Sediment, water quality, trace ~el-~e~nts
~cen~'~, spoil, ~f~l~o~c~c~u~l~l~st~s~, Particulates,
~P~,~,~,
(5) -~.~1~. ~i~@~.~T~o-~'~!~- fur ... .lid wastes Dredging, shoreline erosion
cents
~(~6) Circulation p~att~em~s in t~he w~a~z~e~r~wa~y
~j~e~tt~i~.~.~'
(7) Fuel han~,~@~I~iZ Spill.~Z~e.~, fire, ~a~nd visual impact.
~q
(~S) ~0~:1 ~'t ... ~@~e ~t~-~k~" Visual impact.
~"o ~n~t~'~.~I~s~' ~& ~p~i~;~i~,~!~g
~(~9~) Conveying ~sys~t- Visual impacts
(~qcr~qane~qi~q, ~qfo~q@~qs~q@~qs.
chutes)

~q(~q1~q0~q) Waste ~qh~q.~q'~qd~ql~qi~qr~qg Noise,, a~qn~qd Visual i~qm~qj~q@-~qtS

e-~q-.~q,~q.. ~qw~qr~qo~q@
c~qn~qi~qp~qp-~q, t-h

~qd. ~qS~qe~qc~q-~qi~qt~qy ~qf~qe-~qi~qn~qg L~qo~qn~qg-t~qe~4q-
(1) ~qk-~qe- road S~qe~qd~qi-t~q@~q, wood ~qw-t~q@~qs ~qJ-r~qv~qa~qs~qed runoff
(2) ~qT~qe~qnr~qi~qn~qg Barrie~q- t~qo animal ~qm~qo~qv-~qt~q,

~qP~qT~q'~qJ~qecz C~ql-~qe-~qt ~qo~qf t~q'~q@~qP--~qY ~qSh~q.~qr~qt~q-~qt~qe~ql-
offices ~q& ~qs~qh~qc~qp~q@
(~q1) Noise. dust, solid -~qst~qe~qs ~qN~qo~qi~qs~q'~qs~q. solid waste, dust
(2) St~qo-~qat-, r~qe~qso~qff, traffic blockages, soil c~qo~qr~q;~q@a~qc~qt~qi~qo~qn
~qb. Site r~qe ~qst.-t~qi~qon Short-term
(~q1)~qF~qi~qn~qi~qs~qh ~qg~qr~qa~q3~qi~qn~qg Sediment, dust .~q,~q'~qI
~q(~q2~q) ~qT~qo~qp~qs~qo~qi~ql~qi~qn~qg. ~qS~q'~qd~qi~qn~qe~q.~qt ~q, ~qd~q"~q'~qt Erosion, ~qs~qc~qdi~q,~,~q,~q.~q-~qnt
(3) ~qVutr~qi~qent runoff, wat- quality
~q0) ~qS~q@d~qi~qr~qe~qn~q- ~q-~qn~qt-~ql~qs ~qV~qe~qg~qe~qt~qa~qt~qi~q.~qh
~qt~q. Preliminary ~qs~qt~qa~qr~qt~q-~qe~q? ~qS~qhrt-t-
~q(~q1~q) ~qc~ql~qe-~qi~qn~qg ~qNu~qc~qt~qi~qen~qt~qr, petroleum products water quality, .!Is, phosphate and ~qct~qb~qtr nutrients
(~q2) Flash~q.
~q.~qr~qg
203~2q1

189

excavated and cleared soil might be greatest for a nuclear facility construction
site because of the longer construction periods involved. The impacts associated
with a given construction activity must be evaluated in light of thespecific
conditions of the site under consideration and the actions proposed by the
developer. A list of factors having a bearing on these impacts include:
Resistance of the surface and subsurface soils to erosion by gravity,
water, and wind

0 Chemical and physical properties of the soils and parent materials
Topography and size of the jobsite
Distribution and frequency of rainfall
Care used in trapping sediment and collecting liquid wastes
e Area and time duration of exposure of cleared and excavated portions
of-the jobsite
s Number of people and machines linked with each jobsite at successive
stages of the construction effort [173; p.41.

(2) Cultural'Environment
The impacts of construction on the cultural environment in the -vicinity
of a proposed energy.facility can be severe as evidenced in the Alaskan Pipe@
line experience. While it is unlikely that impacts of such magnitude would be
,experienced in the Great Lakes Region, certain elements of development-induced
cultural system change must-be considered.
Tables 18 through 21 present employment profiles for each of the facility
types considered. The different facility types show considerable variation in
terms of construction time, peak construction employment, and operating employ-
ment requirements. Because of its small construction manpower requirements, it
is not likely that the development of a new fuel transshipment facility would
cause any significant cultural system impacts. On the other hand, the large
work forces and relatively long construction periods with.high levels of.employ-
ment for power plants and refineries create the,potential for some local social
impact. The magnitude of this impact depends on existing socioeconomic condi-
tions and.must be evaluted on a case-by-case basis.
Cultural impacts during the.construction and pre-operational stages of
major facilties development arise from three major sources: influx of a large
construction work force, the movement of construction materials through the

190

TABLE 18

WORK FORCE PROF11LE: NUCLEAR POWER PLANTS

P R 0 P 0 S E D P -0 W E R P L A N 7 1 N F 0 R M A T 1 0 N HYPOTHETICAL
AVERAGE
812 lefonte McGuire River Bend Susquehanna
(24 30HWe) (2360MWe) (1870HWe) (21OOMWe) (220OMWe)
Year ConstructionjOperation- Construction Operation Construction Operation Cons truction Operation Construction Operation

1. 850 0 850 100 0 300 0 418 0

2 1500 0 1537 0 350 0 '1800 0 1232 0

3 2150 0 1810 0 1200 0 2300 0 1980 0

4 2240 30 1634 0 2100 0 2500 0 2200 0

5 1660 155 950 30 2000 0 2400 0 1914 0

6 630 170 200 170 1650 0 1500 0 1254 35

7 0 170 0 200 1000 30 800 0 396 105

8 0 170 0 200 300 70 250 20 0 140

9 0 170 0 200 0 100 100, 60 0 140

10+ 0 170 0 200 0 100 0 77 0 140

(390]

TABLE 19

WORK FORCE PROFILE: FOSSIL FUEL (COAL) POWER PLANTS

P R 0 P 0 S E D P 0 W E R. P L A N T I N F 0 R M A T 1 0 N BECHTEL 3
Colstrip 3 & 4 Tombigbee 2 & 3 Pleasant Prairie 1 & 2 2' ESTIMATES
(70OMWe) (420MWe) (1234MWe) (80OMWe)
Year Construction Operation Construction Operation Construction Operation Construction Operation

1 270 0 180 0 48 0 40 0
2 1418 0 972 0 155 0 420 0

3 1418 0 972 0 566 0 864 0

4 270 173 180 112 1131 0 814 0

5 0 693 0 450 578 0 360 109

6 0 693 0 450 845 0 0 109

7 0 693 0 450 81 120 0 109

8+ 0 693 0 450 0 120 0 109

[3901
2[573), Unit 1 completed in year 5, Unit 2 in year 7.
3[5411, probable error less than 25%.

191

TABLE 20

WORK FORCE PROFILE: REFINERIES

1 3
.250 MBD 200 MBD
Low Fuel Oil High Fuel Oil Low Fuel Oil
1 2 1 2
Year. Construction Operation Construction Operation Construction Operation

1 2180 0 1800 0 521 0

2 2180 0 1800 0 2536 0

3 2180 0 1800 0 3272 0

4 0 435 0 410 1257 0

5+ 0 435 0 410 0 551

1 [5061
2 [505]

3
[541], probable error generally less than 25%.

TABLE 21

WORK FORCE PROFILE: FUEL TRANSSHIPMENT FACILITIES

C 0 A L 0 1 L

1 2 3
Superior, Wisconsin Marquette, Michigan Superior,, Wisconsin
(8 million tons/yr) (12 million tons/yr) (6.2 million.barrels/yr)

Construction Period
(months) 20 12 12

@Construction
Employment 100 150 2010
-@Operating
4
Employment 50 2 8 12

1 [3911
.2 [2991
3 [158]
4 Based on operator time requirements.

192

local area, and the presence of the facility itself. Of these, the potential
for the greatest cultural system damage is associated with the first, while the
greatest potential benefits stem from the third. Ofcourse, the magnitudes of
,the costs and benefits associated with each will vary from case to case.

(a) Influx of work force

For a construction project of the magnitude considered here, there will
be 1,000-3,000 workers employed at the site for periods of up to five years. It
is doubtful that a mix of the skilled tradesmen in the quantities required could
be found locally unless the site were near a major metropolitan area. In other
cases, a large fraction of the work.force would have to come in from outside of
the local area and either commute (daily or for the week days, leaving on week-
ends) or move into the local area for the duration of the project. Construction
workers generally are. willing to commute long distances to job sites, with
50-100 miles each way not uncommon [4511. Figure 14 shows those areas within 75
miles of major metropolitan areas (SMSAs with 1970 populations of 500,000 per-
sons or more) in.the Basin where daily commuting may be possible for a large

portion of the work force. . While it may not present a complete picture of
"local work force availability," Figure 14 does at least indicate that the south-
ern, more heavily developed portion of the Basin may generally be less suscepti-
ble to the types of impacts associated with heavy in-migrations of construction

workers.

The reader is cautioned about drawing conclusions from Figure 14 and the
brief dicussion of it that go beyond the material presented. In reality, the
problem of a commuting versus transient resident'work force is much more complex,
depending,on many factors, some site-dependent, others supralocal. One factor
that must be considered is the attractiveness of the site community in terms of
inducing workers.to move from their present locations to the local area. For
example, if the workers were being drawn primarily.from large metropolitan
areas of great cultural diversity (shopping, entertainment, recreation, schools,
etc.) that a rural job site could not offer, then it might be that those that
could commute would do so. If however, the site were in an area similar to those

7@-
For the purpose of this discussion, the physical presence of the facility it-
self, regardless of its operational status, will be considered under construction
impacts. Impact's and residuals stemming directly from-the operation of the plant
are discussed in later sections.

Cq"
0

MINNESOTA c

LAKE SUPERIOR

th STA
z supeno, ONTARIO
20 X,

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MICHIqAN----

Wis.

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R." I 11A Y

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WISCON N LAKE HURON
A. S&.&&
Cleo ".."w
Bay

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194

in which the potential work force lived at present, there may be more in-migra-

tion to the local community.

Another factor is that the contractor and subcontractors may bring a
portion of the labor force in with them, especially for the managerial and
highly skilled engineering positions [4511. Thus, if non-local construction
firms were used, it is likely that at least a portion of the work force would
be brought in form outside of the area.
Labor union practices are also important in determining the geographic
origin of the construction work force [451]. How jobs are distributed to mem-
be@7s of the various.craft locals'will influence the mix of commuting versus

resident workers:

It was found to be a general rule that the location of the
union had much to do with the housing and commuting patterns
of the work force. For instance...more people commuted to the
job site from Leominster and Fitchburg [Massachusetts], a dis-
tance of roughly one hour by good road, than might have been
expected. The cause of the heavy commuting was the fact that
mose of the-carpenters working on the site were from the
Fitchburg7Leominster area [and] nearly all the field employees
commuting from that area were, and are, carpenters [451; p.175].

Another factor that should be considered is the condition of the local

(i.e, commuting) construction labor market. If unemployment among the skilled
trades is high, then more local commuting might be expected. If, on the,other
hand the available labor force is fully employed, then immigration from other
regionS may provide a large percentage of the needed workers.

There are three patterns of work force entry to th e local area: daily
commuting, Monday-Friday commuting (where the worker stays in the area during
the week and travels to a permanent home over the weekend), and relocation to
the local area for the duration of the project. In general, the first case, a
daily commuting force, "generates minimal fiscal, social, or political impacts
on. a host community" [hypothesis advanced in 600]. In a study of the cultural
system impacts of two nuclear facility construction projects (Pilgrim I in
Plymouth, Massachusetts and Millstone I in Waterford, Connecticut) in which
daily commuting was common, the following conclusions were drawn:
Social, political, and economic impacts upon the towns of
Waterford and Plymouth during construction of their respec-
tive nuclear plants have been minimal. The only impact of
any magnitude identified retrospectively is construction
worker traffic.

195

Most construction workers in the case of Pilgrim I and
Millstone I and II commuted t o the site from their
existing place of residence within the metropolitan
areas rather than relocate closer to the site or,within the
host community. As a result, little impact on commercial
activity was noted in either community during construction.

In both Plymouth and Waterford, little interaction took
place between construction worker crews and local towns-
people. What interaction did take place was primarily
in local grocery stores and taverns.

Speeding by construction workers appeared to be a problem
in Waterford and Plymouth. In Waterford, a police officer
had to'be stationed at the entrance to the construction site
each night in order to control speeding onto secondary
town roads [600; pp.9-.10].

In the case of Monday-Friday commuting by the project workers, the poten-
tial impacts may be somewhat-more important, depending on local socio-economic
conditions. During the week, the workers would require housing, food,, and recre-
ation. in the local area. However, they would probably not spend a large portion
of their wages locally, preferring instead to send most of it to their families
for living expenses elsewhere. This means that service industry requirements
would be minimal. Also,'because the workers do not relocate their families into
the local area:, impa:cts on the schools and other family-rela.ted systems would be
insignificant.
This is not to say, however, that Monday-Friday commuters may not-cause
significant local impacts. The 'need for housing,.especially of a "boarding
house" type, for@'the workers during theweek may cause changes in the local
housing mix and price structure. Conversions of large single dwellings into
Existing
multiple units may increase availability to offset this demand.

rental housing may be diverted away from those who would normally rent it as
well. Rents may rise as the demand increases, especially as local landlords see
an opportunity to increase profits at the expense of the construction workers
(whose median income may be considerably higher than the local norm). Because
of this, low-income residents of"the area may be forced into lower quality
housing than they could afford prior to the project. Finally, the housing mix
established as a re'sponse to the project will exist a .fter.construction has
ceased, which may leave the local communities'with an overabundance of poor

A secondary impact may be an increase in building code violations and the'need
for an expanded inspection and enforcement program.

196

quality rental units [451]. Also, rents may fall once the work force leaves the
area, causing significant local income effects.

,There will also be impacts felt in other sectors of the local economy.

Food sales may increase, both at markets and restaurants and cafes. Tavern and
bar sales may also increase [451]. As in the case of housing, market demand-
response expansion and inflation may occur in these areas during the construction-
period followed by a sharp decline once the project ends. It is not likely that
there would be significant increases in the durable goods market.
There are, of course, many factors operating to mitigate these potential
problems. For one, the magnitude of these problems will depend on the local
economic and social structure. It would be reasonable to assume that, in general,
a large metropolitan area would be better able to absorb the work force without
significant change than would a rural town or small city. Care must be taken not
to over generalize, however, and to examine the economy of the proposed site
localities in-detail to determine how important these effects might be. For
example, the impacts, particularly with respect to housing, may be considerably

less in areas oriented to a seasonal tourist economy, where excess capacity may
be available for rent. Also, areas with stagnant or declining populations may
have an' excess supply of housing available and, thus, be more able to absorb

the influx of workers.

In addition, the construction workers may not locate in one area but
rather, spread out into surrounding localties. This avoids a concentration of
the impacts of this phase (subject to the qualifications discussed with respect
to local fiscal effects below).
In some cases, a substantial portion of the work force may relocate into
the locality of the project. The impacts of such an immigration can be signifi-
cant, subject to the caveats discussed above. Demand for housing in this case
will be shifted away from the "boarding house" market, into family dwellings.
This may cause a decrease in availability of rental units and a limited increase
in new home starts. An important source of housing for construction worker
families is the mobile home sector [4511. Because rapid development of mobile

home.parks can bring problems with public service support and conflict with
existing residents (especially in areas of limited experience with this form of

Owners may also prefer to rent to construction workers on a Year-round basis,
rather than depend on temporary tourist occupancy.

197

housing), the expansion of these facilities should be carefully planned and inte-
grated into the local system.
An overview of the local response to the demand for new.housing has been

summarized as follows:

Recent population trends and the. age structure of the local
population are important: in an area which is stagnant or
declining in population, and which has, relatively few younger
people, rooms or larger parts of existing houses may be in
great supply and obviate the need for other sources. An area
which is growing rapidly and has many young families is more
likely to meet some demand with Permanent housing, because
such housing is likely to be saleable or rentable after con-
struction ceases.

The availability of sites for mobile home Parks, the import-
ance of tourism (and, thus, the abundance of motels and inns),
and the attitudes of owners toward conversion and renting
space to strangers are all relevant factors. The general
amenities'and quality of public services will also influence
choices of workers, especially those bringing 'families.
Thus, the sources of supply of housing which are easily
expanded in particularly favored communities will weigh
heavily in determining the mix for the whole region [451; p.179].

In addition to demand for new housing and associated services, there will
also be a general increase in local business activity. As in the case of the
weekend commuting, food and food service sales will increase, although to a
greater extent in this instance. There will also.be increases in other sectors,,
including both durables and nondurables as family-oriented demand rises.
As a net result, more of the c6nsturction payroll will be spent locally,
'generating secondary income benefits. The size of this income multiplier effect,
,as it is called, is determined primarily by two important factors,.the marginal
propensity to spend locally (c), and the fraction of sales that becomes local
income (h). The general formula is:

multiplier 1
1-(c)(h)

The larger the value of the multiplier, the greater the secondary income benefits.
The marginal propensity to spend locally is simply the fraction of total
income spent on locally provided goods and services. As such, it depends on the.

This concise explanation of a potentially complex concept is taken from
reference 451.

198

.mix of goods available locally, relative prices between local and imported goods,
the availability of imports, and the type of goods and services desired.
Finally, movement of families into alocality for the,term of the pro-
ject could have impacts on other services, such as schools, sewers, health care,

police, churches, etc. The school,system especially could be adversely affected,
as enrollment increases, but only for a short period (2-7 years). Because the
crowding is only temporary, new additions may not be warranted. This does, of
course, depend on the enrollment in the system relative to capacity before the
project begins.

(b) Movement of material through the local area

In addition to a movement of workers,to the site of a new energy facility
there is also a large-scale movement of material:
All plants require substantial amounts of materials to be
moved to the plant site. The most important of these are
the concrete required for build 'ings and dams; steel for.
concrete reinforcing and for structural frameworks; and
large pieces of equipment, such as turbines, parts of
boilers, pipes, etc. These materials can be moved to the
construction site by any one of three ways, by truck, by
rail, or by barge, depending upon how accessible the site
is to each of the modes and where the materials are being
shipped from. In general, the greater the dependence on
highway transportation, the greater the impact on the
surrounding communities [451; p.130].*

The major transportation-related problems are local system congestion
(both by worker traffic and material delivery to the site), increased risk of
accidents, and deterioration of the roadbed, curbs, and bridges.
There may also be local improvements to the transportation system brought
about by the project. For.example, relocation and improvement of existing road-
ways could provide improved access for the local residents after the construction
period has ended.
Related to the movement of construction materials through the local area
is the local purchase of materials to be used at the site. If the area is
highly industrialized and produces'structural steel, piping, equipment, or other
materials, then a significant share may be bought locally. However, if the area
is rural with little heavy industry, then the locally purchased material will

See diszussion of Transportation Access Requirements indescription of,nuclear
power plants.

199

most likely be limited to sand aZd gravel.

(c) Impacts of the facility's presence
The presence of a major new energy,facility, even prior to its operation,
can produce significant changes in'the local socioeconomic system. One of,the
most obvious of these impacts is the addition to the.local tax base. IA new
facility valued at several hundred million to more than one billiondollars will
pay several million dollars per year in property taxes upon completion. Assum--

ing that total tax revenue to the local jurisdictions remains constant, this
would mean a tax reduction for all other property owners. 'The size of this re-
duction depends, of course, on the tax value of the plant relative to the total
local tax base. Figure 15 illustrates the range of.effects that a new plant
might have on the tax rate as its share of the tax base changes.

FIGURE 15

EFFECT OF A MAJOR NEW FACILITY

ON THE LOCAL TAX BASE

E-1 10 0

ILI

a L, 0

.........
10 50 100 150
Plant tax value as proportion of origirc.1 tax base

[Source 451]

It will also produce property tax revenue throughout the period.of construction
in proportion "to the total amount expendedby the utility oninvestment to
date" [451; p.1941.

200

In a case study of two towns within which nuclear generating plants pro-
vided 50-60 percent of the local tax base, workers from Oak Ridge National Labo-
ratory found the following:
The majorimpact of the nuclear plant in both Plymouth and Waterford
is the large increase in tax base provided by the operating reactor.

One option chosen by both communities has been to lower (or stabi-
liz6) the existing tax rates while currently using the additional
revenues to significantly increase public services and facilities.

Both communities have taken some steps to professionalize adminis-
tration of services through hiring,new staff and creating some new
positions in local government. In'both communities, new depart-
ments of public works have been established and town planners.
have been hired to control future land use development. In
Plymouth' a town manager has been hired to oversee local
affairs [600; p.10].

In addition, to direct tax benefits from the new facility, there will be

some secondary tax revenue gains. For example, new housing for construction and
operating employees will expand the facility tax base. Also, market value of
commercial property may increase in expectation of higher profits [451]. Finally,
there may be added benefits in cases where local communities can levy sales and
income taxes, especially during the construction period.
These benefits do not accrue without offsetting costs, however. The Oak
Ridge study cited above also has identified a number of problems created by the

new facilities:

External relationships of the two communities have been altered
by the presence of the nuclear power plant, principally because
of the augmented tax base., The presence of the nuclear power
plant may create new tensions or exacerbate existing tensions.

Efforts have been initiated in both states to redistribute the
utility tax payments so that a larger proportion will go to
other jurisdictions and/or the state.

Neighboring towns have, in varying degrees, become resentful
or antagonistic over the favored'status and resources of the host
communitIy. The transportation of nuclear waste.through neighbor-
ing towns in both Plymouth and Waterford has caused some concern
and hasIresulted in challenge of the legality of the transfer of
that waste.

The sudden population growth occurring in Plymouth since 1968
(the beginning of the nuclear plant construction) was intensi-
fied by construction and operation of Pilgrim I, but growth
would have occurred soon because of regional growth patterns

201

and proximity t1o.Boston. Growth was one consequence of the low-
ered tax rate in Plymouth t600; pp.11-121.

While these conclusions are-based on the study of a specific situation,
they do highlight a problem that may be true in the general case.. That is,
while tax revenue (especially property tax revenues) generated by the facility
accrues primarily to the host,jursidiction, the costs may be shared with several
surrounding communities.
There are other problems related to local fiscal effects as well. For
example, the actual assessment and taxing procedure may be very complex, causing
problems for-local officials. There are sometimes.problems with deciding what

portion of the'facility is taxable, how to tax transmission line easements, how
the presence.of the plant or.constrluction activities affect neighboring property
values, etc. [451]. Resolution of problems such as these may be beyond the
capability of local.administrators.
Another problem is that plannning and implementation of programs to miti-
gate adverse impacts, especially during the construction phase,.must be done
before the project begins...Tax revenue to finance these programs, however, is
notavailable until after construction has begun (see Table 22). This lag
effect can produce dislocations in thelocal fiscal picture.

TABLE 22

TAX PAYMENTS DURING CONSTRUCTION

OF THE JIM BRIDGER POWER PLANT

Tax Year Property Taxes
1972 $ 37,000
1973 490,000
1974 1,285,000
1975 3,000,000
19716 4,000,000
1977+ 5,000,000

[Source 451]

202

Another source of monetary benefits is the interst paid on the bonds to
construct the facility. However, it is likely that these monies will be spread
out among a large group outside of the local area and, hence, will riot add direct-
ly to local income.

In addition to monetary costs and benefits, the presence of a large
energy facility will have other impacts of both a local and regional scale. In
many cases, at"least a portion of the land used for such a facility will be
unavailable for other uses for at least 30-40 years. The long-term commitment
of a site of the size considered here (range of 300 to approximately 3,000 acres)
will affect development patterns on a local and,, perhaps, a regional scale. In
addition, potential uses displaced by the facility must be considered, especially
in terms of alternative sites available to them. This analysis should also in-

clude possible.uses of water resources that may be preempted in the long term.
Related to this is the problem of potential land use conflicts that may
arise, both in terms of existing development patterns and future changes. A
large facility does not exist in a vacuum and must be related to the socio-
economic matrix within which it is located. Included in this is the problem of

aesthetic disruption and visual intrusions which may be considered to be a
measure of harmony between human artifacts and the existing environment. Natural
draft cooling towers, tall stacks, and large distillation and cracking-towers
can significantly degrade the quality of. surrounding environment.

M Summary

The evaluation of facility impacts during the construction and pre-
operational stages is a complex and confusing task. The discussion presented
above covered only part of the picture, giving major highlights without filling
in the many gaps and details needed to do a complete analysis. Table 2.3 presents
a list of potential construction phase problems. Used in conjunction with the
facility activity impact matrices, it should present at least a starting point
in evaluating the cultural impacts engendered in the construction of a new
facility.

C. Operating Impacts
The major impacts caused by the operation and maintenance of a large
energy facility are related to the production,,storage, and release of residuals
to the water, air, and land. In contrast to the construction phase impacts

TABLE 23

CONSTRUCTION IMPACT SUMMARY

IDENTIFICATION OF POTENTI,L I DEN T IF I C f-T 1 CN Ot
ITEM OF COMMUNITY FUNCTION PRIMARY CONDITION CHAtGES, VAJOR ENVIR0NMLNrAL
ACTIVITY AC71VITY PRACTICE, OR VALUE NUISANCES, AND BENEI`I@S A!.D SCCICIECONOMIC IMPACIS

I Wcrk Force A . Services I Lodg i ng CHANGES I N :Ne ed fo r ho@s i s co Sc hoo 1 s ; r,! o t i L, s o
2 Transportation @'ater s@ppl Y, medical, F"st.1 an of "z' t@ ..':n 1, , p I a "d
3- Schools & churches police 3ervi ces. old QpL- spasc. F1 c '-s'
4. Lit i I I t I es Q f r. e ; I n
5 M e d i c a I N U I SA N C E S Disposal of garb2-.e solid creastj tr._-@fi c 1 c d s
6 Police & fire wa s t e s , in @ ieased peak traffi c 1 n a @ E , a.- d
7. Recreational overloading o f t e I ephon.e s y s
8. Commerical
9. Postal BE [email protected] I TS : Increased taxes and -a-..e for
pub I i @ u t ; I ities; exp2rsion,of -@c . c31
services, postal, and food s- ice@

B. Social Aspects I Labor force C HAN G E.S - 1 N ;Mix cfprofessic@a 1 a 7. Pe I o c'@ i o n c. f h @'Ic I n d
2 E, p I oy"'e t technical workers, infl ux of sk iI led prop-rty; ir.c-azed -ipluy-
3. Cultural patterns labor, family life pressures. me l t ol;@ o I u.. i L

N 't I S AN C E S :Population d c n s Lt y , p r,2 @ s u . a
on xtx i s t ing local wage rates, re 1 cra t 7 on
of homes, and changes - proper*ly c@@ers!hip.

3 ENE F I TS :Increased emplcy;@tnt o@Dort r.
ties for skilled and un5kil?ed @c,',ers.

I I - Ove@ ra I I A. Business 1. Agricultural '.@iANGES - IN: Size of certain @is ;r,c@s es-,=@- Dernand for
Development 2. Commercial li5hmerts ; land use, zoning -I sewera;e a-1 roe.
3. Industrial ordinances; demand for recreazion, e.n:ertain-
4. Miaeral ment, and other lesiure-time activ:-ies.
5. Forestry
6. Recreational NUISANCES: Periodic crowding of cormerc ia I IQ
Tarking areas, picnic, and recreationil
areas ; solid waste d isposal, sedimer@t and
the@ pollULants rel ated to ne-@ bisiness
construction.

BENEFITS: Increased spending for food,
drugs, heating fuel, gasoline, lu ber,
leisure time activities, and rentals.

B. Aesthet ics and Scenic views CHANGES IN: Accessibility and relative Pu@lic attitud@s--@
Human Interest 2. Wilderness areas I
security of wilderness areas, [email protected], 'istcr'c cc,flic"-
3- Unique physical features and rare and unique species.
4. Parks and reservoirs
5. Open space NU ISANCES: Visual pollutior. , e,-.o t ; oi a I
6. Moniments and c Iashes, adversary ercouniers; litication,
landmarks tlme delays due to public opposit;cn
7. Rare and unique species
of plants, mammals, BENEFITS: Public discussion and deci-ic,n
& birds making.
8. H i storical and archaeo-
10 9 1 C a I

C . Transportation I . Truck and rail deliveries CHANGES IN: Traffic volume, required fuel
.of heavy equipment and suppl ie;,-.
construction materials
2. Heavy construction equipimen t ".LS _AY@�_@_ Increased den,ands an locals to
provide fuels and lubricants: load 1 1 m ; t son
roads and small bridges necessizazina @eli ve r v
route changes; low underpasses req-r;r9
alternate highway and railroad ro,;Les : eve r-
sized loads causing tree dara@e: increzcedl
noise and exhaust emissions.

BENEFITS: Ne. bridges and/or rcads to
Tate ;:,creased load weights, creazicri of
docking and rail-head utiloadirci f@scilities,
increased job opportunities for locals to
provide fuels and road and vehicle rainten-
Ance

[Source 173]

204

which are primarily related to the cultural environment, those produced by plant
operations ten&-to be more closely tied to the natural environment. This is not

to say, however, that they do not affect the cultural system, but rather that
their impacts are generally channeled through the natural system. For example,
changes in air quality caused by plant emissions could lead to public health

problems and reductions in land values close to the plant site.
In many cases, the linkages between these natural system changes'and
resultant changes in the cultural system are poorly understood. Th s is es Ipe-
cially true where those changes require long periods of time to accumulate and

become measurable. As a result, a discussion of the environmental impacts caused

by facility operation must deal primarily with identifying the residuals produced

rather than the effects of those residuals on the natural and cultural

environments.

(1) Fossil Fuel (Coal-Fired) Power Plants
.Table 24 presents a general summary of the types of impacts associated
with the major activities in the power generation fuel cycle, while Figure 16
diagrams the major impacts specifically related to the operation ofla coal-fired
power plant. The discussion below is organized by major activity types as de-
fined previously and shown in Figure 16. For a discussion of the impacts related
to fuel transshipment and storage, the reader is referred to the section on Coal
Transshipment and Storage Facilities.

(a) Plant operation
Table 25 presents estimates of the air-borne effluents produced by a
1,000-MWe plant both with and without emission controls. While this type of
information may not indicate the effect of these emissions on the environment,
it does at least provide guidelines as to the scale of the.problem.
The impacts and interactions of these air-borne residuals on t he environ-

ment are generally not understood at this time., Of the major pollutants listed
in Table 25, the one most easily controlled at present is particulate matter.
Current control technology allows collection efficiencies greater than 99 percent
[546, 2222 451, and others]. For this reason, the most visible effects of

The entire fuel cycle has been included here to provide the reader with a
broad perspective of the impact picture. Only those activities directly related
to this report are discussed further.

TABLE 24

SUMMARY OF FUEL CYCLE IMPACTS

FUEL CYCLE ACTIVITY WATER AIR LAND BIOTA

Extraction siltation, pH particulate emissions soil erosion disruption of habitat
changes altered successional
patterns, toxic
compounds, radiological
@iMpaCL
Transport accidental particulate and' right-of-way disruption ot habitat
releases gaseous emissions, toxic compounds
radiological impact
Preparation effluants, particulate and solid .4astes, disruption of habitat
heat rejection gaseous emissions, physical plant toxic compounds
U1
heat rejection siting radiological impact
*Conversion tberma. 1 particulate and solid wastes, disruption of habitat
dischar ges, gaseous emissions physical plant toxic compo-unds,
toxic compounds siting radiological impact
consumptive water use
*Transmission right-of-way alteration of
maintenance habitat, disruption of
landscape homogeniety,
biocides
*Disposal heat rejection gaseous emissions, dedication of releases of toxicants,
heat rejection repository land @radiological impact

Discussed further in text

[Source - 501]

206

FIGURE 16

DIAGRAMATIC SUMIJARY OF
COAL-FIRED POWER PLA14T ENVIRONMENTAL IMPACTS

Coal filosaga
at the Plant

rw.twdi..m. d..Ud.

Who, -HC

Air - H,O
' FW
convemion
Plant

. . .... wl.n

0 i$110sal of Ash
and Solid Wastes

f A ... . .. P-6-]

Wid.

WO Dry
Cooling I cooling co.liml,
Pond To-.r Tower

dt-5- ... ....
-.d @Wl.
Coal
a. "a Plant
.d @...d.

[Source 501]

TABLE 25

SUMMARY OF COALrFIRED POWER PLANT AIR EMISSIONS

Nitrogen Sulfur
Primary Particulates Thermal Solid
Description oxides Oxides (103 tons) (1 012 Btu's) (103 tons)
Efficiency (103 tons) (103 tons)

i Coal: Conventional steam
No controls 38 21.8 119.2 48.5 31.1 298

Eastern Coal: Conventional'
Boiler with wet limestone
scrubbing 35 19.2 16.0 3.2 0 955

Eastern Coal: Conventional
Boiler with magnesium oxide
scrubbing 35 191.2 16.0 3.2 0 410

0
western Coal: Conventional
Boiler with wet limestone
scrubbing 35 25.0 5.1 2.2 0 487

Physically Cleaned Eastern
Coal: Conventional Boiler
with wet limestone scrubbing 35 17.6 6.4 1.4 0 417
Coal: Steam plant with controls 38 23.2 19.1 2.6 .0 1,009

Based on data developed by Hittman [400 and 401]
2 Based on data from Battelle [545]

208

particulate emissions, thick, dark smoke, and deposition of dirt on surrounding
property, can be eliminated.
While the overall removal efficiency may be high, the ability to control
the fine particulates (<l@i) is markedly lower. Recent studies have indicated
that trace metals (such as arsenic, beryllium, cadmium, maganese, mercury,
nickel, and vanadium) have a high affinity to this fine fraction [546]. Table
26 shows estimates of emission rates for these trace elements. The toxicity of
many of these elements has been documented and there is some concern regarding
the long-term effects of chronic, low-level exposure.

TABLE 26

TRACE ELEMENT EMISSIONS OF A

COAL-FIRED POWER PLANT (1000MWe)

lbs/ton of coal burned 1 tons/yr 2

Arsenic 0.003 5

Beryllium 0.0003 0.4

Cadmium 0.001 0.001

Manganese 0.080
Mercury 0.0004 5

Nickel 0.003 0.5

Vanadium 0.0005

Lead 0.2
1 [5461 2 [2031

Also of increasing concern is the emission of trace radioactive mate--
rials in particulate form, primarily as uranium and thorium and their associated
daughter products [203]. While comparison with nuclear plant emissions is dif-
ficult because of the large number of variables involved, one study has indi-
cated that they fall "intermediate between the annual dose from PWR and BWR
nuclear plants"jcited in 203; p.1741.
Other effects associated with particulate emissions include the
following:
Action as a catalytic agent in reactions involving SOX and/or-NOx
(discussed below)

209

Vehicle for carrying toxic materials deep into the respiratory tract
6 Reduction of direct sunlight

* Reduced-visibility
e Interference with plant physiology
* Adverse effects on animals eating'plant materials with particulates
on them [203]

The principal oxides of nitrogen released to the atmosphere during the
combustion process are NO (nitric oxide) and NO 2' (.nitrogen dioxide). Most of
the NOx produced in the boiler is NO, a portion of which is converted to NO 2 upon
reaction with oxygen in the atmosphere via a photo-chemical reaction [203]. The
effects of NOX in the environment are just now becoming clear. They are "now
recognized as prime contributors to the eye-irritating smog characteristic of
Los Angeles area" [451; p.1151. Other studies [cited in 203] indicate serious

health effects:

At ambient concentrations, N02 presents a direct threat to
general health, while NO does not-except in its ability
.to be converted to N02-

Nitrogen dioxide exhibits primary toxicity to the lungs,
and levels above.about 100 ppm are lethal to most animals.
Repeated exposure to N02 in sub-lethal doses has resulted
in early pulmonary emphysema-type lesions in the experi-
mental animals. Long-term exposure to N02 concentration
that does not cause acute inflammatory responses may have a
significant role in the development of chronic lung disease...
Other effects of atmospheric NOx are corrosion damage and
crop reduction...[203; p.172].
In general, research and development of NOX control systems for power plants have
been quite limited, primarily because the automobile is presently the major con-

tributor to air-borne oxides of nitrogen.
As discussed previously, air pollution control efforts by the electric
utilities have concentrated on theredUction of sulfur emissions (SOX) from the
combustion process. The main species of SOX formed in the combustion chamber is
S02 (sulfur dioxide). In general, S02 by itself does not exhibit any major
deleterious effects [521]. However, once in the atmosphere, the S02 participates
in a number of chemical reac tions resulting in several products, each capable
of some degree of environmental damage. The processes by which these conversions
take place "are complex and incompletely understood" [521; pp.xxii-xxiii].

See discussion of Emerging Technology in Fossil Fuel Power Plant.

210

When S02 is emitted to the atmosphere, a fraction of it is oxidized to
form H2so4 (sulfuric acid). While the reaction normally occurs relatively slowly
(0.1 percent per hour), it is greatly accelerated by the presence of other air
contaminants (trace metal ions, hydrocarbons, and nitrogen oxides). Once formed,
the sulfuric acid may then react with trace metal ions (found in conjunction
with the five particulates discussed above) to form particulate sulfates. Even
in the absence of this oxidation reaction, the SO 2 may dissolve in water vapor,
forming the weakly acidic surfurous acid (H 2so 3).
The effects of SO 2 and its by-products can be observed throughout the
natural and cultural environments.
The major impact of airborne SO 2 is probably on vegetation.
These effects are due to the direct effect of acid formed on
the surface of leaves in combination with moisture and to S02
gas.penetrating.into the plant tissues..." [498; p.29].
In terms of its impact on man, SO 2 is primarily a pulmonary irritant:
Massive acute doses can result in severe respiratoryreactions,
chronic low level exposure may lead to chronic obstructive lung
disease. The secondary reaction products of S02 in the body may
result in additional potentially systemic effects" [498; p.301.

The synergistic effect of SO 2 and fine particulates may be potentially more seri-
ous due to the formation of sulfates and the ability of the particulate material
to carry them deeper into the respiratory tract [498 and 521]. "Animal studies
and the recent ... epidemiological studies indicate that sulfate aerosols are the
fform of airborne sulfur primarily affecting man's health" (498; p.32]. However,
the health effect findings are not completely clear:

First., the chemical form of the sulfates that are associated
with increased mortality and morbidity has not yet been
clearly identified. Second, there have been few direct
epidemiological studies linking excess mortality to sulfates.
Rather sulfate concentrations were usually estimated based on
correlations with particulates and sulfur dioxide (a correla-
tion which has been shown to be low) and these estimates were
related to'health effects... Finally, case studies (e.g.,
London) tend to indicate that attainment and maintenance of
ambient standards for S02 and particulates will protect public
health [393; p.A-7].

In addition, sulfur emissions can affect materials as an acid increasing
corrosion and'deterioration of "painted surfaces, metals, building materials, and
Seet521]for a more complete description of these reaction sequences.

211

fabrics" [498; p-31]. They also can reduce visibility at high concentrations.

Appendix E contains a list of the observed effects of the three major
air contaminants associated with fossil fuel power plant operation (particulates,
NO 2') and SO2), taken from a report prepared for the Michigan Public Service Com-
mission (393]. While they are not the only important pollutants associated with
plant operations, they are the ones for which standards currently exist and,
thus, should be highlighted. However, consideration of a much broader range of
pollutants, including the secondary products of these three, should be a part of
a site selection and/or certification procedure.
Wastewater effluents other than those associated with the cooling system
arise from several sources: main steam boiler blowdown, demineralizer regenera-
tion wastes, floor drains, sanitary wastes, and ash sluicing water. Most of
these waste streams are relatively small compared to cooling water return flow.
(Even a closed-cycle system blowdown flow can be several thousand gallons per
minute.) Some are subject to standard treatment practices (e.g., sanitary
waste treatment and the use of.ash settling ponds to- significantly reduce sus-
pended solid loads in ash sluicing water).
The impact of these effluents will depend on the volume of flows, treat-
ment received, the discharge structure configuration, the nature of the chemicals,
and the assimilative capacities of the-receiving waters.
The impact of these chemicals on human populations is generally
not direct, because natural processes of dilution and chemical
reactions reduce the concentrations to negligible levels at
the point where.water is withdrawn for human uses [203; p.156].

Specific details of potential impacts on the aquatic ecology are difficult to

quantify because of the wide variety of variables and the complexity of inter-
actions (most not yet understood) involved.
Leaching of toxic materials from the ash storage pile may represent a
serious threat to the quality of the ground-water supply.
Direct cultural system impacts arising from the operation of a coal-fired
power plant are not nearly as significant as those possible during the construc-

tion phase. As indicated in Table 12, the operational work force for proposed
plants ranges from 120-693 persons. Estimates from other sources indicate a
somewhat smaller range: 150-300 [2031, approximately 160 [451], and 120 [526].
Unlike the construction force, however, the operating personnel will become part

212

of the permanent residential base in the local communities:
... the induced effect on local business and employment in other
industries will be substantially greater than the effects of the
same number of construction employees. They will tend to spend
a greater proportion of their income in the area, and their
housing needs will be more permanent and substantial. This means
the property tax collections per employee will be higher, but of
course their demands on public services will also be higher.
They and their families are much more likely to take active roles
in the community, especially as they have above-average education
and income. In a sparsely populated region, the addition of even
50 or so such families may make an important difference in social
and cultural life, and the work of civic, charitable, and frater-
nal organizations [451; p.177].

(b) Cooling system operation
Presently, one of the activities of concern related to the operation of
a power plant (both fossil fueled and nuclear) is the dissipation of waste heat

via the condenser cooling system. The potential impacts, particularly to the
aquatic ecology, may be significant and must be considered in a facility evalua-
tion procedure. Discussion as to what these impacts are has been grouped by

cooling system type below.

(i) Once-through cooling
Once-through cooling systems have a minimal impact on the air and
local meteorology, as most of the waste heat is carried to the receiving body.
Likewise, they have the smallest land requirement and require no major structures
that may conflict with the surrounding landscape.
It is the potential impact on the aquatic ecology that has generated the
most opposition to the continued use of once-through cooling. These impacts are:
-attributed to (a) the mechanical and thermal shock to small
entrained organisms that pass through the cooling system pumps
and condensers-, (b) the effects of increased water temperature
on the biota in the receiving waters, (c) the entrapment and
impingement of fish on the intake screens, (d) the toxic effect
of chemicals introduced into the cooling water, and (e) the
effects of erosion and changing of ambient currents in the
receiving water. Because once-through cooling systems utilize
large volumes of water from the receiving body (rivers or lakes),
they have the potential for producing significant biological
impacts [203; p.1911.

The entrainment and subsequent passage through the condenser system of

213

large numbers of smal 1 organisms is considered by some to be the leading environ-
mental hazarA of once-through cooling systems [3801. While there are few studies
available to show the magnitude of the problem in the Great Lakes, indications

are that it may be significant:

In addition to the losses of fish caused by impingement on the
3/8-inch mesh traveling screens within power plant cooling sys-
tems on the Great Lakes, substantially larger numbers of fish
0.3-2.5 inches long are lost when they are drawn into these
plants and pass through the traveling screens (rather than
being impinged). ...Edsall and Yocum estimated a potential
entrainment of several million fish fry per day at two power
plants in southeastern Lake Michigan. Their estimate was
based on the abundance of fish fry in the lake near the cooling
water intakes and the cooling water use rates at the two power
plants. Intensive studies of the kinds and numbers of fish
eggs and fry being entrained at plants on the Great Lakes and
their connecting waterways are now underway. Preliminary re-
sults of one such study being conducted at the Detroit Edison
plant on Lake Erie near Monroe, Michigan, indicate that more
than 300 million fish larvae may have passed through that
plant during April-August 1973. The fate of these larvae
was not determined, but the data indicate that some may have
disintegrated during passage through the plant, and the mor-
tality among the remainder must almost certainly have been
high [617; p.458].

While the importance of entrainment has recently.become apparent, the
significance of thermal loadings has been discounted by some: "Thermal pollution
is not the leading adverse environmental threat from power plants, as commonly
has been believed" [380; p.v]. However, there is still a large body of evidence
that thermal effluents can and do cause significant damage (see reviews of find-
ings in 203 and 617). In general, most effects seem to be sublethal, involving
changes in species composition, fish movement through the area, and spawning
habits. Other temperature-induced effects include increased incidence of gas
bubble disease, synergistic chemical reactions, and oxygen depletion.
Related to the discharge of thermal effluents are the effects of entrain-

ment of fish in the discharge plume.
This form of entrainment had also been overlooked until recently,
but the available information suggests that the number of fish
fry that are entrained in this manner may be several times
greater than the number entrained at the cooling system intake
and passed through the plant. This is especially prevalent at
plants with high velocity discharges specifically designed to
lower the effluent temperature by rapid dilution of the effluent
with the cooler lake (receiving) water. Studies have not been
done to determine the fate of fry entrained in this manner at

214

Great Lakes power plants, but mortality could occur from heat
shock, chlorine intoxication, predation, or from hydraulic
mauling received during entrainment. Various investigators
have found that one major effect of such sublethal exposure
of fish to elevated temperature is a reduction in the ability
of exposed fish to avoid predation [611; p.4591.

Impingement on the trash rack and mesh screens of the water intake struc-
ture may also cause fish kills. Examples from studies on impingement problems
in the Great Lakes include the following:
e About 92,000 pounds of gizzard shad at the Lambton plant on the
St. Clair River in 6 weeks during December 1971-January 1972
o 82,187 pounds (nearly 1.1 million individuals) at the Detroit Edison
Company's plant on Lake Erie near Monroe, Michigan between April 1972 and
March 1973, when the plant was operating at less than maximum capacity
9 36,631 pounds (584,687 fish) at the Consumers Power Company's
Palisades plant on Lake Michigan between July 1972 and June 1973, when the plant
was operating at about 68 percent of its total capacity
* An estimated 1.2 million fish (no weight data given) at the Waukegan,
Illinois plant on Lake Michigan between June 1972 and June 1973
* 150,000 pounds of fish at the Pickering Plant on Lake Ontario in
April-June 1973

659.,000 fish (weight unavailable) at the Nine Mile Point plant gen-
erating unit number one on Lake Ontario during intermittent sampling from
January to December 1973, representing an estimated tot al of about 5 million fish
at unit one for that period
o About 67,950 pounds (929,000 fish) at the Zion plant near Zion,
Illinois, on Lake Michigan during September-December 1973 and March-June 1974,
when the monthly cooling water flow averaged only about 45 percent of the maxi-
mum capacity [611; p458].

Of course, the significance of the entrapment and impingement problem
cannot be judged unless its effects are viewed relative to the Great Lakes
Fishery as a whole.
Water used in a plant cooling system requires the addition of chemicals
to prevent biological fouling and retard corrosion. Chemicals used include:
chromates, zinc, phosphates, and silicates for corrosion control;
chlorine, hypochlorite, chlorophenols, quaternary amines, and
organometallic compounds for bacterial growth control; acids and
alkalis for pH control necessary to prevent scale formation;

215

lignintannins, polyacrylamides, polyethylene ami nes, and other
polyelectrolytes to redu6e silt deposition [203; p.205].

When released to the aquatic environment, these chemicals and/or their,reaction
products can have toxic effects, especially on organisms-near the outfall.
While discharges are normally kept below established toxicity levels, there may

be adverse effects due to:

e Possible synergistic effects of the higher water temperatures in a
cooling water discharge
o Possible synergistic and/or cumulative effects of other chemicals
already present in the water and in the tissues of the organism

Presence of untested species or individuals more'sensitive to a par-

ticular chemical than the tested individuals

9 Possible chronic and long-term sublethal effects that may not manifest
themselves until later in the life cycle of the organism [203; p.205].

These effects may be more serious with closed-cycle systems because of

the increased amounts of chemicals used and-the small amount of water available

for dilution.

(ii) Natural draft cooling towers
The use of a natural draft tower creates potential adverse effects on
the local meteorology through increased fogging (and icing during the winter
months). However, this is less likely to be a problem than if mechanical draft

towers are used.

Related to the problem of fogging is that of drift: water lost in droplet
form by means of which salts are deposited over a wide area downwind from the
tower. While drift rates are low (0.002 percent of the circulating flow rate for
natural draft towers), these deposits may be detrimental to the biota and
agriculture.
One concern related to the use of cooling towers at fossil fuel plants is
the possibility of synergistic effects between the most vapor plume and the
stack emissions. In particular, reactions with SO 2 in the stack gas could pro-
ducea sulfuric acid mist. But studies have not indicated that this is a
serious problem [2031.
Land requirements for a natural draft cooling tower are greater than for

See section on Hydrology and Meteorology in description of Nuclear Power Plants.

216

a once-through system but are less than that of the other closed-cycle systems.
The most obvi ous impact of a natural draft cooling tower is its presence
in the surrounding landscape. Because they are up to 500 feet tall and 400 feet
in diameter, it is difficult to make them unobtrusive. Of course, the degree of
intrusion will depend on the character of the surrounding area and the way in
which people view the two in juxtaposition.
Finally, natural draft towers could have adverse effects on migratory
birds if located in a major flyway [614].

(iii) Mechanical draft,cooling towers
The potential for fogging and icing problems is much greater with mech-

anical draft towers than with natural draft towers. This is because the mechani-

cal towers are much lower (60 feet versus 500 feet), making inversion penetra-
tion less likely. Also, the plume is less concentrated and cools faster than
the larger natural draft plume. The potential for drift problems is somewhat
higher as 0.005 percent of the circulating flow is lost in this form [203].
Land requirements are somewhat higher than for natural draft towers due

to the need for multiple units and spacing between them to prevent recirculation.
Because-of their low profiles, mechanical draft towers themselves do not
present the aesthetic problems associated with natural draft units. However,
the increased propensity for fogging and icing could cause significant visual
impacts. Also, noise caused by the fans can be an important problem during

operation.

(iv) Cooling ponds
Occasional fogging and icing,problems may be associated with the use of
cooling ponds, although not to the extent of cooling towers. There are no drift
problems.
The major problem associated with the use of cooling ponds in the large
land requirement: greater than 1,000 acres for the size of facility considered
here. Creation of a water surface this large may require the impoundment on a
river, which could have significant natural and cultural impacts.

See Land Requirements in the Fossil Fuel Power Plant description.

217

(v) Spray Canals
The potential for fogging and icing problems is somewhat higher for
Spray canals than for cooling poinds, although it may be more localized than

that of mechanical draft towers. Also, while there may be some drift produced,
it is ejected at such a low altitude (10-15 feet) that it would most.likely not
be a problem outside of the plant site.
Land area requirements for a spray canal system are larger than that for
a cooling tower of either type but much smaller than that for a cooling pond.

(vi) Summary of cooling system impacts
The above discussion has touched only briefly on the problems related to
cooling system operation, especially With respect to the impacts on the aquatic
environment. While the discussion of these impacts was included.in the section
on once-through cooling, it is important to remember that all cooling systems
will affect the source and receiving waters to some degree.

As discussed in the facility description section, a coal-fired power
plant requires approximately 100,acres for ash disposal over its operational
lifetime. The impacts associated with the handling and storage of t hese waste
materials are primarily related to the release of potentially degrading and

toxic materials to the environment and the disruption of human and natural

systems.
As discussed in the plant operation section, toxic materials present in
the fuel tend to become concentrated in the ash. These substances (primarily
heavy metals and radioactive isotopes) find their way into the environment by
several pathways: particulate material blown off the waste piles, dissolved and
suspended fine particulates in the ash sluic ng water, leachates and,runoff from
the storage area into the ground and surface waters.
The movement of waste material between the boiler and the disposal site
may have an impact on traffic movement around the facility if the two sites are
physically separated. Also, the presence of the disposal area could have aes-
thetic impacts if it is visible from off-site locations. Finally, the ash dis-
posal area will displace the natural biota of the site.

218

(d) Transmission lines
The impacts of an Extra High Voltage (EHV-345 and 765 kV) transmission
line arise primarily from two sources: disruption of the -natural and cultural
environments by the presence of the right-of-way and its associated structures,
and induced electric field effects caused by the flow of energy through the

line.

The presence of a transmission line right-of-way can cause several
changes in the local natural environment. The clearing and subsequent revegeta-
tion of the right-of-way create a new habitat, leading to increased species
diversity. At the same time, however, the application of herbicides as a part
of the right-of-@-way maintenance procedure may have detrimental effects on both

the terrestrial and aquatic ecosystems, if proper application procedures are not
followed. Also, piles of slash left along the right-of-way may provide breeding
grounds for harmful insects and plant pathogens.
Crossing of property lines by the right-of-way may result in fractiona-
tion of property and disruption of certain activities, such as agriculture.
This will not be a significant problem if less than fee-simple ownership of the
right-of-way (i.e., an easement) is acquired, since the actual structures require
littl6area and the owner would be able to keep most of the land in its former

use.

A right-of-way may also provide an access route into or through an area
where none had existed previously. This may have a positive or negative effect,
depending on whether or not such access is desirable.
One of the major problems associated with transmission lines is that
they can be aesthetically disruptive. This is especially a problem in cases
where the right-of-way crosses a high-visibility area, such as a hilltop or a

scenic vista. It can also create aesthetic, and sometimes physical, disruption
when it crosses a recreation area.' The degree of disruption will vary from case-
to-case and should be evaluated carefully in site selection and/or approval

decision.

The second class of effects associated wi.th ERV transmission lines is

that related to the electric field generated by the flow of energy through the-
lines. Available environmental reports prepared by the utilities [378 and 608]
indicate that these effects are limited and not'significant, although there.is
some controversy regarding this point [6021.

GROUND CLZABMSG AND RESHAPING
coaumm USE
CHAMOELIZATION, siiomxjm mmn=&Ti.
AM OTM N&TER-REATED ACTIVITIZO'
MATERIAL MOVEMM TO SITE
INFLUX OF TEMPORARY WORK FORCE
PUBLIC SERVICE REQUIRTIOM
LAO COMKITTED TO FACILITY
OTM

LEACEATES AND RmXw
"N.SJUN
BMW ACTIVITY DISRUPTION
EQUIPMENT USE

V&STVATER DISCHASCE
PARTICULAIES
SO.
BOX
MUMAK SERVICE REQUIRES111173'
ACCID30TS

TKERHAT. EFFLUENT
CHEMICAL ADDITIONS
SLOWDOWN WATER
mum-up WATER RE(rimmmmi
FOG/ICING/DRIFT
ENTRAPMENVINPINGS14M
VISUAL INTRUSION

LEACHATES AND RUNDFF
-iARTICULITES
VISUAL INTRUSION
ED" ACTIVITY DISRUPTION
NATURAL SYSTEM DISR117`2200

VISUAL INTRUSION
MUMAN ACTIVITY DISRUPTION
NATURAL SYSTEM =52UPTION
ELECTRIC FIELD EFFEM

219

Because EHV transmission lines use air as an insulator, there is a con-
stant discharge to the atmosphere, termed "corona discharge." The magnitude of
this discharge depends primarily on the size and spacing of the conductors and
ambient weather conditions,.especially humidity. Proper design can reduce the
problems caused by corona discharge, but cannot eliminate them.
There are four potential problems related to the effects of corona dis-
charge: audible noise (AN), television and radio interference (TVI and RI, res-
.pectively), ozone production, and electrostatic induction.
Generally, these problems are worse during wet or humid weather. Right-
of-way selection and line design should be carried out in such a way as to mini-

mize these effects.

Figure 17 summarizes the impact vectors and.environments potentially

affected by the construction and operation of a fossil-fuel power plant..

(2) Nuclear Power Plants
The types of impacts and general environments affected by the operation
of a nuclear power plant are shown in Figure 18. This discussion will concen-
trate on impacts related to reactor operation, specifically sources of radio-

nuclide release to the environment'. It will also touch briefly on human service
requirements, and. accidents. Impacts related to cooling system operation and
electricity transmission have been covered adequately in the previous section
and will not be repeated here.
The principal sources of radioactive materials are the fission
products which are produced in the fuel elements as a by-
product of normal operation. The quantity formed is small in
terms of mass, amounting to a few kilograms per day in a large
power plant. Under normal operation, more than 99 percent of
fission products remain in the reactor core where they were
formed. Small quantities which leak from the fuel elements,
however, are ultimately released from the plant radioactive
waste processing system to the environment. In addi *tion to
the fission products, other sources of radioactivity are
leakage of radioactive materials from control rods, activation
of impurities in the reactor coolant, activation of corrosion
products from structural materials, and tramp uranium which
adheres to the outside of the fuel rods during the manufac-
turing process [203; p.23].

There are four types of radioactive waste materials (radwastes) that
must be dealt with: gaseous, liquid, ventilation exhaust air, and solids. All
four are produced by both reactor types now in use: the boiling water reactor

220

FIGURE 18

DIAGRAMATIC SUMMARY OF

NUCLEAR POWER PLANT ENVIRONMENTAL IMPACTS

Gd4

Ailh.di .... fid-

Fuel. Light Walat
Fabmaawn Reactor

Spent
Fuel
Storage

W.w/ai ... J-d-I.d.

Spew Fuel ralisportation
plocessisig of Wastes

Ah/1-1

Aldf-k

Wet My Once
C-lutt; Cooling Coolini., Tluouulk
p ... id To- T-w Cooling
Ij
I Ln-ddi ... 1-4 ..1 @-j

W-dd-W-d ..bj.

L-J@-f- -p .......

A'A .1 .,w m....'W@w ."id4m.
@WTC--"

[Source 501]

221

and pressurized water reactor. However, the mix of these wastes varies with
reactor type, BWR's producing more gaseous radwaste (radgas) and PWRIs producing
higher levels of liquid radwaste.

(a) Boiling water reactor wastes
The principal source of radgas in both reactor types is the degassing
ofthe primary coolant. Much of this gas is a result of air inleakage at the
condenser. In a BWR, additional gaseous wastes are generated by fission and
activation products and radiolytic decomposition products (hydrogen and oxygen).
Also, radgas emissions may arise from leakages around the turbine gland seals,
especially in older plants (new plants having eliminated this waste source).
Most of these gaseous wastes are removed at the turbine condenser through
an air ejector. These effluents contain nitrogen-13 (an activation product),
noble gas isotopes, krypton and xenon (fission products), halogens (mostly
iodine), and tritium. In addition, there are some radioactive particulates and

solid decay products associated with the gaseous wastes.
Treatment consists primarily of delay (30-60 minutes) to allow the short-
lived isotopes to decay and filtration through high efficiency particulate (HEPA)
filters prior to venting through the station's stack [203 and 546]. Alterna-
tively, cryogenic distillation may be used to liquify and remove the noble gas
fission products [5461. A charcoal absorber system can also be used to provide
up to 10 hours of delay to reduce the amount of xenon and krypton, the two
principal radioactive species. -Figure 19 shows a simplified radgas control sys-
tem schematic while Table 27summarizes the principal isotope emissions based on

varying delay times.
There are four major types of liquid radwastes from a nuclear power
facility of either type: high purity wastes, which are radioactive but low in
normal chemical impurities (e.g., primary coolant leaks and equipment drains);
low purity wastes with varying levels of radioactivity, such as floor drains;
chemical wastes; and detergent wastes with low levels of radioactivity [203 and
5461. "These waste streams are segregated according to origin so that liquids
of near coolant quality may be treated and reused..." [546; p-167]. Following
treatment, the liquid waste discharges are then, bled into the cooling water
discharge flow at such a rate to meet government emission standards. Figure 20-
and Table-27 show a typical BWR liquid radwaste treatment system,and effluent

activity levels, respectively.

FIGURE 19

BWR RADGAS CONTROL SYSTEK

S
T
A
C
K

GLAND FROM SECONDARY VENTILATION AND
SEAL VACUUM PUMP DISCHARGE
LEAKAGE
HOLD-UP

STEAM FROM'
REACTOR
V
E
URBINE N
T_
CONDENSATE CONDENSER RECOMBINER
RETURN TO AIR CONDENSER
REACTOR EJECTOR OFF GAS
HOLD-UP
1A ------- IL
;CHARCOAL,
I BEDS I
P- ROUGHING FILTER OR I
C- CHARCOAL AOSORBER CRYOG EN IC!
STILL
A- HEPA FILTER

[Source 2031
p
@R
1@E

223

TABLE 27

ANNUAL LIQUID EFFLUENT ACTIVITY FOR A 1000 MWe REACTOR

.(Curies/year)

Principle Isotopes BWR. PWR

Rb-88 0.39
Sr-89 0.64
Y-90 0.14
Y-91 0.31
1-131 1.71 0.47
Te-132 0.96
1-133 0.20 0.11
Cs-134 0.36 0.41
Cs-136 0.20
Cs-137 0.27 0.28
Cs-138 0.27
Ba-140 0.93
Ba-137m 0.26
La-140 0.71
Fe-55 0.26
Co-58 0.60 0.33
Mn-56 0.84
Other liquid activity 1.0 .0.78

Total(excluding 7.1 5.3
tritium)

Tritium 20.0 350

[Source 203]

Solid radwastes are similar for both BWR's and PWR's, consisting of
three general types: wet, such as spent resins and evaporator concentrates; dry
compressible, such as rags, clothing, and plastic; and dry noncompressible, such
as equipment [546]. The wet wastes are solidified and kept on-site for a period
to permit the decay of short-lived radionuclides. Ultimate disposal for all
forms is burial at an approved site. It is estimated that total.solid waste
activity from a 1000-MWe reactor amounts to 2,500-5,000 curies per year [2031.

See Table 21 for definition.

224

FIGURE 20

BWR LIQUID WASTE SYSTEM

CONDENSATE RECYCLE
STORAGE

FROM
EQUIPMENT COLLECTOR WASTE
DRAINS FOR HIGH --pFILTER DEMIN- SAMPLE
PURITY ERALIZER TANK
WASTE

FROM FIL OR DRAIN
PLANT WASTE DEMIN- SAMPLE
FLOOR COLLECTOR 7r FILTER TANKS
DRAINS ERALIZER

CHEMICAL
FROM LAB WASTE EVAPO- CONDENSATE
DRAINS AND--' COLLECTOR- RATOR TANK
DECON- NEUTRALIZER
TAMINANTS

FROM LAUNDRY
LAUNDRY@ (DETERGENT) FI LT ER R
DRAINS DRAIN TANKS

DISCHARGE
s CANAL

S SAMPLING POINT

SOLID-WASTE TO PAC KAGING S

ADDED FOR MAX RECYCLE

R RADIOACTIVITY MONITOR

[Source 2031
@CONDENSATE
STORAGE

DPEMIN @:LE
LIZ
.S
t ;ERA ER

225

(b) Pressurized waterreactor wastes

The major source of PWR radgas is in the primary coolant system, although
r1radioactive gases will exhaust from the main condenser air ejector when steam
generator leakage from primary to secondary system occurs" [546; p.190].
During operation of PWR, radioactive materials released to the
atmosphere in gaseous effluents are similar to those released
from a BWR and include low concentrations of the fission product
noble gases (krypton and xenon), halogens (mostly iodines), and
tritium contained in water vapor and particulate material [203; p.26].

However, the activity levels of these emissions is typically much lower for a
PWR, due to the considerably larger delay prior to release (45-60 days); see
Table 28. A schematic of a PWR radgas control system is shown in Figure 21.
As Table 28 indicates, liquid radwastes are similar for both PWR and
BWR plants with the exception of tritium. This greater than tenfold difference

in tritium emissions arises

primarily from the use of boron soluble poison in the PWR
coolant for supplementary control. Boron undergoes a
neutron capture reaction to generate tritium which has a
relatively long half-life (12.3 years). Since tritiated
water is chemically identifical with ordinary water,
separation is very difficult and to date impractical. The
lower tritium releases in later model PWR's have been largely
achieved by water management schemes which store more of the
tritium in the plant water inventory [203; p.34].

As discussed above, PWR solid radwastes are similar to those from a BWR
facility.

Figure 22 shows the major pathways of radiation-through the environment
and ultimately to the human population. Under normal operating conditions, all
nuclear plants (and, as discussed earlier, most fossil fuel plants) emit traces
of radioactive substances to the environment in both liquid and gaseous form.

Concern with the effects of these emissions, especially over the long term, is

one of the major points of controversy in the nuclear power debate. The brief
discussion below cannot answer any of these questions (nor can any other docu-
ment) but it will highlight some of the issues.

Radioactive solids (except for fine particulates that may pass through the
HEPA filters) are not considered to be an emission for the purposes of this
report, although their handling and disposal (storage) do present significant
problems.

226

TABLE 28

ESTIMATED ANNUAL RADGAS EFFLUENTS

FROM A 1000-MWe REACTOR
Release Rate, curie0yearl/

2/
Nuclide Half-Life 30 min. delay.:-, 1 day d layll 60 day delayl/
83mKr 1.86 hr.. 90,000 13 0
85Kr 10.76 yr. 250 250 250
85mKr 4.4 hr. 160,000 3,900 0

87
Kr 1.3 hr. 480,000 1.5 0
88Kr 2.8 hr. 510,000 1,500 0
89Kr 3.2 min. 11,000 0 0

Total Kr activity 1,250,000 5,650 250
(approx.)

15 day de
131mXe 11.9 day 375 150 10
133Xe 5.27 day 1601000 22,000 50
133mXe 2.3 day 6,000 50 0
135Xe 9.2 hr. 540,000 0 0
135mx, 15.6 min. 260,000 0 0
137Xe 3.8 min. 281000 0 0
138xe 14 min. 780,000 0 0

Total le activity 1,800,000 22,200 66
(approx.j

l/ Assumes operation with 0.2% clad defects.
2/ Typical holdup time in BWR's built to date.
Typical holdup times for BWR's using charcoal beds.
Typical holdup times in PWR's are between 45 and 60 days and
accordingly would be between the 1 and 60 day values.

A curie is a measure of radioactivity, specifically "a quantity of
any radioactive nuclide in which 3.7 x 1010 disintegrations occur per
second" (Webster's New Collegiate Dictionary)
[Source - 2031

FIGURE 21

PWR RADGAS CONTROL SYSTEM

RECYCLE TO PRIM.
COOLANT SYSTEM

PRIMARY COOLANT
SYSTEM OFF-GAS DECAY TANK
,11EADER
P C A
COMPRESSOR ORIFI CE
SURGE
TANK

STEAM
TURBINE
p

CONDENSA E CONDENSER
AIR SUPPLY PRIMARY ->
COOLANT CONDENSER Al
EJECTOR

STEAM
GENERATOR

z
BLOWDOWN LLj
L FLASH TANK >
DRAIN TO WAST E SYSTEM FT
CONTAINMENT BUILDING RU R G E
CONTAINMENT BUILDING

P-ROuGHING FILTER
C-CHARCCAL ADSORSER
A-HEPA FILTER

[Source 2031
R AIR
L@CO@N CT
4;ANYT DENS@ER
E@JEO@R
AM@
7@F
D

228

FIGURE 22

PATIMAYS OF RADIATION THROUGH THE ENVIRONMENT

Dairy
Crit;c-@l Pasturage Animals
Pathway for Products

Dischare,e of
Radionuclides Air b Crops P- Farm
In Gaseous Products
Effluents

Nucliear Fish & Fish & Shellfish Human
Reactor Shellfish Processing Population

Pecreational
Discharge of Surface Exposure
Radionuclides Surface Water Edible
In Liquid Water Waterfowl
Effluents supply
I Ground
Ground Water Drinking
Water Water
Supply

[Source 4511

No radioactive materials normally emitted by a nuclear power facility
must exceed standards administered by the NRC. At present, the regulations
(10 CFR 50 Appendix I) specify that air emissions cannot exceed one percent of
the normal background level of activity. Furthermore, the maximum annual whole
body dose to an unprotected individual is restricted to15 millirems.

� Estimated annual total quantity of radioactive material, except

tritium, should not exceed 5 curies.

� Estimated annual average concentration of radioactive material prior
to dilution in a natural body of water, except tritium, should not exceed
-5 .
2 x 10 microcuries per liter.

* Estimated annual average concentrations of tritium prior to dilution
in a natural body of water should not exceed 5 x 10- 3 microcuries per liter.
A
Z
J 'I'll
A / / //j/1
n /a@@

On a similar basis, S02 and N02 emission standards are 10,000 percent and 400
percent of natural background levels.

A measure of radiation dosage. For comparative purposes, the average dose
per year from natural background sources is 135 millirems.

229

0 Radioactive material above background must not result in an exposure
rate such that a hypothetical individual, continuously present in the open at
the site boundary, incurs an annual exposure to the whole body or any organ in
excess of 5millirems [203; p.155].

A major factor in calculating the effective dose rate from airborne
radioactive material is the dispersion pattern upon release from the stack.
Estimated maximum individual doses are shown in Table 29, based on a person re-
siding permanently at the plant site boundary closest to the plant. Doses for
individuals further from the plant would be lower, the amount dependent on wind

patterns and other dispersion factors.

TABLE 29

MAXIMUM ESTIMATED WHOLE BODY DOSE

AT SITE BOUNDARY FOR A 1000 MWe PLANT

Dose Rate (millirem/year)
BWR
Holdup Time 300 ft. Stack Roof Vent.
(days) P WR_ Discharge Discharge

0 40
30 (min.) 500
1 8 420
3 2 110
9 0.8 45
15 4.5
25 0.1 6
30 0.9
45** 0.45 0.01 0.7
60, 0.36 0.005 0.3
90 0.34

Typical design hold-up time for BWR's currently
coming into service
Typical design hold-up time for PWR's currently
coming into service

230

As Figure 22 indicates, direct whole body exposure is not the only route
to human (and other natural system component) contamination. For example,
iodine-131 is passed to man via an air-pasture-animal-dairy product pathway.
Once consumed, it concentrates in the thyroid gland. Knowledge of this and
other pathways of airborne emissions is incomplete and worthy of considerable
future research. The problem has been summarized:
Thetrue impact on the population of these very low doses from
nuclear power stations has not been accurately quantified to
date. The difficulty arises from the enormous amount of'data
which would be required to detect a statistically significant
effect from incremental doses that are only a few percent above
the normal background radiation exposure. Even if one accepts
the "linear 'dose theory," which implies that damage is'propor-
tional to dose down to essentially zero exposure, with no thresh-
old, the evidence suggests that the additional impacts are small
indeed [203; p.153].

The pathways of radioactive materials released to the aquatic environ-
ment have been succinctly described in material presented in reference 603:
Upon introduction into an aquatic environment, radioactive wastes
can: (1) remain in solution or in suspension; (2) precipitate and
settle to the bottom; or (3) be taken up by plants and animals.
Immediately upon introduction of radioactive materials into the
water, certain factors interact to dilute and disperse these
materials, while simultaneously other factors tend to concentrate
the radioactivity. Among those factors that dilute and disperse
radioactivity are currents, turbulent diffusion, isotopic dilu-
tion, and biological transport. Radioactivity is concentrated
biologically by uptake directly from the water and passage
through food webs, chemically and physically by adsorption, ion
exchange, coprecipitation, flocculation, and sedimentation.

Radioactive wastes in the aquatic environment may be cycled
through water, sediment, and the biota. Each radionuclide
tends to take a characteristic route and has its own rate of
movement from component to component prior to coming to rest
in a temporary reservoir, one of the three components of the
ecosystems. Isotopes can move from the water to the sediments
or to the biota. In effect, the sediments and biota compete
for the isotopes in the water. Even though in some instances,
sediments are initially successful in removing large quantities
of radionuclides from water, and thus, preventing their
immediate uptake by the biota, this sediment-associated radio-
activity may later affect many benthic species by exposing them
to radiation. Also, any radioactivity leached'from the sedi-
ments back to the water again becomes available for uptake
by the biota. Even before the radioactivity is leached from
the sediment, it may become available to the biota due to a
variation in the strength of the bonds between the different

231

radionuclides and the sediment particles. Loosely bound
radionuclides can be 'stripped' from particles of sediment
and utilized by bottom feeding organisms.

Plants and animals, to be of any significance in the cycling
of radionuclides in the aquatic environment, must accumulate
the radionuclide, retain it, be eaten by another organism,
and be digestible. However, even if an organism accumulates
.and retains a radionuclide and is not eaten before it dies,
the radionuclide will enter the "biological cycle" through
organisms that decompose the dead organic material into its
elemental components. Plants and animals that become radio-
active in this biological cycle can pose a health hazard when
eaten by man.

Aquatic life may receive radiation from radionuclides present
in the water and substrate and also from radionuclides that
may accumulate within their tissues. Humans can acquire radio-
nuclides via many pathways, but among the most important are
drinking water or edible fish and shellfish that have concen-
trated nuclides from the water. In order to prevent unaccept-
able doses of radiation from reaching humans, fish, and other
important organisms, the concentrations of radionuclides in
water, both fresh and marine, must be restricted [603].

As indicated above, the levels of exposure are too close to background
levels to be assessed aasily, "although all indications.are that the effect
is vanishingly small" [203; p.155].
As indicated in Table 18 in the discussion on construction impacts, the
operating work force requirements for a major nuclear power facility are rela-
tively small, ranging from 77-200 at the proposed plants listed. Other sources
indicate that a single unit facility with a capacity of 750-1000 MWe will have
less than 100 full-time employees, while a plant with two.units "will have much
less than double" that number of employees [451]. Based on this, it would seem
that the long-term socioeconomic impacts of immigration would be on par or
slightly less than those of a similar capacity fossil fuel plant.
A potential impact "unique to nuclear power plants evolves from per-
ceived danger of radiation" [601; p.2]. This concern would be articulated via

local opposition to the construction of a facility and tension during the
operational phase. In a study of this problem in the Northeast, researchers

from Oak Ridge National Laboratory found that:
Residents, in general, are unconcerned about the nuclear plant
in their community unless it has an accident or radioactive
spill.

232

intervenors [opposition leaders] in both communities are few;
those who do intervene or are vocal about nuclear power face
opposition from the majority of local residents.

Communities appear to adopt an "out of sight, out of mind"
attitude toward the facility [600; pp.11-12].

While these results apply only to the specific communities involved and should
not be generalized, they do at least provide an indication of what local senti-
ment might be. Opinion research studies in the area of a proposed facility
should be a part of the evaluation procedure.

One of the most controversial issues related to the future use of nuclear

power plants is the potential for catastrophic accidents, core meltdowns with a
release of primary coolant to the atmosphere. The utilities and suppliers
point to redundant emergency control systems, conservative engineering standards,
and a nuclear safety record of hundreds of reactor-years of-operation without a
major accident. Critics point out that much of that experience has been with

low-power naval reactors and that several mishaps have pointed out flaws in
design, construction, and operation. Finally, they make.the point that the
magnitude of destruction associated with an accident presents risks too large
to take, even if the probability is extremely,small. There is no answer to the
controversy and it is not the purpose of this report to go beyond suggesting
that the states should consider it as a part of an energy facility siting

program.
The activity-impact evaluation matrix in Figure 23 summarizes the
activities associated with the construction and operation of a nuclear power
facility and the environments potentially affected by them.

(3) Coal Transshipment-Facilities
Impacts related specifically to the. operation and maintenance of coal
transshipment facilities fall into the major categories of natural environment
disruption and intrusion on cultural aesthetics. In addition to these negative
impacts are thepositive effects on local and regional economy and employment
and the value of the service performed by the facility when completed. Conse-
quently, the natural/cultural division of environments provide a workable base

Other major issues include safe disposal of high-level wastes, protection
against sabotage and terrorist activites (including stealing plutonium), and
transport of hazardous materials.

232a

N A T 11 It A L
C U L T.U R A L
hrYSICAL & (JVKICAL CIMMTURISTICS BIMOGICAL (MITICHS SOC I AL Ecouomic
TERRESTilli-Al. QVA-ric Ar.,Tltr.Tlt;S AMD rual.1c
TERRE7TRIAl TIYF)Rnf.0rl(:Af. ATIVISMIER I C, Ecul,I)rT rx(ll.f*;y IRMO MEREST IMA1,111 rmAIMENT 11(41MC wRASIMIC-11M.F. I.AM) VALUE
@u FACF ( (VIRT) AIM 11111.111RAL C(NNVIVRCIA1. ItIMISPRIA1,
WATER WA I l:K It-Au'ry
-----------
ti cl @l ri U

13
8 3

CRWND CLEARM AM RRSWVAr
EQUIPMENT USE
CRAHMIZATMN. SHOMnM HMtftCATMW,
AM OTHER WATIR-RIMATED ACTIVITIES
PaTilmi, MVMMT To SITE
nrnm OF Tv"R"Y WRX FORCE
maic SmvIcx z=uum=
LAW COM17M TO MILITY

RAD MaSSIONS
WASTElaTER DISCRAWE
Suw SEEVICT. mmumu4mm

MEL AND WASTE HANDLI NG

TmEDia Zn%mM
CHEKIM AMT10113
BLOWWWN MATE1
MM-4u? WATER ffwammm
FOG/T.CING/bRUT
mnTAMMMT/nenCMUM
VISUAL amsim

VISUAL MMS1011
HUMAN ACTIVITY DISRUPTION
MMIAL SYSTEM DISRUPTION
L MECT IRIC Ill= E"ECTS E-1 I

FIGURE 23
NUCLEAR POWER PLANTS

233

from which the specific impacts of a coal transshipment facility may be

considered.

(a) Natural
Coal dust emissions and their associated effects are the most signifi-
cant negative impacts related to the operation of coal handling and storage
facilities. The two most important impacts of these coal dust emissions relate
to the terrestrial and aquatic ecologies. Because of the presence in coal of
trace elements such as cadmium, mercury, lead, and arsenic, problems may develop
when these heavy metals are taken up from the soils and sediments by terrestrial
and aquatic plants [391]. Ingestion of these plants by terrestrial and aquatic
life introduces these trace elements to the food chain and in some cases, may
reach toxic levels through a cumulative process.
Coal dust fallout may increase turbidity levels of surrounding water
bodies as well. This may result in an overall decrease in the zone of photo-
synthetic activity and, thus, reduce productivity [391].
Similar impacts result from runoff and leachates associated with coal
stockpile drainage. In the case where large stockpiles of coal are maintained

during the off-shipping season, large volumes of coal are exposed to snow and
rain and subsequent runoff. In addition, liquid suppressants are sometimes
used to wet down the coal piles to control dust, resulting in additional infil-
tration of the pile by liquids.

The result of this drainage is two-fold. First, the surface runoff is
capable of washing coal dust from the pile and carrying it into existing drainage
canals or storm sewers, eventually introducing the dust to the receiving water.
body. The effects of this are explained above. Secondly, the water which per-
colates through the coal pile may take into solution those trace elements men-
tioned previously and introduce this resulting leachate to the ground-water
system. Because of the persistence of these heavy metals, well water quality
and even surface water quality may be impacted.
Harbor maintenance in the forra of dredging and disposal of these dredge
spoils is particular to coal transshipment facilties and has a potentially
significant impact on both water quality and aquatic and terrestrial ecology.

Mechanical disruption and displacement of bottom sediments may result in
increased turbidity and the release of gases and nutrients to the water column
which were previously tied up in the bottom sediments.

234

Noise from operation of heavy equipment such as rail traffic, stackers,
conveyors, bulldozers, ship loaders, and ship machinery may have an impact on
the wildlife community within the vicinity of the facility. This may result in

both behavioral and physiological changes such as alterations in migratory
patterns and sexual function [391].

(b) Cultural
Impacts of a coal transshipment facility on the cultural environment of
the area result primarily from the physical presence of the facility and the
activities associated with its operation.

From a social standpoint, the visual intrusions which result from the
creation of large coal stockpiles approaching 50 feet in height may represent
a serious alteration of the previous view. This aesthetic impact is difficult

to quantify but may be reflected indirectly in public attitudes toward the
facility and in changes of land value around the-facility. Other aesthetic
impacts may result from high noise levels due to equipment use. Public health
may be affected by a coal transshipment facility operation in two ways: noise
levels due to equipment use may,occasionally exceed hearing damage levels re-
sulting in hearing impairment in the vicinity of the facility; likewise; effects
of coal dust on water quality (discussed in the previous section) may affect
drinking water supplies, threatening water potability- I
Economic impacts of a coal transshipment facility are reflected in
long-term employment for operation, taxes on earnings, property taxes, and
employment in associated rail and ship transport. These are all generally
positive impacts, which are felt most strongly at the local level. The magni-
tude of economic benefit will depend on the scope of the project. A new facility
will create many more jobs than the expansion of an existing facility, but this
number is still small by comparison with electric generating plant figures
(see Table 21). Likewise, the extent of economic impact is highly dependent on
the economic health of the area in question.
From a physical standpoint, changes in land use and recreational value
may result in cases where the facilities are developed on previously nonindustrial
sites. This is unlikely because most coal transshipment facilities have been
developed at existing harbors and expansion of these facilties is generally con-
tiguous to the existing facility. In the case of specific sites, such as
Conneaut Harbor, Ohio, expansion of coal storage facilities may result in a

FUEL TRANSSHIPMENT
AND STORAGE FACILITIES CONSTRUCTION

Lli@a FORMS

MYSICAL
QUAL.

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235

change of land use due to the rural nature of the area. In these cases, the
impact of committing undeveloped open lands to a single use (coal storage) is
significant especially in the coastal zone where land utilization and public

access are important questions.
Finally, community disruption in the form of traffic flow alterations
and tie-ups is a potentially significant impact of a coal transshipment
facility. In the case of the coal facility at Superior Harbor, Wisconsin [3911,
major consideration was given to the effects,of unit train operation in and

about the facility and how it would be reflected in traffic disruption. These
effects include increased necessity.for traffic rerouting, construction of
bridges and bypasses, and expansion of existing roads or railways. A graphic

summary of activities and environments assembled in the form of a matrix, which
may be used for amore specified case analysis, is provided in Figure 24.

(4) Oil Transshipment and Storage
Operation and maintenance impacts associated with oil transshipment and

storage facilities include the effects on the natural environment of oil spills

and hydrocarbon emissions and effects on the cultural environment in terms of

aesthetics and safety.

(a) Natural

The most significant and specific impacts of an oil transshipment and
storage facility on the natural environment are those associated with hydrocarbon

emissions and potential leaks and spills of oil. Hydrocarbon emissions escaping
during both storage and loading processes. adversely affect air quality by re-
ducing visibility in contributing to a photochemical smog effect [158] and by
adding significantly to the ambient odors. Also, as discussed in the facilities

description section, refined products transshipment is most common on the Great

Lakes and it is these petroleum products whose aromatic hydrocarbons are most
toxic [292].
Effects of oil leaks and spills on the natural environment range from
adverse impacts on water quality to health effects on wildlife. Figure 25 shows
the manner in which an oil spill may be taken in the aquatic environment. In the
case of transshipment facilities on the Great Lakes, these spills will most
likely occur at or near the water's edge. Depending on the viscosity of the
spilled oil, impacts on the land range from few for high viscosity products

Ni'MOSPHERE

P110to-oxidDlion
'Ile
evaporation t rain and ingestion by, and surface pFoto-oxidation LITTORALZONE
fall-out coating on birds and rnammals
o,@rnsolization evaporation
I
SURFACE SL(CK BEACHED OIL
1, microbial oxidation 1. photo-oxiclation
2. photo-oxidatioA - littoral deposition 2. microbial oxidation C01 H20
OIL S $pill --------- 40. 3. polymerization -4 refloating 3. physical accumulation of
4. flushing inert products i("pavement")
5. einulsifi@ation (water-in-oil) 4. physical removal by clean-up
6. physical removal by crows. birds. animals and
clean-up crews. unwary beachcombers
WATER COLUMN
dissolution ingestion

1. sinking of non-buovant ingavion thr ugh substratum I
residues smott I
emulsiheation 2. silt-sedimentation emulsificazion
o NO
il-in-viater)

I PLANKTON orgaruc uptake INTERTIDAL ORGANI
di-.%olution of oil dissolved SIVIS
NEKTON or emulsified in
Water
bubble transport ingestic
and upwolling

bioaccumulation through
ingestion

smotherirg

SEDIMENTED OIL incgestion BENTHIC ORGANISMS
C02 H20--l. microbialoxidation
2. physical accumulation
of inert residues.
3. chemical oxidation
SUBLITTORAL ZONE
UM

@t @TERT
jE

)h
@f

FIGURE 25

FATE OF OIL IN THE MARINE ENVIRONME,4T
(2921

237

to significant for low viscosity products (such as gasoline), which are more
difficult to recover [158]. Impacts on water quality are intensified by the
high solubility of refined prducts and the subsequent toxic impacts on aquatic
ecology. In the cases where oil products are emulsified in the water column,
threats to drinking water derived from wells may result.
Impacts on biota include toxicity of volatile hydrocarbons and smothering
by the heavier fractions of refined products. Effects of oil spills are felt
most severely in nearshore areas, and shoreline communities are thought to suffer
pronounced detrimental effects [158]. Benthic organisms, aquatic vegetation,
and sea and shorebirds are all significantly affected by the range of petroleum
distillates that may be spilled from a storage facility. The effects are numer-
ous and underscore the necessity for strict safeguards against leaks and spills.
In addition to the potential for leaks and hydrocarbon er-assionsl there
are harbor maintenance impacts similar to those described in the proceeding coal
transshipment section. These dredging impacts are significant in the case of oil

transshipment facilities because the sediments in the berthing areas are likely
to have higher amounts of petroleum distillates due to leaks. When these
materials are dredged up, the hydrocarbons may be released into.the water, or the
dredge spoil may have a higher toxicity and present special problems for disposal.
Finally, hydrocarbons and other chemicals may be discharged from ballast tanks
sof ships during the loading of refined products. Their effects further degrade
.water quality in the harbor areas.

(b) Cultural
Cultural impacts of oil transshipment facilities lie primarily in the

aesthetic intrusion and safety categories.
Because of the organoleptic impacts of hydrocarbon emissions and oil
leaks and spills, public attitude is the area most severely affected by these
facilties. Odors from these emissions are generally disagreeable and their
indirect effects may be seen in changes of land value in the vicinity of the
facility. In the case of spills or leaks, drinking water quality may be
negatively affected in an extreme case if ground or surface water infiltration
by low viscosity distillates.
The probability of major accidents is low, but the magnitude is extremely
high. In the event of a major spill, human service requirements for oil spill
contingency plans must be met. These include personnel trained in oil containment

238

and clean-uptechniques, and the various paraphenalia, such as booms.and skimmers
used in the clean-up process. Likewise, the potential for major fires exists and
local fire fighting services must be prepared for special procedures for Petro-

leum fires.

Economic benefits from these facilities are reflected primarily in tax

revenues to the local area. Personnel requirements for maintenance and operation
are low or.negligible and therefore, do not significantly affect employment or
housing.

(5) Refineries

The problems associated with crude oil and product transshipment were
described in the preceding section. This discussion will focus only on those
activities related directly to crude oil refining: air and water emissions,
solid wastes, visual intrusion, and human service requirements. Because expan-
sion of the present Great Lakes refinery capacity is unlikely and "standard"
refinery characterization so difficult, this discussion will be as brief as
possible, touching.only on major issues.

(a) Air quality impacts
The principal air emissions produced during refinery operation are
SOX31 NO X, particulates, and hydrocarbons. In addition, a wide range of organic
and inorganic materials are produced in various quantities:-olefins, aldehydes,
ammonia, hydrogen sulfide, carbon monoxide and others. Table 30 shows estimated
emission rates for a variety of refinery sizes and product mixes.
The technology is presently available to meet national air emission
standards for all major pollutants with the exception of hydrocarbons [506, 370,
and 222]. Measuring the impact of these hydrocarbon emissions is difficult,

however:

Current federal.standards are.based on total hydrocarbon
emissions. One of the major problems in measuring hydrocarbon
impacts is the difficulty in discriminating among "reactive"
hydrocarbons and inert forms. Reactivity is critical to the
formation of photochemical oxidants, which constitute the
major hydrocarbon-related air quality problem. At present,
there is no adequate basis for distinguishing between reactive
and nopreactive hydrocarbons; the subject is being studied by
the fe'deral government [506; pp.II-80].

238a

W A T U It 11 L C U L T U R A L

i) rf-5l CAI. 011MICAL (JMCTFRlr;rlr.S BIDUrACAL CONMITICtis SOCIAL Ermomic
nmw:@'s AQUATW Annmrml(;@z Affb 1118f.tc
ff"IR1.11.0arvAr. AlPRI5111YRIC 111:01119;y rlr.()I.":l intflAN INJERI:Sr 11VALI'll FMrlAlV?lE"r HNInIN(l lN"AMlRlh:jlJPr, LAM) VALOR
FM 'A v I.XQ11) Ar.Rlf3fl,lHlRAL CTfUlrR(:lAl. 1"IMISTRIA1.
Fli M RE!;1hVNTlAl.
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J4

p
Ji
CROMM CLEARING Al"D "=11APING
EQUIPMENT USE I f I I
CrANVELIZATION SHOR INE
OTHER
EL
MODIFICATT ON : An
WATER-KEIA
TED ACTIVITIES
MATERIAL MOVEMENT TO SITE
INFLta OF TEMPOR,%RY WORK FORCE
PUBLIC SERVICE REQUIRE@tZNTS
[AND COK41TTED TO FACILITY
OTHER

HARBOR MAINTEKATICE
WATER.MR)tE MATERIAL MOVDIERT
OVIZ;RLJA6.N*D MATERIAL MOVOIENT
mwdi SERVICE RrWimans
DROCARBOM EMISSIONS
LEAKS AND SPILLS
VISUAL INTRUSION
TTUKAN ACTIVITY D ISRUPTION
ACCIDENTS

OIL TRANSSHIPMENT FACILITIES

Figure 26

239

TABLE 30

ESTIMATED REFINERY AIR EMISSIONS
J1000 lbs/day),

S02 CO NOX HC Particulates
250 MBD, Low Fuel Oil1 97.8 5.6 42.1 90..l 20.8
250 MBD, High Fuel Oil 84.0 5.7 35.1 91.9 17.2
2 3
100 MBD, uncontrolled 274.3 698.2 26.1 265.1 10.4
4 3
100 MBD, controlled 24.0 0.2 22.5 27.0 3.1
5
180 MBD 102.6 4.7 63.2 62.4 23.1

1 [5061
2 [222], without emission controls
3 sox
4 [222], with emission controls
5 [3701

(b) Aquatic impacts
Water-related impa cts of refinery operations arise from two sources:
withdrawal and consumption., and effluents added to the receiving waters. As was
indicated in the refinery description discussion, the dependence on water supply
and wastewater disposal has decreased as water recycling within the facilities
has increased. Water requirements (Table 16) are relative small, generally
less than 10 mgd (15 cfs).. Estimates of withdrawals and consumption'for a
250-mbd facility are:

Withdrawal Consumption
low fuel oil 13.2 mgd 5.4
high fuel oil 10 .5 mgd 4.5
[Source 506)

Waterborne effluents discharged by a refinery include both organic and
inorganic materials. Table 31 presents estimates of pollutant concentrations
in the water return flow from typical refinery configurations.

240

TABLE 31

ESTIMATED WATERBORNE EFFLUENT CONCENTRATIONS (ppm.)
BODs COD Ss Oil Phenols IAmmonial Total P
250 MBD Low Fuel Oil, 43.22 291.72 27.60 12.96@ 0.28 42.05 T
Present Controlsl

250 MBD Low Fuel Oil,
Advan ced controlsi 13.68 74.43 13.68 2.64 0.06 16.71
250 MBD High Fuel Oil, 30.49 206.48 19.69 9.12 0.19 29.44
Present Controlsi

250 MBD High Fuel Oil, 9.75 52.82 9.75 1.92 0.04 11.76
1
Advanced Controls

2
180 MBD- 15 80 10 2 0.1 2 2

1 [5061
2 [3701, best available controls

The impact,of these effluents depends on the water quality an d volume
(flow) of the receiving waters. For large rivers and lakes, very few problems
are anticipated using existing technology [370 and 506]. An analysis of the
effects of a new refinery on a large river in New England concluded:
The effluents from "new source" [existing control technology]
250-mbd refineries appear to pose very few water quality
problems in a large river, when considered independent of
,actual receiving water quality above the point of discharge.
(If the receiving stream immediately above the refinery dis-
charge already contains high concentrations of contaminants,
even minor incremental loading may contribute to poor water
quality.) The 250-mbd "new source" refineries would probably
remove biochemical oxygen demand (BOD), suspended solids (TSS),
and chemical oxygen demand (COD), in greater.amounts than they
would contribute to most large New England rivers, thereby
improving certain aspects of water quality. The concentrations
of phenolics in the receiving waters would approach or slightly
exceed Massachusetts standards [0.001 ppm], but would be well
within the EPA recommended criteria [0.1 ppm]. Ammonia concen-
@rations would exceed the EPA criteria [0.02 ppm], but not those
of Massachusetts [0.5 ppm]. ...In summary, the 250-mbd refinery
modules with "new source" wastewater treatment technology would
appear to pose several minor but no major water quality problems/
in a large clean river [506; pp.II-50].

REFINERY 6PERATION CobeSTRUCTION

CRUDE O!L
MDUCT STOKArz PLANT OPERATION RECEIVI. G
AND S I
u Fri*; A.HD STORAGE

R M -9

@g ;5

SO I L

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AMIENT, MISE LEVELS
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JAIR ';UALITY
ISAFETY

SHORT TER.4

LONG TERM

SHORT MM

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UTTLIT-1ES
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l
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DESIGNATED LANDS

WrKm

241

(c) Cultural impacts
Of all facilities examined in this study, refineries require the largest
operational work force. As shown in Table 20, the estimated employment.during
the operational phase varies from 410-550 persons for a 200-250-mbd facility.
Furthermore,, because average.refinery wages are higher-than-@-average for the
economy.as a whole [506; pp.I-29], the indirect employment and income gains to
the local and regional economy could be significant. Also, the,tendency for
associated petrochemical plants to locate near large refineries could bring in
significant numbers of new jobs and income.
An important consideration is-the land committed to the facility on a
long-term basis, espe cially concerning the uses displaced by it. As the dis-
cussion of refinery land requirements indicates, a facility of the size con-
sidered here would require from 1,500-2,700 acres, a substantial committment of
land on a local and even regional scale.
Other concerns of a site-specific nature are related to aesthetics,
noise, and public safety hazards.
The accompanying activity impact matrix for refineries (Figure 27) can
be used to evaluate potential impacts of a proposed refinery.

242

5. FACILITY COST ANALYSIS

a. Introduction

The economics of site location depend on the variations of costs and
prices over space and time that arise through differences in@resource and pro-
duct availability and distribution. Some of the basic economic factors' that are
considered when examining and comparing energy facility locations are the avail-
ability and cost of capital, infrastructure, labor,'transportation, facilities,
and the natural resources necessary for production and waste disposal, such_ar@

air, water, and land.

The following factors are related to the determination of power plant

location in the coastal zone:

9 The cost of transporting fuel from its origin to the energy facility
and of onsite fuel storage.
The cost of a cooling system (including transporting water from
source to plant).
The cost of product storage and distribution to consumers and the
relationship of distribution to the distance of consumers from the facility.
9 The opportunity cost of using land on the coast for energy facilities

rather than alternative uses.

The cost of environmental controls, including air and water quality
controls and transportation and storage of solid wastes@

Energy facility siting requires tradeoffs among these factors. Table.32
is an example of such tradeoffs developed by the Rand.Corporation for power
plants located in California. Caution should be exercised in using th'--se fig-
ures because of their regional specificity. However, this chart does show some
of the tradeoffs that can be important in siting power plants. These tradeoffs
are of the type that must be made in comparing coastal and inland sites.

b.@ Fossil-Fuel (Coal) Power Plants

(1) Fuel Transportation and Storage
The three major coal-producing areas which serve the Great Lakes Region
are: the Eastern Province, the Interior Province, and the Northern Great Plains
Province (Montana,'Wyoming, North Dakota, and South Dakota). These areas are
shown in Figure 28 [222].

243

Table 32

MISCELLANEOUS COST COMPARISONS

INLAND COOLING VS. ONCE-THROUGH WITH SET -BACK
. Wet cooling towers a s-- 2 mi of set-back
- Dry cooling towers se6 mi of set@-back

WATER CM4VEYANCING VS. TRANSMISSION
1 mi of water conveyancing -_ 1 mi of

transmission lines

LATER COST VS. 14ATER CONVEYANCING COST

Water.cost at $100/acre-ft@F_- 18 mi of

water conveyancing

DRY COOLING T014ERS VS. TRANSMISSION
0 Nuclear: dry cooling tower ;t; 240 mi of

transmission lines.

. Fossil-fuel: dry cooling tower sz::170 mi
of transmission lines

WET COOLING TOWERS VS.. TRANSMISSION
� Nuclear:. wet cooling towerszz: 70 mi of

transmission lines
� Fossil-fuel:- wet cooling towera ;@, 60 mi
of transmission lines
[1491
aNo water or water conveyancing costs in-

There is a great deal of variation in the heat content of coal, depend-
ing upon its origin. Western coal contains 7,800 to 8,800 Btu per pound, with
an average of 8@300 Btu per pound, although some coal has up to 13,000 Btu per
pound [3161; Illinois and Indiana coal ranges from 10,500 to 13,000 (213] Btu
per pound, with an average of 12,000 Btu per pound; and Appalachian coal varies
from 10,000 to 13,000 Btu per pound, with an average of about 12,000 Btu per
pound.
The Great Lakes Basin has four major coal transportation routes. Coal
is transported by unit train from the Appalachian area to Lake Erie ports and
shipped from there to other United States and Canadian Great Lakes ports (51%
of the coal shipped Iout of Lake Erie ports went, to Canada in 1975). The second

Coc3t Proyinco I
I?OCk.Y 110MIGin PfOVIrCO
,NorP,,ar,n Grect Ploins Provinco Intorior Pmvi'nco

Anthracite
Eastarn Plovll7co I
Bituminous coal
nj

Subbituminous coal

Lignite Guff Provinco

Figure 28 Disll---ributioi-i Of' Ui'li'Lcd Statos CoaJ. -Rosources

Source: B1,1YI, 1974: 1-47

245

route is from Illinois and Indiana coal fields by unit train to the Chicago area'
and the lower part of Wisconsin along Lake Michigan. The third and most recent-
ly developed route is from the west by unit1train to the Lake Superior ports of
Duluth and Superior. Currently, coal from the Superior coal dock facility is
shipped to ports on the St. Clair River at the southern end of Lake Huron. Wes-
tern coal may soon be shipped as far as Buffalo. The fourth route, also devel-
oped recently, is by unit train from the west to Minnesota, Wisconsin, Illinois,
and Ohio.

The costs of transportation are important considerations in the future
location of the coal-fired power plants in the Great Lakes Basin. Coal deli-
vered by unit train is less dependent upon coastal siting than coal delivered
by ship or barge. Locations east of Chicago probably would not receive western
coal by unit train because the cost of receiving that coal would increase sub-
stantially, due to problems and costs of transferring the coal to lines of other
railroad companies.
Important economic parameters that affect the cost of shipments are vol-
ume, distance, capacity, speed, return trip cargo, and mode. Delivery of coal
can be less expensive per mile if there is a return cargo, if it is delivered
by unit rather than conventional train, if there are higher volumes, and if the
cargo travels longer distances (although short routes with high volumes,can be
less expensive in some'cases than longer routes). It should be noted that these
factors will change with the location of the receiving site.
A comparison of slurry pipeline and unit train costs per mile (shown in
Table 33) illustrates that their costs are closely competitive. Shipping coal
on the lakes is less expensive per mile than other modes, but shipping dis-
tances are generally greater on water than on land.

(a) Western coal

A comparison between railroad unit train delivery and a combined unit
train-ship delivery of coal presented in Table 34 shows that it is economically
feasible to deliver coal by unit train-ship from the western coal regions to
Detroit. Although not indicated by Table 34, it is also economically competitive
to deliver coal to Buffalo by this method. (Power companies serving the western
New York area are considering this possibility.) The estimated cost of trans-
porting coal to Buffalo by unit train-ship combination is $11.19 per ton; to
Cleveland, $10.36 per ton.

246

TABLE 33

COSTS OF COAL TRANSPORTATION
(1972 ESTIMATES)

Costs
(dollars per 10 12
Type Btu's transported) Distance Assumed Cost per Ton-Mile
(miles) (cents per ton-mile)

Fixed Operating Total

Unit Train 5,100 79,800 84,900 300 0.7

Conventional Train 9,240 145,000 154,000 300 1.3

River Barge 4,850 35,600 40,400 300 0.3

Slurry Pipeline 48,500 20,800 69,300 273 0.6

Ship** .5

Source: (Hittman, 1974, Vol. I, Tables I and 2 and associated footnotes.)
Personal communication, Argonne National Laboratory. [218)
1976 Dollar Figures.

Slurry pipeline is another mode of transportation that can be used to
deliver large quantities of coal. The estimates by Hittman Associates (218)
show unit train and slurry pipeline are economically competitive with each other
under certain conditions. Slurry pipeline is much more specialized and requires
high initial capital outlay. It is considered a serious alternative only when:

� No other transport exists.
� Volumes between origins and destinations are large and steady.
� Pipeline transport offers a more direct route (especially over rugged
terrain).
o The solid coal is reduced to a slurry of fine particles during part
of its normal processing.
o Water for transport is readily and cheaply available.

If one assumes new rail branch-line construction rather than transport
by existing lines, costs per ton-mile for pipelines are competitive under the
following conditions for solids:

Tons per year Competitive with
(in thousands) Railroads Over:

500 All distances
1,000 Distances over 70 miles
2,000 Distances over 150 miles
5,000 Distances over 250 miles
10,000 About the same over 300 miles [3121

247

Table 34

Transportation Cost-, (April- 1974 Dollars)
Per Ton of Delivered Coal

Midwestern Point
(D=Distance in Miles) 1974 1978 1982

P o w d e r R i v e r B a s i n
Chicago (D=1172) $ 8.08 (9.20) 2 9.10 (10.36) $10.24 (11.76)

Detroit 9.96 (9.78) 11.21 (11.01) 12.63 (12.39)@

Milwaukee (D=1257) 8.66 9.77 11.00

Indianapolis (D=1266) 8.74 9.84 11.07

Cincirmat'i (1):=1304) 9.14 (9.67) 10.14 (10.88) 11.37 (12.25)

Clevela@id (D=1512), 10.43 10.77 13.21.

11 a n n A B a s i n

Chicago (D-1128) 7.78 8.76 9.87

Dc--troit 9.66 10.87 12.24

Mlilwauk,ce (D=1213) 8.37 9.42 10.60

'Indianapolis (D=1273) 8.78 9.90 11.14

C-Irtc-1--n-nati (D@1361) 9.40 (10.24) 10.58 11.89 (12.99)

Cleveland (D=1468) 10. 13 10.92 12.84

n t a

Chicago (1>1,.,
-1.0.20 11.47 12.91-

DetroiL (D=-L7/,'-,t9) 12.07 1.3.59 15.30

N@ilwaukee (D=1562) 10.78 12.13 13.66

Indianapolis (D=1585) 10.94 12.32 13.85

Cincinnati (D@1612) 11.30 (11. 53) 12.53 (13.03) 14.09 (14, 67)

Clevc1and (D=1817) 12.54 1A.11 1.5.89

111"ttilroad d-istance -.11easured from the Bandy Railroad Atlas-of the U.S. (Rand McNkilly)
2Njjf@,,,,)crs in parenthesis correspond to rail water rOLItes
f-Argonne National Laboratory has indicated.that these figures have increased three
to four dollars a ton.

248

It is difficult to obtain land for construction of slurry pipelines
without the power of eminent domain. Most states do not have laws granting land
condemnation power for slurry pipelines. Capital construction costs are 70%
[312] of the total costs of-slurry pipeline operation and construction.
Slurry pipelines transport a single substance (coal) from, a single point.
.There is a tremendous risk in building such a specialized line due to changes in
the fuel transportation patterns, coal gasification costs, or costs of desul-
furization. One slurry pipeline in Ohio has not shipped coal since 1958. The
purpose -of this pipeline was to reduce coal shipping cost by offering competi-
tion to railroads. However, the railroads proved to be a more adaptable trans-
portation mode and were more economically desirable.

In the Great Lakes Basin the most likely destination for a slurry pipe-
line from the western United States, from an economic standpoint, would prob-
ably be the Chicago area. Such a facility would probably not be dependent on

coastal locations, unless the coal slurry were transshipped to water carriers.
The uncertainty of origin and type of fuels that will be used in the U.S. in the
future and competition from railroad and barge lines will likely restrict any
possible development of slurry pipelines to the Midwest.
The location of power plants at western coal mines and transmission of
electricity to the Midwest is an exceedingly expensive option, due to the high
cost of building transmission lines compared to using existing railroads for
coal shipment [307].
In summary, the most likely mode of transportation from the western coal
region in the next 5 years is unit train,.or a combination of unit train and
ship. Power plants west of Lake Michigan are not as coastal dependent with res-

pect to deliveries of coal from the western United States as are plants that

must receive western or Appalachian coal transported by a combined unit train-

lake carrier movement.

(b) Eastern coal
Obviously, since Appalachian and Illinois basin coal is transported
shorter distances (50 to 400 miles) than western coal (900 to 1,400 miles) to
reach the Great Lakes Region [5501, eastern coal transportation costs are lower.
Coal from these regions is transported by unit train to power plants in the
Great Lakes Region.

249

The typical costs for transporting coal from the Appalachian field to
..the Great Lakes range from 2.50 to 4.00 dollars per ton in 1973 dollars. These
costs depend upon the origin and destination of coal. The cost of transporting
southern Illinois coal to the city of Chicago is approximately $2.00 per ton,
and to the State of Wisconsin is approximately $4.50 per ton in 1976 dollars.
The@costs vary by contract, type of delivery, distance, and other regional con-

siderations.

(c) Short distance hauling
Power facilities located at inland sites near but not on the coast may
receive fuels from water ports. In this situation, the additional cost of
transporting the fuel is reflected in the cost of locating the facility inland
as opposed tolon the coast. The total cost of the coal may be less if it is
transported to the plant entirely by railroad. In this case, the incremental
cost of locating the facility inland (as opposed to on the coast) may-be less
than it would be if the coal were transported by.water and then from the port

to an inland location.

. There are a number of ways to-transport coal over short distances,
truck, conveyor, slurry pipeline, train, and barge being the most common.

Trucks, although commonly used At mines, have limitations in the
coastal zone. Economic considerations require use of large trucks which are
generally undesirable or illegal for street use. Off-street use of large mine
trucks requires an access road with approximately 53 feet of right-of-way or
6.4 acres per mile from the harbor to the power facility [4001.
Conveyor belts can transport coal and wastes along a fixed route on an
access strip. Conveyors require approximately 30 feet of right-of-way or 3.64
acres of land per mile [4001.
Pneumatic slurry pipeline is a new technology for t ransporting coal.
The pipeline would require a right-of-way of approximately 62.5 feet, but.could.
be buried [400]. For new technologies such as this, costs are subject to change

more rapidly than in existing and proven,technologies.
Unit train transportation of coal for short distrances is expensive be-
cause of high loading and unloading costs in addition to other slowdowns and

Personal Qommunication, Commonwealth Edison

Personal.Communication, Wisconsin Electric, Power Company

250

delays incurred by using a long train over a short distance. According to one
industry source, it would be virtually impossible from an economic standpoint
to move a unit train 15 miles or less. Rail transportation lends itself to
longer hauls.
.Barge transportation of coal from ports and terminals inland is limited
to special areas with water access and inland dock facilities.
'Table 35 presents a cost comparison among methods used for short dis--
tance transportation of coal. Although the estimates are not all for the same
base year, the costs listed are indicative of the relative differences between
modes. The cost estimates indicate the following order of transport modes by
cost per ton-mile for a 5-mile distance, from lowest cost to highest: slurry
(water) pipeline, truck, unit train, and conveyor belt. The (updated) 1974 cost
estimates for unit train and conveyor belt transport of coal suggest that the
two modes are about equal in cost over the.5-mile distance.

Table 35

SHORT HAUT, CQAL:TRANSPORTATION COSTS
TONNAGE COST PER TON-IMILE
MODE YEAR MILES PER DAY (Cents)

T ru c 1972 (estimates) 5-10 4.5 (A)
(July '74)updated 5 4.7 (B)

Conve-ior Belts 1972 (estimates) 5 7.6 (A)
(July '74) updated 5 5.4 (B)

Unit Train (July '74) updated 5 5.4 (B)

Slurry Pipeline May 1975 4.5 (above 2000 tons) 1@-2@ (estilptate.3), (C)

Slurry Pipeline (July '74) updated 5 1.2 excluding
c@
grindin(I equip. (B)

(A) [2221
(B) [211]
(C) [ 218]

*Personal communication, Chessie System.

251

However, additional considerations change the relative ranking of the
alternatives. Unit trains would probably not be used to transport coal from a
coal unloading dock to an-inland electrical generating or storage facility lo-
cated 15 miles or less from the dock because of loading costs and delays. Ad-
ditionally, large trucks presently used to transport coal at mine sites would
probably not be used for the short haul of coal from docking facilities to in-
land sites over public roads and highways due to the weight of the trucks.and
environmental concerns such ag noise and coal dust. Thus, conveyor belts and
slurry pipelines@are the primary modes that would be used to transport coal
from shoreline coal unloading docks to inland sites over distances of 15 miles

o
less,[211, 218, 222]. Additional costs must be considered for slur
r ry pipe-,
lines for grinding the coal for slurry pipeline use and dewatering the coal
slurry (if,pneumatic lines are not used) after movement to destination. There-
fore, conveyor belt transport is the mode most likely to be used for the short
haul transportation of coal from a shoreline dock to an inland facility.

(2) Cooling Systems

(a) Cooling system types
A major determinant in the location of coal power plants is the cost of
providing a sink for waste heat. Water is the primary natural resource used as
a heat sink, although air can also be used in some cases. Costs vary for pro-
viding water and cooling systems to coastal and inland locations.
There are five basic types of cooling systems used for fossil-fueled and
nuclear steam-electric plants: 1) once-through cooling, 2) wet cooling towers
(mechanical and natural draft), 3) cooling ponds, 4) spray channels, and 5) dry

towers.

A nuclear power plant requires 50 percent more cooling water than a coal
plant of the same capacity, due to thedifference in heat rejection rates to the
cooling water and stack losses. This difference for coal power plants is 67% of
that for muclear power plants. As a-result, coal-fired plant cooling systems
cost less than systems used on nuclear plants of the same generating capacity
[21-1, 1491. As a rule of thumb, the cost of the cooling system for nuclear pow-
er plants is assumed to be 50 percent more than that of a coal-fired plant. For
this study's generalized facilities it is 45 percent.
There are two major costs to consider in analyzing cooling@systems: 1)
capital costs (costs of building the system) and 2) operation and maintenance
costs. Once-through cooling systems are used as a standard or base against

252

which to compare other cooling systems. Table 36 shows that there is a loss in
plant efficiency and plant capacity and an increasein auxillary power consump-
tion when other systems are used. These losses and increased power consumption
arereflected in higher operation and maintenance costs.

TABLE 36

COOLING SYSTEM EFFICIENCIES FOR 800 MW COAL-FIRED PLANTS

Once Wet Dry
Thru, Mechanical Natural (Mech)

Lost Capacity Base 1% 1% 9%
(Due to Higher Back Press)
Loss in Efficiency 1 Base 1% 1% 10%
(Increased Heat Race)
Auxillary Power 1 Base 0.5% 0.25% 1.25%
(Consumption)
Land Requirements 2 3-5 2-3 5-7
(Acres)

SouLrce- [1491
Based on various reports, and manufacturer's information
2 These land requirements are for comparative purposes only, not to
calculate total station land needs.

The capital costs in Table 37 were compiled for various cooling systems
from an Atomic Energy Comm-Ission report on power plant costs (3081. Historical-
ly, once-through cooling has been the least expensive cooling method.

Table 37
ESTIMATED COSTS OF TWO-UNIT [1300 MW(e) EACH] COAL FIRED-PLANT WITH ALTERNATIVE

COOLING SYSTEMS
Withovt With Increased Costs Above
Once-Through Cooling Abatement S02 once-through Cooling Costs
Capital- Costsa 945 1150 Base Base
Dollar's per kilowatt b 363 442 Base Base

Wet Natural Draft Cooling Towers

Capital costs 983 1194 38+ 44+

Dollars per kilowatt 378 459 15+ 17+
Hechanical Draft Cooling Towers c

Capital-costs .958 1164 13+ 14+

Dollars per kilowatt 368 448 5+ 6+
a Capital costs in millions of dollars (mid-1974 dollars) Source: [308]
b Capital costs in dollars per kilowatt of plant capacity

253

The cost figures in Table 38 compare alternative cooling systems for
nuclearpowe r plants [511. The figures are updated to.1975 dollars from 1973
.dollars in the manner explained below the table and are based on a lower heat
rejection rate for coal-fired plants than for nuclear plants. The entry en-
titled "Evaluated Present Worth of Cooling System,, Millions of Dollars" presents
the capital costs for the various systems and the entry entitled "Increase in
Generation Cost, Mills per Kilowatt-Hour" gives the operation and maintenance

costs.

From a capital cost standpoint, once-through cooling is the least expen-
sive plant cooling system. At present, however, closed-cycle cooling is re-
quired unless a utility company can prove, on the basis of meeting certain cri-
teria presecribed by the U.S. Environmental Protection Agency (see Section
III.B.l.d.), that its once-through cooling system will not cause-serious envi-
ronmental damage, and thereby receive.a variance from this requireme .nt. The
data for closed-cycle cooling systems show that wet natural draft towers, wet
mechanical draft towers, and spray canals are all economically competitive cool-
ing systems, and the ultimate choice is dependenton site conditions. Environ-
mental impact statements for nuclear and coal-fired plants show a wide variation
in the costs of cooling systems. The reports [51, 181, 203, 235, 279, 308, 312,
149] do, however, indicate that wet mechanical draft towers are currently the
least costly closed-cycle cooling-system. Wet natural draft cooling towers are
closely competitive to wet mechanical draft, but are restricted in use due to
geological and atmospheric considerations. Recent experience with spray canals
shows that operation and maintenance costs have been much higher than reported
in the Nuclear Regulatory Commission's Nuclear Energy Center Site Survey [48-541.

(b) Cooling water supply
A power plant located inland but near the coast could have water trans-
ported to it by pipeline from the Great Lakes. Supplying water for a 1,000 MWe
power plant with a once-through cooling system would require a pipe ten to twenty
feet in diameter. An evaporative cooling system would only require a one to
three-foot pipe. The exact diameter of the pipe needed depends upon many fac-
tors, such as the velocity of the water, the hydraulic resistance of the pipe,
and the volume of water required to ensure proper heat exchange.
The operation and maintenance costs of supplying water by pipeline.de-
pend on pumping costs, which are a function of the height the water is pumpedi

Table 38

COMPARISON OF COSTS AND EFFECTS ON NET CAPABILITY FOR
1200-MWe NUCLEAR GENERATING UNIT
(Figures in 1975 Dollars)

Evaporative Coolinq. Dry @Cooling
Once- I'Viech. Natural Spray lyl 0 r. h u r;, I
Through Draf t Draft Pond Canal Draft D-aft

Plant Cipacib-ility at@ Dcsign
11200 1,177 1,170 1,159 1,156 1,,-22 1,029

4.5 8.0 3.5 3.8
3.3 6.6 7. 0

Fen Po-1.4er Requirercnts,
3.5 14.9

coolin; Syste"i caoita"I
-t, "'lillions 01,
a rsa 14.9 19.5 21.1 35.9 18.1 33.2 40. f

j uated Present 'v@o-th of
co-'114ing [email protected],, mi -1 -11 i 0 n s
of -nr)llars@) 34.,-4 65.1 64.7 94.8 70.1 210.9 20.2.5
Ul

Increase in Genorati on Cost'
s !, e r K i I c@,x a Vt.- - h o u r Base .397 .397 .794 .464 2.307 2.197

The above dollar figures were approximated from 1973 cost data to 1975 cost data by mulLiplying by the
factors indicatc-d below.

a 1973 Cooling System Capital x 1.2
b
19-13 Evaluated Present Worth x 1.3
c 1973 Generation Cost x 1@6
These corrections are approximate based on NECSS st-udy assumptions of: (1) 30 year unit life; (2) 10% discount
rate; (3) 15 mill value of replacement power; (4) 2@.),',' increase in capital cost; (5) 70% capacity factor.
The above chart and dolla r figures were developed Lnd adapted from a Nuclear laegulatory Agency Commission report
[511, and from Nuclear Regulatory Cormnission staff.

255

the distance from the water source, the type of power plant, and -the.type of

cooling system. Table 39. shows how operation costs vary by distance from water
sourceand height that the water is raised. The cost of operation increases
drastically with the distance and height that the water must be pumped. In
general, power plants with once-through cooling will be used when the elevation
of the site does not significantly increase operating costs. The operating costs
for conveying water for closed-cycle cooling will not generally affect the selec-
tion of a site. In the Wisconsin Electric Power Company Environmental Report on
.the Pleasant Prairie Power Plant [552], three of the potential sites located
along Lake Michigan would not have used once-.through cooling systems due to the
height to which the water would have had to have been pumped and the distance

from the plant to the,end of the pipe in the-water.

Table 39

OPERATION COSTS FOR WATER CONVEYANCE BY PIPELINE,
BY DISTANCE, AND BY TYPE OF FACILITY FOR A 1000 MWe PLANT
(Mills/kWh)

C 0 A L N U C L E A R

(HEIGHT WATER IS CONVEYED) 3 FT. 50 FT. 100 FT. 3 FT. 50 FT. 100 FT.

DISTANCE FROM
WATER SUPPLY CLOSED CYCLE COOLING

1,000 Feet .6024 .0168 .0315 .0031 .0419
I Mile ..0089 .0230 .0380 .0112 .0300 .0500
5 Miles .0409 .0550. .0700 .0512 .0700 .0900

ONCE-THROUGH COOLING

1,000 Feet .0776 .4536 .8536 .0993 .5693 1.069
1 Mile .3070 .6830 1.083 .3960 .8660 1.366
5 Miles 1.439 1.815 2.215 1.360 2.180 2.830

NOTE: 1972 dollars are projected to 1985 dollars at 3% for operation costs.
The differential between:.nuclear and coal operation cost for water
conveyance are due to the higher BTU/Kwh for nuclear power plants.
Figures are from formulas derived by a Rand Corporation Report Electrical
Generating Cost Model For Comparison of California Power Plant Siting
Aiternative@s, Rand Corporation, 1973, p.24.

Capital costs for pipelines vary directly with the diameter of the pipe,
length of pipe, type of cooling system, and cost of land. Both evaporative

256

cooling and once-through cooling systems require intake and outfall pipes.
Table 40 shows the cost of pipelines for different cooling systems.

TABLE 40

WATER PIPELINE COSTS

NUMBER OF 1000 MW CAPITAL COSTS YEAR OF
COOLING SYSTEK POWER PLANT UNITS PER MILE DOLLAR

Evaporative Cooling
System 1 $158,400 1985 from
1.972-1/ at
5% inflation
2 units (1234 MW) 1,020,000:@' 1974
4 units (4800 MW) 1,071,428 1973
1 223,214-4/ 1973

Once-Through cooling 2 20 000,000 19761./
System 1 10:000,0006/
1 9,963i360 1985
estimated from
19793/

Communication, Detroit Edison
Communication, Commonwealth Edison
1985 dollars estimated at inflation race of 5% per year. [311]
Th. proportion of cost for a 1000 MW unit of the 4800 MW - 4 unit costs.
Cost for I pipeline would be much higher than the figures indicate, but
it is assumed that if power plants were located inland from the coast,
then more than one plant would be built to take advantage of these
economies of scale.
5/ The average cost per mile derived from cost daca for a five-mile pipeline.
[573, 5741
6/ The proportion of cost for a pipeline serving a 1000 MW unit of a 2000 '-4W 2
unit plant. The cost for one pipeline would be much higher than chis figure
indicates, but it is assumed that if the power plant were located inland, then
more than one unit would be constructed to take advantage of economies of scale.

In general, once-through cooling would not be used for a facility loca-
ted two or more miles inland. For example, cooling system costs for a 1200 Mwe
coal-fired power plant with a once-through.cooling system located- two miles in-
land are shown in Table 41 to be approximately the same as those of a plant
with a closed-cycle cooling system, because of the rapidly increasing operation
and maintenance costs of the former system, Costs for specific sites vary de-
pending upon site characteristics.

257

Table 41
COST OF PROVIDING WATER TO A COAL-FIRED POWER PLANT
WITH 1200'MW CAPACITY SITED TWO MILES INLAND

ONCE-THROUGH COOLING

Pipeline Costs
A. Capital $20,000,000 (a)
B. Operation 0.5279 Mills K,,h(b)(d)

CLOSED CYCLE COOLING (MECRANICAL.DRAFT)

Pipeline Costs
$500,000
A. Capital $2,000,000(e)
B. Operation 0.0153 Mills Kwh (b)(d)
The cost of the mechanical Draft System which is more
than the Once-through Cooling System.

C. Capital .5 30, 700,000

D. Operation and
Ih (c)(d)
Maintenance 0.397 Mills Kw
(a) 1976 dollars
(b)
1975 dollars adjusted at 3% per year from 1985 dollars to"1973
dollars, and increased at'9.3% per year to 1975.
(c) 1975 dollars
(d)
Pumping costs assume 3 ft. per mile which maximizes the use of once-
through cooling.
(e) 1974 dollars

If a variance to current Environmental Protection requirements is not
obtained@or if once-through cooling cannot be used, the principal cost of lo-
cating a power plant that uses Great Lakes water one mile inland-from the shore-
line would, then be the cost of conveying water for an evaporative cooling system,
or about $250,000 to $1,000,000 per mile. "This is not to say that such vari-
ances cannot be obtained at a reasonable expenditure of time and resources by
the utility. Section 316[a] (of the Federal Water Pollution Control Act Amend-
ments of 1972) exemptions to the,closed cycle cooling requirements have been
granted to Great Lakes'stations."
If a given site would qualify for a 316[a] exemption, the differential

Communication, Commonwealth Edison

258

cost of locating inland would be the cost of conveying water for a once-through
cooling system up to a distancL- of two miles. This cost.is approximately
$10,000,000 per mile and 0.307 to 0.396mills per kx@h, assuming a 3 foot change
in elevation. When a closed-cycle cooling system has to be used, the differen-
tial cost is that of using a closed-cycle system versus a.once-through cooling
system. This cost is $30'to $45 million for the differential in capital costs
of the systems, 0.397 to 0.517 mills per kwh for the differential in operation
and1maintenance costs of the two systems, and $250,000 to $1,060,000 per mile
for the water pipeline costs. In any event, economics have a strong bearing on
the type and design of cooling systems.

(3) Electrical Transmission System
The electricity produced by power plants is consumed at load centers
which are,primarily in the urbanized areas of the Basin. The cost of transmit-
ting the electricity t o the load centers from the power plant is primarily de-
pendent upon the cost of thetransmission facilities. These costs encompass
transmission lines, their associated terminals., substations, and step-down
transformers at major load centers. In recent years the location of power
plants in relation to regional and instrastate transmission lines has been co-
ordinated to minimize costs and increase electrical reliability- Power gen-
erated in urban-metropolitan coastal areas is generally consumed within the

coastal zone.
There is no simple relationship between a transmission facility's cost
and distan Ice of p.ower plants from the loadIcenters. In specific cases,'the
cost may be increased or decreased by locating a power facility inland rather
than on the coast. It is important to consider the location of existing load
centers and transmission lines when examining a n inland location for a power
plant. If the transmission lines have'been placed'inland for environmental,
social, or economic reasons, it may be less expensive to,locate the power plant
inland. If no such lines exist, it probably would be more economical to locate
on the coast. There 'are more potential inland sites near load centers (urban

areas).
The cost of transmission facilities varies widely.,
Estimating unit cost is made difficult by 1)regional differences
in line construction cost due both to labor rates and-the type of

Communication, Detroit Edison

259

terrain; 2) differences in design at the same voltage rate; and
3) rapidly escalating costs [236].
Two linesIof the same voltage level and length may have,substantial,differences
,in cost because one may have to follow an irregular right-of-way, requiring in-
stallation of costly angle structures and dead end towers, in contrast to lower
cost tangent towers which can be used on straight rights-of-way.
As is indicated in Table 42 the "capacity of a transmission line at
any.voltage is'a_function of the length of the line and its location in.the
bulk power network." Figure 29 graphically presents the variations in power
capacity with voltage and line length.
Transmission 1ines, like other structures, have increased in cost at
disproportionately higher inflation rates than the average price indexes. Over-
head 765 kV lines are projected in various studies to cost in 1975 dollars be-
tween.$200,000 and $500,000 per mile, excluding land costs-. It was estimated in
the Nuclear Energy Center Site Survey (1975) that it would cost about $400,000
per mile,on the average for the west and east central regions of the United,
States and $500,000 per mile for the eastern regions of, the United States for
a 765.kV line'[51].
In summary, there is no apparent relationship between transmission line
cost and proximity to load.centers. Specific site characteristics will deter-
mine the cost of locating inland versus locating on the coast, and no trends

have been found at this time.

(4) Land
The value of land is a function of the availability of land offering a
similar mix of resources, and not necessarily a function of,the amount of land
needed for energy facilities. The coastal zone has unique characteristics and
features, whose value has often been assumed to be greater than that of an
equal sized inland property. The value of theseunique characteristics and
features result from various demands on the coastal zone, many of which are in
competition with one another, such as recreation, tourism, water supply, and
multimodal transportation (ship and train), The value placed on this land due.
to its cultural, psychological, and aesthetic resources is greater than the
value that these physical uses would indicate. For example, a house located
on a lot on thecoast near West Olive, Michigan costs $60,000 1549). The cost

Communication, East Central Area Reliability Agreement

260

'iABLL 42

C6sts and Power Carrying Capabilities of Overhead
Transmission Cixcuits

Costs are estimated as of January, 1974*

1. Voltage: Nominal 345kV' 500kV 765kV
Maximum 362kV 550kV 800kV

- MW
2. Cztpacity: 50 Mile 1000MW 240OMW 5500,
250 Mile -625MW 150OMW 3300YMW

3. Land: Route Width 150 ft. 1.75 ft. 2,00 ft.
Acres/Mile 18 21 25

4. Line Cost: Million $/Mile East 0.081 0.151 0.236
West 0.059 0.113 0.206
Central 0.051 0.059 0.102

5. Terminal Cost: Million $/Line
,excluding transformers)
50 mile 3.175 4.900 8.700
250 mile 4.415 6.475 13.S-'-"?O

6. Incremental Terminal,Clost
(Park less disp6rsed)'Milli,on $/Line
50 mile 0 5.525
250 mile' 1.575 10.325

7. Transformer $/MW
Generator Step Up 1900 1900 1900
Step Down (Auto) 2600 2600 2600

.8. Power Losses: Percent of yearly
energy delivered per iOO miles 1.0% 1.0% 1.0%

CAUTION: As of April 1975,these costs, which were derived
from industry reported values i,n the early
1970's, appear to be or 1/3 of their present
value s@.'

[1491

261

FIGURE 29

TRANSMISSION LINE CAPACITIES

5000
THERMAL
-765
LIMIT

4000-

3000

TYPICAL
--500 LOADINGS
T. L.

w 2000

345
1000 T.L.

-230

0.
0 100 200 300

MILES

262

of the lot was $30, 000 of which 000 was simple land, value (similar to inland
land costs) and $25,000 was aesthetic value [549]. The implications of these
figures are that coastal property is more valuable than non-coastal property
primarily because of its unique aesthetic resources. The benefits from this
land realized by the public for aesthetic, recreational, or psychological rea-
sons versus*the benefits gained by public and private uses for ports and ter-
minals,'power plant siting, and cooling water are important resource management
considerations..
In summary, although difficult to estimate, the value of coastal land
is generally assumed to be greater than non-coastal land.

(5) Environmental Controls

(a) Air
The major air pollutants from the coal-fired power plants are SO 2 (Sul-
fur dioxide), NO 2 .(nitrogen dioxides), and suspended particulates. The National
Ambient Air Quality Standards and New Stationary Source Performance Standards
place restrictions on the emission of these air pollutants. The major tech-
nological problem for coal-fired power plants has been meeting the SO 2 stand-
ards and auxiliary to this, particulate emission standards.
Two primary ways to meet the sulfur dioxide emission standards in the
near future are flue gas desulfurization and use of low sulfur coal. In the
future, fluidized-bed boilers and coal gasification may be important. Flue gas
desulfurization technology is now in operation on several demonstration coal-
fired power plants; however, the technology has not proven to be reliable in
all cases. There are several types of flue gas desulfurization systems: wet
limestone, dry limestone, magnesium oxide, catalytic oxidation, double alkali,
and citrate systems, among others.
Environmental Protection Agency information in Table 43 shows the lat-
est estimates of cost for different flue gas sulfur control technologies, ar-
ranged by size of power plant. The Table shows that the cost is between 2.7
and 4.2 mills per kilowatt-hour for limestone flue gas desulfurization, cur-
rently the least expensive of the technologies [336].
The other major method of controlling sulfur emissions is through the

use of low sulfur coal. There are two sources of low sulfur coal: the western

states and the Kentucky-West Virginia region. Most of of the West Virginia and

Table 43
SUMMARY OF TOTAL AVERAGE ANNUAL REVENUE REQUIREMENTS OF
FIVE LEADING FLUE GAS DESULFURIZATION PROCESSES
1978 Cost Basis,

-i b
Total average annual rovenue requirer.,cntsz
YLars Limestone Lime Magnesia Sodium ca'.-Ox
Case life -M $ Mills/k@@ $ @Jills/kllh M $ Mills/kWh M $ Mills/kWli M $ Mills/kMn

Coal-fired power unit
90% S02 removal; onsite solids disposal
200 XW, new, 3.5% S 30 5,883 4.20 6,362 4.54 7,036 5.03 9,238 6.60 6,000 4.29
200 existing, 3.57 S 20 5,686 4.06 7,150 7,257 10,868 7.76 8,263 5.90
6.34 17,765 5.09
500 @W, existing, 3*.5% S 25 11,854 3.39 14,528 4.15 14,052 4.01 2@'189
500 @@W, now, 2.0% S 30 10,625 3.04 11,145 3.!8 11,572 3.31 14,549 4.16 12,681 3.62
550 K.4, now, 3.5% S 30 11,937 3.41 12,758 3.65 14,082 4.02 5.37 12,766 3.65
5CO M,,T, new, 5.0% S 30 13,105 3.74 14,377 4.11 16,448 4 * 70 22,858 6.53 12,844 3.67
1 38,813 5.54 31,133 4.45
i
1 3.40 23,169 3.3,
,000 cxistinp,3.5% S 25 19,711 2.82 23,819
1,000 MW, new, 3.5% S@ 30 19,163 2.74 20,570 2.94 22,789 3.26 31,1S6 4.46 20,534 2.93
ON
80' SO? removal; onsite solids disposal LJ
500 'e'U, new, 3.5% S 30 11,319 3.23 12,206 3.49 13,406 3.83 17,425 4.98
90X S02 removal; onsite solids disposal
(existing unit without existing
particulate collection facilities)
500 @'N, existing, 3.5% S 25 14,376 4.11 14,826 4.24 16,639 4.75 24,995 7.14 19,480 5.57

Power unit oln-stream time, 7,000 hr/yr. Midwest plant location, 1978 revenue requirements. Investment and revenue requirements for disposal
of flyash excluded.
Th.ese revenue rccluiremonts reflect capital investments shown in Table I (updated); byproduct credit and sludge fixation costs excluded.

3361

264

'Kentucky low sulfur coal is used for metallurgic processes although some has
been.used in the Midwest by power plants."
The cost of westernlow sulfur coal,,the major source of low sulfur
coal for the Midwest utility market, is projected to increase at 3% per year
between 1975 and 1980. After 1980, the price is expected to remain relatively
constant. The cost of transporting coal has been a major component of this
increased cost. This cost has roughly increased three to four dollars a ton
more than the figures reported in the coal transportation section (Section
IV.B.2.a). The cost of flue gas desulfurization, on the other hand, has re-
cently stabilized and is not expected to increase as rapidly as in the past.
The price of western coal depends upon several parameters; the cost of,
transDortation, profit margins on low sulfur coal, whether air pollution stan-
dards are enforced on time and without variances, the capability of mining and
transportation facilities to expand, and others.
An Argonne National Laboratory study on the differential in cost be-
tweeh low sulfur coal and flue gas desulfurization. found it to be less than one

mill per kwh, with low sulfur coal being slightly cheaper. Due to this small
variation in the cost differential between the two majorsulfur controls, the
method which will be used depends upon site characteristics affecting the trans-
portation, origin, and destination of coal, duration of contracts, and company

policy.
There is an interrelationship between the cost of SO removal and par-
2
ticulate removal. For example, the use of certain low sulfur coal will in-
crease the emissions of particulates, and the cost of particulate removal.
Another method for reducing sulfur emissions is physical and chemical
coal desulfurization. When used with medium sulfur content coal, the resulting
fuel can meet existing standards. The availability of medium sulfur coal re-
strirt-9 the use of this method (14% of the United States reserves) [2191.

(b) Waste disposal
Coal-fired power plants produce large quantities of solid waste; out of
a ton of coal delivered to the plant, 10 to 30 percent is residual waste, main-
ly in the form of fly ash. Coal with an ash content of 15 percent would.pro-
duce approximately 40 tons of waste per hour or approximately 250,000 tons a

Communication, Argonne National Laboratory

265

year for a 1000 MWe power plant. A large land area (100-133 acres) filled to a
depth of 25 feet is necessary'for disposal of the waste over a 35-year useful
life for a 1000 MWe plant [2211. In recent years, fly ash has been sold as
filling material on local markets for asphalt and structural fills or embank-
ments. In the United States in 1974, 16.3% of the fly ash was sold at prices
ranging from two dollars a ton to as much as six dollars a ton, depending on
the market supply and demand and the region. In the future,, scarce metals
such as magnesium,'chromium, titanium, and vanadium may be extracted from the

ash.

,A power plant located near the coast may transport the waste to an in-
land location for disposal. The mode of transporting the waste inland varies,
but tenerally pipelines or trucks are used. "The tariffs currently approved
by the Michigan Public Service Commission for transporting fly ash are 690,/ton
for up to five miles and $1.32/ton for distances up to 5-20 miles." The
transportation cost is only one of the costs associated with transporting the
waste to an offsite location. The other is the incremental cost (the extra
cost above onsite disposal costs) for extra onsite or offsite preparation, dis-
posal, and storage of waste.
"Annualized costs for waste disposal, a diffi-cult problem,, ranged from
$1.00 to $7.00 a ton, and $3.00 a ton is used" [432]. Information from Detroit
Edison shows the total cost of transporting fly ash wastes and disposing of

them offsite to be as follows:

A. Dry storage in silos and trucking to offsite disposal area.
Assume sufficient silo capacity for three-day storage.

Levelized Annual Cost: $3.96 per ton, 5 miles to disposal site
$5.02 per ton, 20 miles to disposal.site'

B. Flyash from hoppers mixed with water and pumped to small on-
site reservoir. Dewatered sludge removed and trucked to off-
disposal area every two years.
$2.64 per ton, 5 miles to disposal site
$3.71 per ton, 20 miles to disposal site

C. Flyash from hoppers mixed with water and pumped directly to
permanent disposal site.

Figures were reduced from a 3000 'MWe plant, which would require 300-400 acres'.
Electric World, May 1, 1976; Volume 185, Number 9.
Communication*, Detroit Edison.

266

Levelized Annual Cost: $2.53 per ton, 5 miles to disposal site
$3.32 per ton,, 20 miles to disposal site

It sh'ould be noted that these costs are actually costs per
ton of fly ash produced. The increased tonnage of ash-water mix"
tures or any additional costs due to lime/sulfur slurries have
not been estimated.
The differential cost per ton of disposing the fly ash offsite as opposed to
onsite is the cost per ton of offsite disposal (as in the chart above) minus
the onsite d4sposal cost per ton. The major costs contributing to this differ-
ence are those for transportation, onsite equipment, cost of disposal site, and
site preparation. The cost of onsite disposal of fly ash varies from site to
site and depends upon land costs, selling price and alternative uses for fly
ash, and transportation and storage costs.

If limestone scrubbers are used for the removal of SO residual waste
2
volumes will be expanded by one to two times the present amount each year [231].
Special problems will be.encountered in disposing of the sludge from limestone
scrubbers. Sulfur removed from the gas can be sold at up to $15.00 per ton
[432]. '.'The EPA has estimated that sludge for a 1000 MWe coal-fired power plant
[assuming three percent sulfur, 12 percent fly ash, 6,400 hours/year operationj
will require 269 acres for solid waste disposal or 377 acres necessary includ-
in g fly ash" [4321. "As a rough guide, EPA believes that if the cost of sludge
disposal exceeds $4.00 to $6.00 a ton [wet basis], a regenerable process which
covers a useful byproduct will be more economical than a nonregenerable pro@
cess" [432]. In many instances, the preliminary data which EPA compiled on
disposal waste indicated that offsite disposal is cheaper than onsite disposal
[432]. In reality, the costs associated with offsite disposal depends upon
specific site factors and regional conditions.
In summary, waste disposal with limestone scrubbing could be-a major
problem.in terms of land required. There is no obvious pattern related to the
extra cost associated with offsite disposal as opposed to onsite disposal.

c. Nuclear Power Plants

(1) Fuel Transportation and Storage
While the cost of transporting fuel can have a major effect on the 10-
cation of a coal-fired power plant, this same factor has but a minor effect on

Communication, Detroit Edison.

267

the location of a nuclear power plant [50].
The cost of transporting nuclear fuel is approximately $4.00 to $5.00 per
kilogram of uranuim, or only one to two p ercent of the total costof fuel.
Table 44 shows that the transportation requirements for nuclear power
plants are low over the entire nuclear fuel cycle.
The implications of risk and impact on coastal waters from'the,trans-
portation of nuclear materials is out of the scope of this report; however.' the
implications are extremely important and deserve further examination.

TABLE 44
ANNUAL SHIPMENTS OF RADIOACTIVE MATERIALS TO AND FROM AN OFFSHORE NUCLEAR
POWER STATION (One 1100-MWe Pressurized Water Reactor)

Approximate number of shipments per year
Operation
Barge Land

Fresh (unirradiated) fuela
1. Fuel fabrication plant to 6 trucksb
shore transfer point
2. Shore transfer point to 1 to 2 bargesc
offshore power plant
Spent (irradiated) fueto
1. Offshore power plant to 2 to 5 bargesc
shore transfer point
2. Shore transfer point to 60 trucks or 10 rail cars
fuel reprocessing facility

Solid radioactive wastes
1. Offshore power plant to 2 to 5 bar9W
shore transfer point
2. Shore transfer point to 46 trucks or 11 rail cars
licensed radioactive waste
disposal facility
aThe shipment of .2mpty casks for fresh and spent fuel will req uire
essentially the same number of shipments as the number of loaded casks
indicated in the table. However, the radioactivity hazard will be negli-.
gible.
b1nitial loading of reactorrequires about 18 truckloadsof unirradiated fuel. Shipment
of unirradiated fuel by rail is usually ruled out because of length of transit time.
'Number depends on capacity of barge. [5621

(2) Cooling Systems
A major determinant in the location of nuclear power plants is-the cost
of providing a cooling medium. Water is the primary natural resource used as
a cooling medium, although air can also be used. There are different. costs in-
volved in providing cooling water to coastal and inland locations.
As was the case with coal-fired plants, both capital (costs of building
and of the components of the system) and operation and maintenance costs must
be considered. The use of more sophisticated cooling systems results in
greater losses in efficiency and capacity, and increased auxiliary power con-
sumption than the use of once-through cooling. Table 45 shows that the ef-
ficiencies for nuclear power plants vary with the cooling method. Table 46

268

TABLE 45
COOLING MODE. EFFECTS ON NUCLEAR PLANT EFFICIENCY

Typical Nuclear
Cooling Mode Plant Efficiency

Evaporative Natural Draft Tower 32.7
Evaporative Mechanical Draft Tower 32.6
Cooling Pond 32.8
Once Through (River) 32.9
.Dry Tower - Mechanical Draft 28.1
DryTower - Natural Draft 28.6
Source: [149]

Table 46

..COQLINC,.MODE EFFECTS-ON FOSSIL/NUCLEAR PLANT OPE.RATION

F01SSIL/HTGR - 800 MW BWR/PWR - 1000 RW
Once Wet Dry Once Wet Dry
Thru Mechanical Natural (Mech) Thru Mechanical Na Lural (Mech)

Lost Capacity

(Due to Higher Back Base 1% 1% 9% Base 1% 1% 15%-PWR
Press). 1-7%-13WR
Loss in Efficiency(l)

(Increased Heat Rate) Base 1% 1% 10% Base 1% 1"/ -M-PWit
Auxiliary Power(P 17%-BWR

Consumptien Base 0.5% 0.25% 1.25% Base 0.8% 0.4% 2%
La nd Requirement (2)

(Acres) 3-5 2-3 5-7 5-7 3-5 7-10

(1)Bsed on various reports, studies, and manufacturer's information
(2) These land requirements are. for comparative purposes only, not to calculate total station land needs.
[1491

shows losses in efficiency and capacity and the increase in auxiliary powercon-
sumption due to various cooling systems. These losses are reflected in higher
operation and maintenance costs.
The capital costs in Table.47 were compiled for various cooling systems
from an Atomic Energy Commission report [308].. Historically, as shown in the
Iable, once-through cooling has been the least expensive cooling method.
The cost figures given in Table 48 show comparisons among alternative

269

TABLE 47

ESTIMATED COSTS OF TWO-UNIT [130OMWe EACHI.LWR PLANT
WITH ALTERNATIVE COOLING SYSTEMS
(cooling Systems. Cost i .n.Brackets for One-Unit [1300 MWe'j
LWR Power Plant with Alternative Cooling Systems)

Increased Capital costs
Once-Through cooling Above 'Once-Through Coolirrg
Capital costsa, 1410 BASE
Dollars per kilowatt b 542 BASE

-Wet Natural Draft cooling Towers
Capital costs 1434 24+
[7221
ll+
Dollars per kilowatt 551
[5561

Wet Mechanical Draft Cooling Towers

Capital costs 1406 -4

Dollars per kilowatt 541 -1

a
Capital costs millions of dollars mid-1974 dollars for a plant finished in'1981
b Capital costs in dollars per kilowatt of plant capacity

[3081

cooling systems for nuclear power plants [511. The figures in the table are
updated to 1975 dollars from 1973 dollars in the manner explained at the bottom
of the table. The line indicating "Evaluated Present Worth of Cooling Systems,
millions of Dollars" shows the capital costs and "Increase in Generation Costs,
Mills per Kilowatt-hour" is the operation and maintenance costs.
Once-through cooling is the least expensive system but currently is not
used on new plants unless a variance is granted under Section 316(a) of the
Federal Water Pollution Control Act Amendments of 19,72.
As the data shows, wet natural draft towers, wet, mechanical draft towers,
and spray canals are all competitive alternative cooling systems depending upon
the site location. Further discussion of this �ubject is presented under Sec-
tion IV.A.5.b.(2) of this report.

(3) Electrical Transmission Systems

No discernable differences between eldctrical transmission 'lines for
nuclear power plants versus coal power plants''could be:detedted. For dis-
cussion see Section IV.A.5.b.3.

TABLE 48

COMPARISON Or COSTS AND EFFECTS ON NET CAPABILITY FOR 1200-MWe NUCLEAR GENERATING UNIT
USING ALTERNATIVE COOLING SYSTEMS
(1973 COST DATA)

Evaporative Cooling. Dry Cooling
Once- Mech. Natural Spray Mech. NaturaT
Through Draft Draft Pond Canal Draft Draft

Plant Capability at Design 1,200 1,177 1,170 1,159 1,156 1,022 1,029
Conditions, Megawatts

Pumping Power Requirements, 4.8 9.5 10.2 6.5 11.6 5.1 5.5
Megawatts

Fan Power Requirements, - 5.0 - - 21.6 -
N.egawatts

Cooling System Capital 18.0 23.6 25.5 43.4 21.8. 40.11 49.1
Investment, Millions of 21.6 28.32 30.6 52.0 26.16 48.12 58.92
Dollarsa

Evaluated Present Worth of 38.3 72.6 72.1 105.7 78.1 235.2 225.8
Cooling Sy@tem, Millions 49.79 94.38 93.73 137.41 101.53 305.76
oil Dollarsu 293.54

Increase in Generation Cost, Base 0.36 0.36 0.72 0.42 2.09 1.99
i'Mills per Kilowatt-hourc .576 .576 1.152 .672 3.344 3.184
Nctc: For approximate correction to Ja nuary 1975 costs multiply by factors as indicated.

aCooling System Capital x 1.2.
bEvaluated Present Worth x 1.3.
cGeneration Cost x 1.6 [5 11
These corrections are approximate based on NECSS study assumptions of: (1) 30 year unit life; (2) 10% discount rate; (3) 15 mill value of replacement
power; (4) 2M increase in capital cost; (5) 70% capacity factor.

271

(4) Land

No discernable differences between land or land value for nuclear power
plants versus coal power plants could be detected. For discussion, see Section

IV.A.5.b.4.

(5) Environmental,Controls
"It is recognized that there exista number of controversial issues re-
garding the safety-environmental-public health aspects of nuclear,power plants
and accompanying fuel cycle operations" [1481. This section.is concerned only

with the cost of environmental controls which affect site location and resource

utilization in respect to the coastal waters.
The cost of controlling accidental releases of radioactive material in-
to the coastal waters or land through plant operation and f-uel transshipment
would not affect the location of a nuclear facility [50, 148].
Radioactive material is stored on the site of a nuclear power plant.
Irridated spent fuel elements.require the strictest containment due to their
extreme toxicity and radioactivity. The storage of such material is not a
significant cost in locating a power plant [148].
The irridated spent fuel elements may, in the future, be transported to
.regional reprocessing plants. These reprocessing plants may receive shipments
by truck, railroad, or barge.

It is beyond the scope of this report to consider risks and impacts of

these activities on the coastal zone or waters. However, it is recommended
that future research be conducted on the impact of these activities on the
coastal zone and waters, especially in respect to possible barge shipment of
irridated spent fuel to reprocessing plants.
In summary,.while an initial evaluation indicates the costs associated
with nuclear power plants' environmental safety are not a significant factor
in determining site location, more detailed research on both impacts and costs

in relation to coastal waters would be beneficial.

Role of Transportation in the Nuclear Fuel CycleL Energy Research and
Development Administration presented at the July meeting of Michigan Envi-
ronmental Review Board.

272

d. Fuel Transshipment and Storage Facilities

(1) Introduction
In the following discussion, only coal transshipment and storage fa cili-
ties are considered, because the potential magnitude of their possible effects
on the Great Lakes coastal zone is the greatest. The capacity.of coal trans-
shipment and storage facilities in the Basin varies from 2,000 tons of coal per
year to as large as 20 million tons of coal per year.
This section examines the cost of a fuel transshipment a nd storage fa-
cility where the storage pile is inland from the port. The cost of transpor-
ting coal inland by conveyor belt for the distance of five miles is 5.4 cents
per ton mile. The cost of moving 5.6 million tons of coal per year (the
amount needed for two 1000 MWe power plants) one mile is $302,40b. It is un-
likely that coal would be transported only one mile inland to a storage area,
due to the high cost of handling for short transport. It is,more reasonable to
assume that coal.would be transported longerdistances.

(2) Land.
Coal may be transported inland to conserve the use of coastal proper-
ties. In general, a coal transshipment and storage facility maintains a 90-day
supply; this.varies depending upon the accessibility of the facility to incom-
ing coal during the winter. The amount of land required to store a 90-day sup-
ply of coal (1,400,000 tons for two 1000 MWe power plants) at 30-40,000 tons/
acre is 30-40 acres.. Approximately one to two acres would-be necessary for
transient storage. A transient storage area at the port is necessary because
it is uneconomical for a conveyor belt several miles long-to have a transport
capacity equal to the rate at which a barge.or ship may be unloaded.
In summary, transporting coal inland saves only about 28-38 acres of
coastal land for a facility with a capacity of 5.6 million,tons per year.

e. Refineries

As was indicated.in the discussion of refinety site requirements and
considerations in Section IV.A.3, the economics of refinery location is a com-
plex issue that must be. considered at a national level. For example, an

The cost data is based on the analysis in Coal Fuel Transportation and
Storage (Section IV.A.5.b.l.)

273

analysis [in 312 based on material from 370] compares costs of supplying re-
fined products to the east coast from refineries located on the east coast,
the Gulf,Coast, and offshore (i.e., outside of the U.S., such as the Carr ibbean.)
As the figures in Table 49 show, the cost of refined products on the east coast
(Petroleum Administration for Defense, PAD, District I), is lowest if the crude
oil is refined outside of the United States and shipped to the market area.
While this is only one example, it does indicate that an evaluation of refinery
economics must be done at a supraregional scale.

f. Facility Cost Discussion
This section is a summary of previous economic material on coal-fired-
power plants, nuclear power plants, ports and terminals, and refineries. Table
.50 is a matrix summary of economic material compiled in the previous sections.
The assumptions of the cost data are listed in the footnotes. It is important
when using this material to review the footnotes, and to keep the material in
context by reviewing the section where it originated.
The first column titled "Land" reflects the average amount of land that
coal-fired plants, nuclear power plants, and refineries occupy. The categories
for the different cooling systems under nuclear and coal"fired power plants

show the average amoung of land different cooling systems occupy.
The."Plant" column reflects plant capital costs for the different fa-
cilities. It is important to note the size and capacity of the nuclear and
coal-fired power plants as they differ from our idealized 100OMWe power plant.
The "Cooling System" column indicates two sections--water provision and
plant system.. The water provision section indicates that both capital and
operation and.maintenance costs for conveying water to a cl6sed-cycle cooling
system are less expensive than to a once-through cooling system. The plant
system indicates that both capital and operation and maintenance costs are
more expensive for closed-cycle cooling than once-through'cooling. The cost
of locating a power plant inland versus on the coast depends'upo,n many site-
specific factors and different configurations of the components of the cooling

systems.,
The fuel column is divided into three sections: short haul transport . a-
tioh, long haul transportation, and storage. The short haul transportation
section indicates that the cost of moving coal one mile inland from a fuel
transshipment and storage facility is not exceedingly expensive. The long
(continued on page 277)

274

TABLE 49

COST OF SUPPLYINGREFINED PRODUCTS TO THE EAST COAST
FROM ONSHORE AND OFFSHORE REFINERIES

($/bbl of product in 1985)

Origin of Supply

Onshore

EAST GULF a
Cost Component COAST COAST Offshore
.Crude oil in Persian Gulf b 2.65 2.63 2.69
Transportation and terminalingc .1.28 1.21 1.00
Duty- 0.11 0.11
Operating costs 0.48 0.45 0.38
Product transportation 0.51 0.27
Interest on working capital 0.08 0.08 0.10
Marketing expense 0.05 0.05
Income taxesd '0.52 0.05 0.05
Return on refinery investmente 0.90 0.79 0.90
Total (15% 'DCFf rate of return) 6.079 6.28 5.68
Total (10% DCF rate of return) 5.58 5.85 L 5.42

aThe tabulation of "Costs shown in this table for an offshore re-
fineryis not based on any particular location, nor are there currently
arly'offshore refineries making the assumed "balanced" District I slate
of products. -Current offshore refineries are of the hydroskii1ming type,
Leeding mixtures of low-sulfur and high-sulfur crude, primarily p.@odUC7
ing fuel oil for the U.S. market.* Consequently, these costs are not
intended to display actual circumstances of current offshore conditions.
b
Prices of crude oil in the Persian Gulf are the same. Figures in
the table differ because they are expressed in dollars per barrel of
proC1uct, and product yields vary from location to location. Costs in-,
clucle bu@ane purchases and Iexclude cost of acquiring import quota.
c
Shipping at.Worldscale 70 rates. Oil moves to District I by vlcc
to -=- Caribbean te rminal and thence by barge to the United States.
District III uses vlccs and a man-made deepwater port.
Forty-eight percent tax rate onshore and zero offshore. It is
assumed that a.refiner offshore will make full use of tax concessions.
eFifteen percent rate of return. Return is related to estimated re-
finery investments. Offshore refinery investment included a power plant,
which onshore refineries do not have.
fDiscounted cash flow.
gCosts are in 1972 dollars.
[SOURCE 3121

TABLE 50
IV 4a(3) FACILITY-COST MATRIX
For Facilities 1'Mile ILL-LCULU VI

PRODUCT ENVIRONMENTAL
LAND VT V1 PLANT COOLING SYSTEM FUEL DISTRIBUTIOR CONTROLS -
VT UT
WATER PLANT
PROVISION SYSTEM

00
Ca a) CO a) V) U) co
U -4 W WC to a P
M 600 C: 0co a Ca 0 'A
" 0W 0 CP 0 W 0
-4 r,. -,4 V 0
FACILITIES Q@W (U ln@ 0 a)
(ao M41 10 0 cqsv (Per (P
U3 $40 U U r VI
Year) Year)
0
(I)v (2) (3)
__C4)_ (5) (6) (7) tA VI (10)] 12)111
IV 11 IV 111 11 1 111 IV 11
COAL POWER PLANTS: 1.45-2000
Once-Through > 1 945 10,00( .317 34.4 0 151.2 5.6-28 25 116,667+ 2.7 --- 2.50 ---
Nat. Draft Tower _10 06( .0089 64.7 .397 151.2 i.6-28 15-20 116,667+
Mech. Draft Tower 45 f?86( .0089 65.'1 .397 151.2 5.6-28 15-20 116,667+ 5 2 1 75 ---
Spray Canal 100 f?80-( .0089 70.1 .462 151.2 5.6-28 15-20 116,667+
Cooling Pond 2000 ?
1?86(, .0089 94.8 .794 151.2 5.6-28115-20 116,667+
_T_ It -TV- ---IT--- ---TV-
NUCLEAR POWER PLANTS: (84-30j50( (9) (11)
1,10OAve',
Once-Through 1 1410, 10,00( .396 49.8 0 --- 234 --- 116,667 - --- --- --- ---
250-
Nat. Draft Tower 10 1 00( .0112 86.5 .576 --- 234 --- 116,667 - --- --- --- ---
W-
Mech. Draft Tower 45 1,00( .0112 94.4 .576 --- 234 --- 116,667 - --- --- --- ---
250-
Spray Canal 130 1,00( .0112 93.7 .672 234 --- 116.667 - --- --- --- ---
250-
Cooling Pond 2600 1,00( .0112 126.9 1.152 --- 234 --- 11.6,667 - -- --- --- ---

(16) ll-(17) Vill VIT
REFINERY 1,500 200 (20@ 16)(18) ( i)-
33 - 1.24 .4-3.9-
2,700 815 R7 6 3.4 22. 1 ?.75
I-
(COAL) FUEL 'TRANS- %5)
SHIPMENT & STORAGE 302 35-45
lFigures in acres V Footnotes on following pg. for numbers VII Dollars per barrel [312)
11 Figures in millions of dollars in ( ) brackets Vill Total plant, million $/yr.
III Figures in thousand of dollars VI This factor would not be substantially affected
IV Figures in mills per kwh by location on coast or one mile inland

276

Footnotes for Table 50.

1 The figures for land requirements include the requirements for different
cooling systems except for cooling ponds. The land requirements for cooling
ponds and spray canals for coal-fired power plants were adapted from nuclear
power plant requirements at the lower Btu/kWh heat rejection rate (77% of
a nuclear power plant)-for coal-fired power plants. The other cooling sys-
tems, it is assumed, would not use appreciably more land for fossil-fuels
than for'nuclear.

2 These figures represent different plant capital costs in millions of dol-
lars for a two unit [1300 MWe each] power plant. These costs are from a
different source than the cooling system costs and are in mid-1974 present
value dollars. These figures do not include fuel,costs, operation and
maintenance costs, or sulfur dioxide controls [308].

3 The capital costs are presented in 1976 present value dollars for conveying
water one mile inland for a 1000 MWe plant. See section on Water supply
(Section IV.A.b.(2)(b)), for detailed limitations on use of figures. The
capital costs for water supply do not consider the type of facilities which
could be used on the coast versus inland and should be 'Used with caution.

4 The operation and maintenance costs are in mills per kilowatt hour in 1985
dollars projected from 1972 dollars for a 1000 MWe plant, assuming a height
increase of 3 feet for one mile inland distance.

5 The capital cost figures are represented in 1975 present value dollars for
a 1200 MWe plant. The coal-fired power plant figures are adapted from the
nuclear figures by using the lower heat rejection, 77% of a nuclear power
plant, for a coal-fired power plant.

6 The operation and maintenance costs are in 1975 dollars in mills per kWh.
See section on Cooling Systems [Section IV.A.b.(2)], for limitations on use
of figures.

7- The figures in the short haul transportation of fuel for coal assume a
1000 MWe plant using 2,800,000 tons of coal per year: the amount of western
coal a power plant would use in a year. The short haul transportation
figures assume moving coal one mile using conveyor belts at 5.4(,, per ton
mile. Coal would not be moved just one mile 'at this cost due to high
handling costs.

8 The long haul transportation figures.assume moving 2,800,000 tons of coal
a distance ranging from 250 miles to 1400 miles, assuming approximately
seven miles per ton per mile.

9 The cost figures for transporting nuclear fuel for a 1000 MWe nuclear plant
assumes the cost of 46,800 KgU of fuel per year is between $4.50 to $5.54
per KgU or an approximately average of $5A0 per KgU in 1976 dollars.
10 The land acreage needed for storage at a coal power plant assumes 90-day
supply of coal and 30-40$000 tons/acre,

277

11 The cost figures are for a.1000 MWe plant assuming a quarter of the cost of
a 765 k'7 line with a 4000 MWe line capacity in 1976 dollars.

'12 The cost for sulfur dioxide controls, the.principal air pollution control,
are figured from costs that range between 2.7 to 4.2 mills per kWh.

13 The costs for fly ash disposal, the principal solid environmental control,
are figured from a volume of 250,000 tons a year fly ash wastes for a
100.0 MWe plant at one to seven dollars a ton di-sposal costs. The costs and
volume will increase one to two times if limestone desulfurization pro-
cesses are used.

1-4 Th e.figures for land requirements.for fuel transshipment and storage are
for the principal use of these'facilities--coal. The land requirements
are only the area necessary for storing 1,400,000 tons of coal.

15 This cost figure for short haul transportation of coal is based upon 5.4
cents per, ton per mile, and 5. 6 million tons of coal transported per year.
Coal would not be moved just one mile at this cost.due to high handling
Costs.

16 Depends on capacity. Figures given are from refinery description section..

17 Based on minimum and maximum figures found in literature and size varies
from 100 to 250 MBD.

18 Based on figures from [370] cited in [312].

19 Noise and light control.

20 @ $1.052/bbl IL312] -- encompasses estimates in [506].

(continued from page 273) haul transportation section indicates that the cost
of transporting coal fuels versus nuclear is many times more expensive on a per
unit basis. The cost of transporting coal can-have a significant effect on the
location of a coal-fired power plant. Refinery site location costs, though no
figures are listed, are significantly affected by existing pipeline location.
New refineries will locate near existing or proposed crude oil pipelines. The
storage section indicates the approximate number of acres the-facilities re-
qiJire for oil storage.
The "Product Distribution" column indicates the cost to power plants
and refineries for distributing their product, electricity and oil, to cus-
t-omers. The cost,of product distribution frompower plants is an important
site location factor, but not necessarily a coastal dependent factor. The cost
of product distribution from refineries is not an important factor in

278

determining site location.
The "Environmental Controls" column reflects the cost to facilities

for air water, solids, noise, and light controls, The important environmental
cIontrol in relation to site location is air. The air quality can affect both
the location of refineries and coal.p9wer' plants due to the ambient air quality.
Refinery location can also be affected by light and noise intrusion,,especially

in relation to residential communities.

In summary, this section has highlighted those factors which affect
site locationand coastal dependency. These important general factors affect-
ing site location.are often mitigated by specific site location factors. The
specific site location factors, as is shown in the Pleasant Prairie Case Study,
in Section IV.6, and.the discussion of coastal dependency can be more important
in determining site location in respecf to the coast than.general site location

f ac to rs.,

279

@6. DISCUSSION OF COASTAL DEPENDENCE AND CASE STUDY

At the outset of this discussion on the environmental and economic factors
affecting the siting of energy facilities the following definition of "coastal
dependence" was adopted:
The determination of energy facility'location with''respect to the
lakeshore is expressed through the.following general considerations:
system requirements, safety, engineering, environmental, institutional,
and economic.

The breadth of this definition indicates that the analysis must go beyond
simple evaluation of factors related to coastal locations, to a more general
examination of facility location. 'Retaining thelakeshore as a reference point,
however, puts the analysis into a coastal-versus-inland framework. This defini-
tion thus provides sufficient latitude to identify the trade-offs between coastal

and inland site locations.
This analysis.will provide a discussion'of the general and specific
factors related to both coastal.and inland sites, highlighted by examples from a
specific facility proposal. In selecting the facility to be used as an example,
the following criteria were important: (1) i.t.should be one of the facility types
considered in this study, (2) it should be representative of the approximate size
of facilities considered.in this study, and (3) coastal and inland location.
alternatives should have been considered. The facility selected, the Pleasant
Prairie Power Plant (Wisconsin Electric Power Company) near Kenosha, Wisconsin,
provides the perfect example for this type of analysis. It is a coal-fired plant
with an electric output of 1,160 MWe. Furthermore, sites both on Lake Michigan
and inland were considered during the site'.selection process. A brief description
of the facility is given below.. The material. used to highlight the discussion of
coastal dependent and nondependent factors was abstracted from the Environmental
.Report, Pleasant Prairie Power:Plant, Units 1 and 2 [552and 553j.

a. Pleasant Prairie Descr iption
In February, 1975, the-Wisconsin Electric Power Company submitted an
environmental report describing its proposed Pleasant Prairie Power Plant Units
1 and 2, to be built near the town of Pleasant Prairie, approximately four miles
southwest of.Kenosha, Wisconsin. In the report, information was provided.on the
proposed plant and site and its environment, the expected environmental impact of
the project.was asses sed, and a comparative assessment was made of six alterha@
tive sites. The facility is presently under construction.

280

The plant will consist of.two identical generating units, each of which
includes a coal-fired boiler, steam turbine and generator, and associated equip-
ment. The two steam generators will use low sulfur pulverized coal at a rate of
approximately 380 tons per hour per unit on a normal full load basis. The
expected net capacity of the plant will be 1,160 MWe, although actual output.will
vary with amb ient.temperature and relative humidity. The total capital invest-
ment in the plant and facilities will be $432,672,000, with annual operating
expenses estimated to be $42,830,000.
As of 1975, the Wisconsin Electric Power Company had'not selected a coal
supplier for the plant. However, it is determined that coal will be received at
the Pleasant Prairie site by unit train from Wyoming coal fields, approximately
1,150 miles away-
Themain cooling water system will consist of two mechanical draft
cooling towers rejecting approximately 6.8 x 10 9 Btu/hr to the atmosphere. The
system will circulate a total of 400,000 gpm across the condensers for both
units. Makeup water for this sytem will be received via pipe from Lake Michigan
(approximately 4.5 miles east of the site) at a nominal rate of approximately
8,660 gpm.
Particulate material will be controlled through the use of electrostatic
precipitators designed for overall collection efficiencies of at least 99.3
per.cent. The collected fly ash will be moved pneumatically to silos for
temporary storage before movement to an onsite disposal area. Because the plant

will use low sulfur western coal it is not expected that sulfur dioxide emissions

will be a major problem. In addition, nitrogen oxides and carbon monoxides are
also expected to meet emission standards. To aid in the dispersion of these
effluents a stack at least 450 feet high will be used.
The Pleasan.t Prairie site incorporates an area.of approximately 425.
acres, of which the principal plant facility will require 210 acres. Figure 30
depicts the arrangement of the plant and the locations of the related facilities.
Figure 31 shows the proposed intake and discharge pipe corridor leading to Lake
Michigan from the site.
The six alternative sites considered for this plant include: '(a) the

Haven site located at former Camp Haven Military Reservation in the northeastern
portion of Sheboygan County;,(b) the Port Washington site located southwest of
the company's existing Port Washington Power Plant in Ozaukee County an Lake
Michigan; (c) the Milwaukee Harbor site situated just north of the mouth of the

281

Milwaukee River on existing lake fill; (d) the Lakeside site located between
@South Lake Drive and Lake Michigan in the City of St. Francis (an existing power
plant owned by the company is located Just.south of this site);@(e) the Oak Creek
site located in the southeastern part of Milwaukee County just north of the
company's existing Oak Creek Power Plant on Lake Michigan; and (f) the Kenosha
site located just south of the City of Kenosha municipal boundary. Figure 32
shows all of these sites., including the selected Pleasant Prairie site.
In a comparison of the alternative sites, factors considered included the
following: (1) proximity and suitability.of,both rail and road facilities during
construction and operation of the plant.; (2) potential for congestion of 'service
roads; (3) surrounding land use; (4) proximity to population concentrations, and.-
(5) other factors discussed in the environmental report. In addition, sites
were evaluated on a combined@economic, engineering and environmental basis.
Critical factors for evaluation and comparison included site characteristics,
cooling method, and fuel supply provisions.

b. 'Discussion of Coastal Dependence
Because this study deals-with the problem of site selction on a nonsite-
specific basis, it is impossible to identify those factors favoring a coastal site
over an inland,site or vice versa.. Instead, at the level of this analysis there
is 'a conftnuum of@coastal dependence or nondependence, running from those factors
that can be generalized for all sites as being coastal-related to those factors
twhich may, on a site-specific case-by-case basis, involve important coastal versus

inland site trade-offs.

The most obvious factor tying major energy facilities, especially
electrical generating facilities, to the coast is the need.for large volumes of
water to dissipate the great amounts of waste heat. in the past when once-through
cooling was used almost exclusively, a coastal location could result in tremendous
cost savings: figures developed for this report indicate that the capital cost
alone for a' once-through cooling system could be up to $10 million per mile to
move water to an inland site for a 1000 MWe plant. In addition, the operating
and maintenance cost would be enormous. One,estimate of this is 0.307 mills/kWh/
mi (assuming a difference in elevation of 3 feet between water intake in the
plant). With the increased,use of closed-cycle cooling systems, however, this
dependency on the coast.has been lessened considerably. The capital costs for
supplying water to a plant with.a closed-cycle system range from only $250,000 to
$1 million per mile. Operating and maintenance cost are estimated to be

CHICAGO AND NORTHWESTERN TRANSPORTATION COMPANY

E-,@-"k DUMPER

COAL STORAGE AREA
UNITS I AND 2

ASH DISPOSAL Cm In
COAL PILE NO a
YARD RECLAIM
ARIA ON.
GAIN SURSTATI LIGMOI
STORAGE
ASH TANK
HANDLING 0 fult OIL
0 AREA-,-Q PUMP
HOUSE
SETTLING BKSIHS O-CHI ANCT

REA
2 11 1
C
CLING TOWERS CON UCTI Cl
0 "@G.T
IS @,
0
.4 00
0
HOUSE
SW:TCMVAItD
*4u""
UN TS IAND2
st 0
040, ",v
0 0,4c",c

Cou"lly CIPA.
CQUMTT ROAD

FIGURE 30

SCALE: 400 0 400 Boo 1200 PLEASANT PRAIR IE POWER PLANT LIEGEND

SOURCE: SITE BOUNDARY
'A AGER
L@@
A-_ 2

SARGENT AND tUNDY Msconsin PRELIMINARY PL ANT LAYOUT
Elec&yc [SOURCE 552]

@
P CO.
l Wilt Y 11 E

PUM
HOUSE 1800,
NTZ a TH 3TH St
T PERSIONG - - MINTAKE
d
,u DISCHARGE

ROM

Q
P > at
it
.0 ST.
89 5
..z LAKE MICHIGAN'

C4 4n
a CTH. T
z
z
.01
PLANT SITE %; 00
U.)

4A
'/COUNTY -TRUNK Hl(;HrAY T 4 T
v-

FIGURE 31
PRCPOSED INTAKF/ DISCHARGE CORRIDOR
[SOURCE - 552]
SCALE: 0 V4 1/1 1 MILI PLEASANT PRAIRIE POWER PLANT LEGEND
SOURCEV PIPE LINE CORRIDOR
SAM.R.P.C.0 CITY OF KENOSHA Hlisconsin SITE BOUNDRY LINE
Elech7c PROPERTY NOT OWNED BY WE.P. CO.
T jP--"-;

284

APPLETON

0
CALUMET .0 MANITOWOC
CO. t:O
OSHKOSH Zu

NE
BAGO 0.

HAVEN 5171
FOND DU LA HAVEN
SHEBOYGAN
FOND DU LAC CO. SHEBOYGA
CO.

z
0
RT WASHINGTON
0 wx--
z @PORT WASHINGTON SITE
0
w

MADISON WAUKESHA
CO; ILWAUKEE
mu MILWAUKEE HARBOR SITE
DANE CO. LAKESIDE SITE

OAK CREEK SITE Lu
GENERAL LILLIAM m
MITCHELL 'FIELD RACINE CO. RAC INE
ROCK CO. ALWORTH Co. @TURTEVANT
ICHICAGO, MIWAUKk' ENOSHA
ST, PAUL AND L-f
'PACIFIC RR. COMPAINY KENOSHA SITE
BELOIT :tYTEt@@O-SIHACO. PLEASANT PRAIRIE S .IIE
WISCONSIN
ILLINOIS

RN
CHICAGO AND NORTH WESTE
TRANSPORTATION COMPANY AUKEGAN

ALTERNATOVIE SOTE LOCATIONS

FIGURE 32

PLEASANT PRAIRIE POWER PLANY

WisconsIn [SOURCE - 5521
DA @C

Electric

285

0.0153 mills/kWh/mi. This.reduction in cooling water supply costs for inland
sites allows the utilities and companies much more freedom in their site selection
procedure. This is not to say, of course, that an inland site witha closed-cycle

system will maintain its water supply more economically than a coastal site with
once-through cooling;.in most cases the latter would be much less expensive in
the long run. What it.does mean, however, is that the companies will be able to
take advantage of other possible benefits of inland locations.
In the Pleasant Prairie example the following site alternative combina-

tions were considered:

& Both once-7through afid'mechanical draft cooling towers were considered

for the Kenosha, Oak Creek, and Haven sites,

Once-through cooling exclusively was considered for the Port Washington,
Lakeside, and Milwaukee Harbor sites.
e Mechanical draft cooling exclusively was considered for the Pleasant

Prairie site.

While an acceptable arrangement could be developed for each of the sites using
the systems mentioned above, there were substantial construction and operating
cost differences between the systems and among the sites. For example, minimum
construction cost would be incurred at the Haven, Oak Creek and Kenosha sites,
utilizing mechanical draft cooling towers. All.schemes utilizing a once-through
system would be considerably more expensive ($2.5 to $7.8 million, depending
.primarily on the length of the cooling water intake and blo,wdown discharge lines
required). The Pleasant Prairie site would incur additional construction costs
of $5.5 million for the five-mile cooling water makeup pipeline from Lake Michigan

to the site. jWhile construction costs for the mechanicaldraft towers are
significantly lower than for the once-through cooling Arrangements the annual
operating costs of approximately $850,000 per year would be'considerably higher.
Although long run costs for cooling water supply to-the Pleasant Prairie
site would be higher than for the other locations, use of a closed-cycle system
allowed the Wisconsin Electric Power Company to take advantage of other signifi-
cant Pleasant Prairie site benefits. Specificallyj the Pleasant Prairie.site
would incur minimum costs in tying into the existing transmission Isystem, for

which the other sites would incur considerable costs. In addition, Pleasant
Prairie was the only site at which adequate rail transportation access was

already available. The Pleasant Prairie site had additional benefits not found
at the other locations,(some of these.are discussed below).

286

Another facto.r important in many'. if not all, facility location decisions
is the location of properties owned in part or wholly by-the companies. For
example, in most environmental reports regarding proposed facilities reviewed
during the course of this study, it was found that.alternative sites were
generally owned by the utilities. In similar' fashion, fuel transshipment
facilities and refinery expansions are generally constructed adjacent to existing
facilities. This is primarily a reflection of the long range.planning engaged in
,by the major energy suppliers. However, it can result in a definite bias toward
coastal locations purchased by the companies in the past when once-through
cooling was used almost without exception. This observation is borne out by the
following citation from the Pleasant Prairie Environmental Report:
With the exception of Pleasant Prairie, all of the candidate sites
were located on Lake Michigan ... All sites are owned by the
Applicant with the exception of the Milwaukee Harbor site and
small parcels at some of the other sites [552; p.6.3-1).
A factor of considerable importance, especially in the siting of fossil-
fuel power plants, is the location of fuel delivery-routes and transshipment
point@. As was indicated in-the discussion of transportation access in the
fossil-fuel facility description [Section IV.A..5.b.(l)], it is desirable to have
a location offering fuel delivery options; a coastal site served by both lake
carrier and railroads would meet that requirement. There are many locations in
the Great Lakes Region where delivery by lake vessel or barge is far more
economical than by unit train. For a 1000 MWe coai-fired plant using 2.8 million
tons of coal per year it would cost approximately $150,000 per mile per year to
transport coal inland, in addition to the handling and land costs for port and
terminal storage. Cost savings for fuel supply (in addition to water supply) in

such a case would tend to favor a coastal location.

While fuel delivery via lake carrier or barge may not be an important
consideration in the case of nuclear facilities, delivery of major facility
components might very well be. As was discussed in the transportation access
section in the nuclear plant description [Section IV.A.c.(I)], ease in delivery
of large reactor and turbine components may favor locations with water access.
In the Pleasant Prairie example, the o 1
pposite situation was.found. Coal
receipt was to be exclusively by unit train from the western 'United States, and
the Pleasant Prairie location offered the least expensive alternative with respect
to fuel supply. This cost savings was able to partially offset the increased
.cost of cooling water supply, illustrating the advantages of coastal nondep&ndency.

287

Two important factors were identified in thediscussion of the hydro-
logical and meteorological site requirements for nuclear plants related to
shoreline sites: (1) the change in atmospheric stability that occurs at the land-
air interface, and (2) the change in wind trajectory experienced when air moves
from the smooth surface of'the water to the irregular land surface. These
concerns highlight the fact that local coastal meteorology may be an important
factor in determining whether or not a facility should be located on or near the
lakeshore. This consideration was further addressed with respect to coastal
meteorology as it affects the dispersion of emissions from fossil fuel plants.
The influence of the lakes onmeteorological patterns plays an
important role in deternAning nitrogen oxide and hydrocarbon
impacts on the air quality onshore. For example, Milwaukee has
experienced high oxidant air pollution reading at times when
emission activity was low. One theory is that the daytime
nitrogen oxide and hydrocarbon emissions are blown out.over.
Lake Michigan by a land breeze, photochemically reacted to form
oxidants, and blown back to the shore with the evening lake
breeze. There are only sketchy experimental data to verify
this hypothesis. Nevertheless', the lakes do play a significant
role in determining the transport of pollutants [546; p.80].
The Pleasant Prairiereport*provides'a perfect example of these types of
concerns. With respect to air quality, the Haven site was the most desirable,
being located in an area which had no othermajor sources of pollution. In this
regard, the Pleasant Prairie site ranked second and was.located further away from
local and.metropolitan emissions than the other sites available. Concerning
meteorology and@climatology, all the sites are located in a region characterized
by favorable large scale dispersion patterns. The Pleasant Prairie site, however,
appeared to be the most acceptable in this respect because it was further inland,
with frequency and intensity of lake effects being less than at the other sites.
Therefore, "the potential for fumigation of stack emiss ion and for ground level
fogging and icing due to the cooling tower emissions during onshore winds will be
less than for the lake shore sites" [552; p.6.3-6].

A second concern related to local shoreline meteorology is-the potential
effect of the facility on the local.'climate'. For example, in some areas (e'.g.,
Erie County, Pennsylvania,and southwestern Michigan) the presence of the lakes
creates a climate uniquely suited to specialized agricultural crops, such,as
fruits, by extending and stabilizing local growing'seasons. The presence of a
major energy facility, especia .lly'one fitted with a closed-cycle cooling system,
@could possibly change these conditions. The potential for such changes would

have. to be evaluated.

288

The.aesthetic impact of a coastally located energy facility can be great.
While this may not be true for all locations (e.g., highly industrialized areas
such as Gary, Indiana, and Lackawana, New York) there most certainly are many
areas along the Great Lakes shoreline which would be severely disruptedby the
presence of such a facility. While there may also be aesthetically unique areas

inland from the coast, it is more likely that such areas would be of limited
extent along the coast. This would indicate a desirability to locate facilities
away from these unique shoreline areas when possible.
There are a series of coastal-related factors that may tend to favor
inland locations to allow savings in construction costs. Examples of these are
areas subject to flooding during periods of high lake levels, coastal reaches
subject to high rates of erosion requiring expensive (and sometimes ineffective)
erosion control structures, areas requiring significant bluff restructuring,
sites requiring significant fill, and sites requiring special foundations. As
the.shoreline segment maps in Figure 33 indicate, the Great Lakes coast is highly
variable and these factors must be evaluated on a site-by-site basis. It is
sufficient to say, however, that there are many areas in the Great Lakes Basin
where inland locations may be preferable to near-shore locations to avoid such
problems.
Several'of these considerations were brought out in the'selection of the
Pleasant Prairie site. The comparisons of site preparation costs included:
special structures required, earth work, demolition, and associated costs. The
only major difference among the sites was in the amount of earth work required.
The, Haven, Milwaukee Harbor, and Pleasant Prairie sites required a minimum

amount.of earth work and thus showed the minimum cost. Two Oak Creek alterna-

and the Kenosha site would have required major grading and use of borrow
material with associated costs of approximately $400,000. The Port Washington,
Lakeside, and a third Oak Creek alternative required landfill and extensive
restructuring of bluffs. Costs associated with these activities were estimated
at approximately $5 to $6 million above the minimum site preparation costs. In
addition, the Haven, Oak Creek, Kenosha, and Pleasant Prairie sites could utilize
mat foundations. The Port Washington, Milwaukee Harbor, Lakeside, and a variation
of the.Oak-Creek site would use landfill and,thus would require pile foundations
at an additional cost of approximately $4.4 million. Thus, the lower construc-

tion costs associated with the inland site tended to favor the selection of

Pleasant Prairie.

289

FIGURE 33

EXAMPLES OF GREAT LAKES

SHORELINE TYPES

L-3@

LAKE SUPERIOR

Z:
.4e

MARQUETTE

0
ALG c-L
1""' S"i-

LAKE ERIE Shore type
,IV to
Artificial Fill Area A
W
High Bluff.
7 LS- Erodible
30 ft. or higher _H8,.
LA
LUpks r-L0,1W Nom-Erodible High Bluff.
__w 30 ft. or higher _Hll@
OTTAW
R -, L8.
Woo. I .
Erodible Low Blut , less
than 30fft. high -1.8,
7
.. I
9,,@q rt Clih- w- 1.01W Non-Eradib
le Low Bluff, less
han 30 ft. high _L8.
SANDU KY w Q. /I, High Sand Dune, 30 ft.
S-d-i v
LB, or higher HD
&RIE Low Sand Dure, less than
30 ft. h,gh LD

L_ Erodible Low Plain P,

Non-Erodible Low Plain P@

Wetlands

Combinations Shown As: E.arnole

Lakeward/ Landward 'NIP,

Loper 111,11 KLE
Lower gu', r:: He'.
Beach Material
J -,77=
Sand and gra@el

Ledge rock
L& 'r,
No Beach
P,
H
HB, Problem Identification
B,
'60 Areas"subject to erosion
generally Protected -aaaaaa
41LP@
Critical erosion areas not
L
Protected
Gf- l -P, Non-critical erosion areas
LO
10, not protected _aiaiiaia
27-
Hlk_@! P, Shoreline subject to lake
TI., C tloodimg@
GRAND TRAVERSE Shoreline not subject to
erosion or flooding
Bluff seepage problems ZL

[SOURCE 6071

290

Just as there'are-a wide variety of shoreline characteristics.that
influence construction costs, there are also many landforms and habitats which
make portions of the coast unique. Examples include the rocky cliffs along
portions of the Lake Superior shoreline, the sand*dunes along eastern Lake
Michigan, and. the areas of coastal wetlands. In many cases these features may be
quit e rare and limited in their extent. For example, there are only 57 miles of
coastal wetlands in the entire Great Lakes Region, amounting to only 1.5 percent
of the total shoreline mileage [436). In some cases the protection of these rare
and unique landforms and habitats may require the inland siting of energy
facilities. This may become especially true when the state coastal zone manage-
ment programs begin to designate areas of particular concern.
Not only should potential conflicts with the land in its natural state be
avoided, but also conflicts with.various land uses. The Great Lakes shoreline is
and will continue to be put to many uses by people from both within and outside
of the region. Some of these uses, such as lake fishing, swimming, and boating,
re.quire the use of the lake. Others, while not absolutely requiring a lakeshore
location can be greatly enhanced by one, such as second home development,
picnicking, hiking, nature study, etc. Displacement of these uses by committing
large tracts of land to energy facilities for long periods of time can result in
long-term social costs and lost resources. The need to look at these alternative
land use conflicts has been alluded to at several points in the discussion of
energy facility impacts. The desirability of avoiding such conflicts may indicate
a preference for inland locations for large energy facilities. Because the amount
of shoreline is immutably fixed, it is important that uses of it should be
assigned priorities, with those not requiring a coastal location sited inland when
possible.

C. Summaly
This discussion of the coastal dependence or nondependence of energy
facilities in the Great Lakes Region has necessarily been conducted at a very
general level. Because of this it has identified only one generally applicable
example of a trade-off that must be made between coastal and non-coastal loca-
tions; the supply ofwater for the main cooling system. There are however, a
large number of other considerations that should be evaluated on a site-by-site
basis to determine the importance of a shoreline location for a proposed power
plant: utility land ownership, mode of fuel delivery, local meteorology and

291

dispersion patterns, aesthetics, potential con'struction problems, unique land-
forms and habitats, and potential land use conflicts. The use of the.Pleasant
Prairie example has served to illustrate that none of these factors can be
considered in a vacuum. A similar evaluation of another plant in a different

area of the Basin could show a strong coastal dependence. The trade-offs and
relative economies associated with each must,be evaluated so an overall picture
of the coastal dependency of a given facility can be developed.

7. CONCLUSIONS AND IMPLICATIONS FOR POLICY OPTIONS

The preceding descriptions and discussions of energy facilities and
their associated siting requirements and environmental and economic impacts have
been provided to determine the degree to which these facilities are dependent on
coastal resources, and to highlight those siting factors which appear to be most
coastal dependent. The discussion of coastal dependence which directly precedes
this section attempts to outline those technical considerations and environmental
impacts which most heavily depend.on or affect coastal resources. These coastal
dependent factors are.further clarified by relating them to a case study reporting
the actual coastal and non-coastal factors considered in the siting of a fossil-

fuel power plant.
Briefly, the following factors and considerations have been highlighted
in the fore-going discussionas the most coastal dependent in relation to the
siting of energy facilities in the Great Lakes Basin:
e The Great Lakes coastal zone provides resources and opportunities for
many uses. Inevitably, the development of some of these uses must necessarily
exclude or displace others.
Unique landforms and habitats presently exist in Great Lakes coastal

areas.

Aesthetic considerations such as scenic coastal vistas are unique to

the Great Lakes coastal zone.
0 Special construction constraints such as bluff reshaping and shore
protection are associated only with the lakeshore.
0 Coastal meteorology and related dispersive capability are special
siting considerations on a site-specific basis.
e Many utilities presently own land along the coast for future develop-
ment of energy facilities.

292

o. The Great Lakes represent a large and easily accessible.source of
Iwater for cooling purposes.
o Access to waterborne transport of fuels and materials is necessarily
related to the Great Lakes ports and terminals.
The following-general. conclusions can be cited with respect@to the
coastal dependence of power plants.:
Facilities using once-through cooling.must be located on or near the
shoreline because of the substantial costs of transpo rting cooling water inland
via pipeline.
Facilities using close.d-cycle cooling are less dependent on loca:,tions
-,.o,n or near the shoreline than are facilities using once-through,cooling, assuming
all other factors to be approximately equal for sites being compared. Site
conditions will determine the type of closed-cycle cooling system used. However,
the furtherinland a facility is located, the greater are'the construction
(capital) costs for water provision and blowdown pipelines..
o For power plants using closed-cycle cooling, the cost of locating on
the shoreline versus@the cost Of locating inland are essentially trade-offs
.among the construction and operati.on cost.s, of such necessities as transmission
lines, water supply and cooling facilities, facilities for-delivery and handling
,...of fuels and other supplies,. and disposal of waste material.
Nuclear facilities require very large andmassive compone-nts, which in
most casesare delivered via water-transportation. However, rail,or road
corridors of,ade'quate width and load-carrying capacity can be utilized for
,delivery of these components. If these rail or road corridors are@ not available
,,to potential sites, the location of nuclear facilities may be more dependent on
shoreline or near.-shoreline locations. However, field assembly is becoming more
...,@common, thus possibly negating some of this shoreline dependence. Other nuclear
facility coastal dependence considerations are the same as in the preceding item.
The coastal.dependence of fuel transshipment and storage facilities.and

refineries can be summarized as follows:
e Fuel.(coal and oil) transshipment and storage facilities that receive
or ship their commodities by water must locate near the shoreline, although
storage areas do not have to be located on the shoreline. Storage area. location
is highly,dependent on industrial needs, future transportation requirements, and

onsite and offsite use of stored fuel.

293

e Refineries are not coastal dependent, but do need access to water for
processing and cooling. Dependence on easily accessible water is decreasing due
to increasing water recycling practices. Air cooling is also reducing refinery
dependence on,easy water access. Refinery location decisions are increasingly
becoming market oriented, with decisions being made on a national basis, due-to
the existence of the national product distribution pipeline.
Finally, coal gasification and liquefaction facilities are not likely to
be located in the Great Lakes Basin, with the possible exception of low-Btu gasi-
fication facilities, which can be located at or near the site of use. Large
coal gasification and liquefaction facilities will be located near mine mouth
locations due to the high cost of transporting coal compared to substitute natural

gas.
The implications of this report on technical considerations for the
development of policy options relating to energy facility siting in the coastal
zone are many-and varied. In a general sense,,however, it is possible to say
that no one factor absolutely ties a given energy facility to a coastal site.
Furthermore,'it is evident from the discussion of-technical considerations and
the case study that there are-a number of technical options which maybe generated
for future siting considerations. These options are predicated on the conclusion
that energy facilities are not coastal dependen t@per se,-and that it is possible
that they be sited inland fromIthe coast while.,maintaining certain degrees of
access to coastal resources. The technical policy options and implications
developed in Section VI.C are based on this tenet of nondependency.
At this point, a concluding statement. on facility siting should be made.
The entire preceding section dealt with technical considerations affecting siting
of energy facilities. It shou ld be noted that there are other possible (or even
,probable) considerations of a nontechnical nature which may affect the final site
selection.process. More specifically, these considerations relate to politico-
economic decisions ba sed on expediency and profit motivation. To ignore the
existence of these nontechnical considerations in the site selection process
would be naive; to assess their magnitude in relation to coastal siting would be
impossible.

294

B. ENERGY CONSUMPTION AND MOVEMENT IN THE GREAT LAKES REGION

1. INTRODUCTION

Rational planning for the future necessitates a sound knowledge of the
present The following information was collected for the purpose of providing
that knowledge. -This section-presents collected data on the present energy
situation.pertinent to the Great Lakes coastal zone.

An attempt was made to concentrate on those aspects of supply, transpor-
tation and utilization of energy that relate to electric power generation and the
coastal zone. Electric generating facilities and fuel transshipment points are
discussed both in the context of present capacities and locations and of planned

and scheduled facilities.

A major portion of this section attempts to address the question of the
future relationship between energy facilities and the coastal zone. This
discussion focuses on the relationship between electric generating facilities
and potential fuel mi@:cs. Further, the pro blems associated with determining,
-future demand levels for electric energy are discussed in the context of how
.various demand growth rates may affect siting of electric generating facilities.
'Finally, a number of potential fuel mixes and growth rates were postulated in the
attempt to determine possible future resource requirements and pressures on the

coastal zone.

2. ENERGY DEMAND

a. Fuels for Power Production

The Great Lakes Region is one of the most highly industrialized and
energy consumptive regions in.the w orld. Its development is in large measure
--facilitated by the ease of commodity transportation on the lakes and the wealth
of fuel resources within the eight states bordering the Great Lakes. Energy
production in the Great Lakes states reflects the unique resource capabilities

of the region.
An average of over ninety percent of the fossil-fuel electrical generating
lacilities are coal fired in seven of the eight Great Lakes states. This section
will therefore focus on the origin, transporltation and end use of coal, although
other fuels will be discussed also. The discussion will assume a regional and
state perspective with special emphasis.on activity in the coastal zone.

295

(1) Origin of Fuels
The Great Lakes Basin states are net importers of energy. Each state
consumes more energy from coal, oil and natural gas than it can produce-. Even
the majorcoal- and oil-producing states of Pennsylvania and Illinois consume
over twice as much fuel as they produce [618]. Thus, the Great Lakes Region must
depend heavily on fuels-from.elsewhere.

(a) Coal

The United States has an abundant supply of coal. The estimated reserve
base for the country is 434 billion'short tons. This is an estimate of the
identified resources deemed suitable for mining by 1974 methods [191. -At the
present consumption rate of approximately 600 million tons per year this resource

could last.six or seven centuries.
There are three primary coal supply-regions: the Appalachian, Illinois

and Western basins.

The preponderance of coal'consumed in the Great Lakes states is produced
in the Appalachian and Illinois coal fields. These two major fields supply most
of the region's needs for coal,for power production. Pennsylvania and Ohio supply
ilmost 40% of the coal used by electric utilities in the Great.Lakes states.
Illinois, Kentucky and Indiana follow,,in order behind these states. Combined,
the five states provided 76% of the total coal supplied to the Great Lakes
utilities in 1975 [5471.

FIVE LARGEST COAL PRODUCING STATES

FOR ELECTRIC UTILITY USE

INTHE GREAT LAKES STATES

1975 1975 Percent of
State' (1000 Tons) Great Lakes States Total

Pennsylvania 38,093 19.5

Ohio 37,533 1.9.2

Illinois 31,201 16.0

Kentucky 22,933 11.8

Indiana _2010172 10.3

TOTAL 149,932 76.8

SOURCE [5471

296

Recently, air quality standards have forced utilities to purchase a lower
sulfur coal than commonly found i; the eastern fields. The purchase of a
considerably lower sulfur coal from the Western basin, primarily Montana and
Wyoming, has increased considerably in the region. Between 1974 and 1975 there

was a 58.3% increase in western coal destined for states in the East Northcentral

Region (Wisconsin, Illinois,*Indiana, Ohio and Michigan). Ninety-five percent of
the western coal shipped to the Great Lakes states was produced in Montana or
Wyoming. Most of this fuel was surface mined and of sub-bituminous grade [547].
Table 51 presents the major state sources of coal to electric utilities in the

Great Lakes states.

TABLE 51

ORIG1N AND DEs,rINATION OF COAL DELIVERIES

TO ELECTRIC UTILITIES IN 1975
(Deliveries in 1000 Lons)

0 R I G I N

I A S T 9 R N H I D W 9 S T W 9 S T 9 9 N

Percent Total
-C-1 Fr-
DESTINATION KENTUCKY 01110 W. VA. 'PA. ILL. IND. MONT. WYO. @OLO UTAH AlI States
1111noia 1.182.1 9.1 0.3 21,218.1 379.3 9,310.5 1,866.3 10.3 20.0 33,99@,O 99,
33,999.3
5,045.5 0.9 75.0 3,134.6 18,896.4 819.0 2,841.4 1.6 130.3 30 944 1
India 30:968:1 992
HIchigan 5.778.7 8,362.3 5,116.6 691.0 274.5 82.2 1,056.0 - - - 21,361.3 991
21,361.8
Minnesota 98.3 0.4 3.0 - 1,717.3 - 6,205.1 2.2 3.0 60.9 8190.2 921
N- York 524.0 - 839.7 4.591.6 - - - - 5.0 - 5,960.3 99 2
5,970.8

01.1. 7,151.9 29,113.6 6,540.6 2,168.2 29.6 931.7 1.9 362.4 4_6 105-9 9,2
46,860.1

P.-YI-ni. 1,080.4 20.3 4.216.2 30,070.3 - - - - - 35.3a7.2 99 X
35,448.9
Wisconsin 2,072.6 26.6 4.6 572.4 4,856.9 704.6 2,161.2 1,052.8 20.2 - 11,551.9 9,2
11,55Z.5

TOTAL 22.933.5 37,533.2 16,796.0 38,093.5 31,201.4 20,172.1 19.551.8 6,700.4 316.5 573.6 194,659.1 99Z
194,959.1

SOURCE: [547]
NOTE: Does not include anthracite and imported coal.

The coal resources in this country have been extensively surveyed. The magnitude
of remaining deposits provides a stable base for fossil fuel-fired electricity
generation. The quantity of this fuel is not at issue. Concern centers rather

on environmental and health risks involved in coal utilization. These factors

will to a large extent determine the coal type recovered for future use.

297

(b) Oil and natural gas
Ali. the Great Lakes states except New York have a fossil-fuel mix
percentage for electrical generation lower in oil and.natural gas than the rest
of the country. These seven states used about 5% oil and 3,% gas for power. The
national figures in 1975.were 18 .9% oil and 19.8% gas for the generation of,
electricity [547]. Further analysi s of these statistics,is contained in the

discussion of fuel mixes.

Most of the sources for oll and natural gas are distant from the Great
Lakes Region. A network of pipellnes carries oil and gas into.the region from the
south, central, and Gulf states' Canada also supplies oil to the region from

fields in Alberta. With Canadian demand increasing, this source will soon be
terminated to the Great Lakes.states. The Great Lakes states are relatively
mi. nor producers of oil and natural gas, contributing about 3% of the U.S. oil
production and 2% of the national gas production [24]. The region must therefore
import substantial quantities of oil and gas. An examination of production and
consumption figures in the eight states for oil and natural gas reveals that the
states supply about 4% of their annual consumption [6181. Figures 34 and 35
show the major sources of natural gas and oil for the Great Lakes Basin states.

FIGURE 34

SOURCES OF NATURAL GAS SUPPLY TO THE GREAT LAKES BASIN STATES

GLGT - GREAT LAKES TRANSMISSION CO. PEPL - PANHANDLE EASTERN PIPELINE CO.
MVPL - MICHIGAN WISCONSIN PIPELINE CO. TET - TEXAS EASTERN TRANSMISSION CO.
NGPL - NATURAL GAS PIPELINE CO. OF AMERICA TGPL _ TENNESSEE GAS PIPELINE CO.
NNG - NORTHERN NATURAL GAS CO,

298

FIGURE 35__@

SOURCES OF CRUDE OIL SUPPLYTO THE GREAT LAKES BASIN

40C AMOCO OIL CO. NVPC - MID-VALLEY PIPELINE CO.
APLC ARCO PIPELINE CO. NTC - NATIONAL TRANSIT CO. (Source 618]
FLC LAKEHEAD PIPELINE CO., INC. SPLC - SHELL PIPELINE CO.
VAR MARATHON PIPELINE CO. TCSP -; TEXACIO-CITIES SERVICE PIPELINE CO.
VPLC MOBIL PIPELINE CO. TPLC - TECUMSEH PIPELINE CO.

LPLC

TPL

Future.long-term supplies of Alaskan oil to the Great Lakes' region I are
pr-sently under consideration. Three major long-term options have emerged for
transport of the oil.
e Trans-Provincial Pipeline--Alaskan crude transported by tanker from
Valdez, Alaska, would be delivered to a new deepwater port at Kitimat, British
Columbia., The oil then would be transferred to a 30-inch pipeline and would
move 830 miles to Edmonton, Alberta. In Edmonton the oil would move into
existing pipelines. The Trans-Provincial Pipeline would utilize the Interpro-
,.vincial/Lakehead Pipeline system presently serving the Great Lakes Region. The
proposal is projected for an initial total capacity of 300,000 barrels per day
with an eventual capacity of 650,000 barrels per day [490].
Northern Tier Pipeline--This proposed line would cross the northern
tier of states from a deepwater facility in Port Angeles, Washington, to Clear-
brook, Minnesota. This 40- to 42-inch line would stretch 1500 miles and con4@ct
with Minnesota and Lakehead pipelines in-Clearbrook, Minnesota. Initial opera-
tional capacity is projected as 600,000 barrels per day with an eventual capacity
of 800,000 to 1,200,000 barrels per day [490].

299

9 Williams Pipeline Company--This expansion involves construction of a
500-mile pipeline from Oklahoma to Iowa. The proposed 24-inch line would receive
oil from existing pipelines connected to a new deepwater facility in Texas. The
Williams line could also connect to a proposed pipeline from Long Beach, Cali-
fornia. The new system could provide an additional 350,000 barrels per day of
crude oil from Oklahoma to Minneapolis, Minnesota [490].
The availability of oil in the future relies on the rate of new discover-
ies and the economic incentives arranged to promote further exploration.
Development of coal liquefaction technologies may also affect the supply of liquid

fossil.fuels.

Additional sources of natural gas to the Great Lakes states may also
arrive fromAlaska. Proven natural gas reserves in the North Slope are estimated
at 22.5 trillion cubic feet. The proposed Artic Gas system would transport gas
through 5,551 miles of buried pipeline overland from northern Alaska through

northern and western Canada to three ultimate destinations within the 48

contiguous United States. One of these destinations would be Delmont, Pennsylvania,
where an estimated 1.5 billion cfd could be delivered.

The other major alternative, the El Paso Alaska system, would move gas.
south from the Prudhoe Bay area by pipeline to a port on the southern Alaskan
coast. There the gas would be converted to liquified natural gas (LNG) and
shipped via cr Iyogenic tanker along the northern Pacific coast to a delivery point
on the California coast. The LNG would then be regasified and would be distributed
@hrough the gas pipeline network. The El Paso Alaska system would provide gas to
the,Great Lakes Region by rerouting northward the,gas previously required on the
west coast [2571.

(2 Great Lakes States Production and Reserves
Oil, natural gas and coal are produced in the states bordering the Great
Lakes. Peat, a potential fuel found in the Great Lakes Region, is not presently
used as a fuel for power, production.. The four southernmost Great Lakes states,
Illinois, Indiana, Ohio and Pennsylvania, yield most of the gaaand oil and
virtually all the coal produced in the Great Lakes states. A summary of fuel
productiph and reserve capacity by state follows.
9 Illinois--Illinois has a recoverable reserve of coal greater than the
combined reserve of the remaining seven Great Lakes states [19]. Deposits under-
lie 65% of the state and are found in 86 of its 102 counties@[51. Illinois holds

300

15.1% of the country's total coal reserves, or'65 billion tons. This plentiful
resource, which has a high heating value ranging from 10,500 to 13,000 Btu's per
pound, accounts-for 16.6% of the,nation's potential energy reserve from coal [4].
Illinois coal production, although on the decline, contributed 9.6% of the total U.S.
coal production in 1974 [327]. The state mined 58,215,000 short tons that year
compared to an average 64,197,000 tons/year between 1966 and 1970 [585]. The
.decline in.coal production is in many ways symptomatic of the quality of Illinois
coal. Much of this coal has a 3 to 5% range in sulfur content, which exceeds the
standards set by'the Environmental Protection Agency [4]. The Federal Power
Commission in 1973 estimated that more than 85% of the coal.now being burnedby

Illinois electric utilities would be prohibited when sulfur emission standards
are enforced [3]. This valuable resource therefore grows increasingly impractical
for power generation and depends on the development of efficient technology for.

sulfur removal.
Illinois also has substantial reserves of oil and natural gas. ..Illinois
oil production was 26,080,000 bbl of crude in 1975 [319], which was the highest
for the eight Great Lakes states. The state had an estimated reserve in 1974 of
162.3 million barrels, which among the Great Lakes states was-second only to
Michigan [24].
Natural gas production was 2,840 million cubic feet in 1973, with
reserves in total gas of 380,525 million cubic feet [586]. Illinois is developing
;the use of underground caverns for.storing liqdified petroleum gases. The.
..Illinois Great Lakes Basin counties of Will and Dupage presently store 46,000 bbl
of LP gas and 250,000 bb! of propane and butane [3].
Peat, which is not sold as a fuel for power production, is the only fuel
mined in the coastal zone [317].
9 Indiana--The mineral industry survey for Indiana in 1975 reports that

Mineral fuels accounted for about 58% of the estimated value of
Indiana's mineral produc.tion in 1975, 15% higher than in 1974.
Coal, which alone accounted for nearly half of the total value of
all mineral output, increased an estimated 5% in quantity and 19%
in value. Output of both petroleum and-na-tural gas declined sharply
in 1.975; continuing a downward trend which has occurred annually
since 1 65 [3201.

In 1975, Indiana produced 24.8 million short tons of bituminous and
lignite coal [3201. The state ha.d,-.a demonstrated coal reserve in 1974 of 10.6
billion tons. Sixty'@-four percent of this .reserve has a sulfur content greater
than three percent, which makes.it environmentally unfavorable. No coal is mined

in the-Indiana coastal counties.,

301

Crude petroleum production in Indiana in 1975 was 4.6 mill.ion-barrels, a
decrease of 287,000.bbl from 1974 production (4031. Reserves of Ind iana crude
oil were 29.6 million barrels in 1974 [24]. A small amount of the oil produced
in 1974 came from the coastal county of LaPorte, which produced 3,389 barrels
[321].
Production of natural gas.in -Indiana has declined also. Production fell
from 176 million cubic feet in 1974 to 126 mmcf in'1975 [320]. Though reserves
of natural gas are estimated at.5,308 mmcf, 50% of this reserve is.in nonproducing
reservoirs-[24].
0 Michigan -Michigan produced no coal'in 1974 [327]. Coal'@ftelds-are'
found beneath 20% of the state, but the resource,is thinly distributed, yielding
an identified coal reserve base of only 119 million tons [19].
Michigan's petroleum production in 1975 increased 6.3 million barrel's
from the previous year, yielding.a total of 24,413,000 bbl [319]. Petroleum*was
produced in the coastal counties of Allegan,-Antrim, Arenac@, Bay, Grand Traverse,
.Huron, Macomb, Mason, Monroe, Muskegon ,' Oceana, Ottawa, Presque Isle, St.'Clair,
Tuscola,'VanBuren, and Wayne. These counties produced 1,757,000 barrels in 1975,
which accounted for about 14% of the total state@petroleum production [317].
Michigan's oil reserve of 164.1 million barrels is the largest of the eight Great

Lakes states.

Natural gas production in Michigan in 1975 was 102 billion cubic feet
which was an increase of 32 billion.cubic feet over 1974 [75]. Natural gas wa's
produced in*th4E@ coastal counties of Allegan, Grand Traverse,@ Macomb, Ottawa,-and
St. Clair (also natural gas liquids) in 1972 [319].' Michigan exceeded the
remaining Great Lakes states in production and reserves of natural gas in 1974.
Total reserves were estimated at 1,041 billion cubic feet [24].
Michigan produced IA million'barrels of natural gas..liquids in 1973. Of
this total 65% was liquified petroleum (LP) gas and 35% was natural gasoline.
Proved reserves of this resource:totaled 25 million barrels in 1973, which was an
increase of 6 million barrels over the previous year's estimate [586,1.
Overall, Michigan is able to produce approximately 10% of its needs for
oil and gas, so must still import the majority of its energy [751.
Minnesota--Minnesota claims 50% of the nation's known supply of peat.
Peat, th: only potential mineral fuel Minnes o.-ta produces, was us.ed pri.marily for
potting purposes (3171.

302

New-York--New York's mineral fuel production is restricted to natural
gas and petroleum. Negligible coal resources are estimated to cover 10 square
miles of New York's total area of 49,576 square miles [19]. In 1975 New York
produced 890,000 barrels of crude petroleum, which was a decrease of 6,000
barrels from 1974 [319]. The state showed crude oil reserves of 6,667 mbbl.in
19.74 [241. Chautauqua County was the sole New York Great Lakes coastal county to
produce oil. In 1973 this county-had 43% (41 wells) of New York's proved oil
field wells [586].-
Natural gas production in New York was 4.5 million cubic feet in 1973.
This represented a 23% increase over production in the previous year [586]. The
estimate of natural gas reserves in New York was 87.1 billion cubic feet. The
coastal counties of Cayuga, Chautauqua, Erie and Monroe produced natural gas.
Erie and Chautauqua Counties had 87% (21 wells) of New York's proved natural gas
field wells in 1973 [586].
e Ohio--Ohio coal production in 1914 was 45.4 million short tons, which
accounted for 7.5% of the national coal production [327]. In term's of value,
bituminous coal is the state's principal mineral commodity, contributing $338.8
million to the economy in 1973 [586].
There was a demonstrated coal reserve in Ohio of 21 billion tons [19].
Of this reserve 60% has sulfur content greater than 3.0% [327]. Most of the
future production of coal in Ohio will depend on recovery from underground mines.

An estimated 80% of the recoverable coal reserve in Ohio is located in beds

suited to underground mining [19]. No coal is extracted in Ohio's coastal

counties.

Ohio ranked third among the Great Lakes states in oil production. The
state produced 11,704,000 barrels of crude'petroleum in 1975 which was an
increase of 2.6 million barrels over production in 1974-[319]. All coastal
counties in Ohio are considered either oil or gas producing counties. In 1975
twenty-five new producing wells were drilled in Ashtabula County. Eight of the
wells produced natural gas, two produced oil, and fifteen produced both oil and
.natural gas. Of the five new'wells drilled in Lorain County in 1975, four were
dry and one produced gas [325 ]. Total oil reserves within the state amounted to
87.3 million barrels. Total natural gas production in 1974 was 94.3 billion
cubic feet [101 with gas reserves totaling 1,238.6 billion cubic feet [241.
0 Pennsylvania--Pennsylvania is the largest coal producing state in the
Great Lakes Region. In 1974, the state produced 80.5 million short tons of

303

coal, which was.13.3% of the total U.S. production [327]. Coal deposits cover
15,000 square miles or approximately one7third of the state. The demonstrated
coal reserve base in Pennsylvania is 31.0 billion tons. Approximately 95% of
this reserve is.recoverable by underground mining methods. Seventy-eight percent
of the total underground and surface bituminous coal reserve has a sulfur content
less than 3%. Twenty-four percent-or 7.3 million tons of the coal has less than
1% sulfur. Anthracite, a-high quality coal, is found primarily in Pennsylvania.
This high Btu coal has an average sulfur content of 0.75%, which is favorable for
compliance with air quality standards [586]. Anthracite-reserves are smaller and
more difficult to recover than bituminous coal. In 1973 anthracite production
was 6.8 million short tons or 8.2% of the total coal production in the state.
Being higher quality coal, anthracite contributed over 10% of the total value
from coal in.Pennsy lvania that year [586]. Erie County, Pennsylvania's only
Great Lakes coastal county, has no reserves of coal.
Crude petroleum.production in 1975.was 3,910,000 barrels, an increase
of 432,000 barrels over 1974 production figures [319]. Proved reserves were
estimated at 35,.5 million barrels [24). Erie County had five crude oil wells in
1974, which produced an insignificant 257 barrels [141.
Natural gas production was 82.7 billion cubic.feet in 1,974, which was a
5% increase over the previous year. Gas reserves wereestimated at 878.5 billion
cubic feet [24]. Erie County produced 64 mmcf of natural gas in.1974 [141.
e Wisconsin--As of 1976, Wisconsin has no known or projected production
or reserves of oil, natural gas or coal.
Although producers of coal, oil and natural gas, the Great Lakes states
are net-importers of energy. The role each state will assume in production of
these fuels is contingent upon a multiplicity of'factors relating to recovery..
technologies,* costs, availability, demand and fuel quality, Reserves of the
mineral fuels available in the Great Lakes states are located primarily in.
Michigan, Illinois, Pennsylvania and Ohio. Michigan and.Ohio hold 70% of the
natural gas reserves. This reserve is insignificant relative to gas consumption
in the region. The 2,279.8 billion cubic feet of natural gas reserves in Michigan
and Ohio would supply about one-tenth of the yearly demand of.the Great Lakes
states, which in 1972 consumed,.approximately 22,614 billion cubic.feet of gas
[6181. The situation is similar for oil. Michigan and Indiana have 67% of the
reserves, or 326.5 million barrels of oil. Consumption in 1972 was 1,752 million
barrels of oil, which was five times the total reserves of the two states [6181.

304

Therefore, production of oil and natural gas in the Great Lakes states can meet
only a minor portion of the demands.
Coal, which is the major f@el for the generation of electricity in the
basin, remains in extensive reserve in Pennsylvania, Ohio, Indiana and Illinois.
Pennsylvania and Illinois hold more than'75%.of the demonstrated coal reserve
among these four states. The Pennsylvania-Illinois reserve of 96.6 billion tons
contributes substantially to the demands in the Great Lakes Region. The future
recovery of,coal from the Great Lakes states hinges increasingly on the question

of sulfur content. Great Lakes coal will retain its traditional share of the

market only if the cost of removing sulfur is competitive with the cost of
delivering low sulfur western coal to thexegion. Great Lakes states coal
production also faces higher mining costs as 85% of the demonstrated reserve
would be recovered from underground mines.
The Great Lakes states produce no fuels for nuclear power generation.
The states of Wyoming, New Mexico, Texas, and Utah are the principle U.S.
producers of uranium, listed in,order of quantity produced [586]. Hydroelectric
power, which contributes substaTitially to the generation of electricity, is
assumed to remain fairly constan It because of the environmental cost of creating
reservoirs and because the major sites in proximity to load centers have been
developed.

(3) Present Fuel Mix
The Great Lakes states consume approximately 46% of the Btu's produced
by coal for fossil-fuels plants in the country. The eight states also consume
27% and 4%, respectively, of the national supplies of oil and natural gas used
for power production [547]. Table 52 describes the relative percentages of coal,
oil and natural gas used for steam-electric plants in 1975. This table shows
that 82.8 percent of the total Btu's produced by fossil-fuel facilities in the
eight states were generated by coal.
The fuel mix for New York is a reversal of themix for the other seven
states. In 1975, New York used oil for 77% of its.electric generation needs.
This percentage does not,properly reflect the fuel mix in the New York Great
Lakes coastal zone. Coal-fired power plants account for about 70% of the power
produced by fossil-fueled plants in the upstate coastal counties of New York [.289].
The state figures on.fuel'mix are generally more representative of the dependence
on oil in and around the New York City area.

305

TABLE 52

PRIMARY ENERGY PURCHASE DATA FOR STEAM-ELECTRIC PLANTS DURING THE TWELVE MONTHS.

OF 1975

PERCENT OF AVERAGE PRICE,
TOTAL BTU (BILLIONS) TOTAL BTU PER 10 6 BTU
STATE COAL I GAS TOTAL COAL OIL GAS COAL OIL I GAS
OIL

ILLINOIS 688,793.7 44,970.2 29,438.0 763,201.9 90.3 5.9 3.9 75.4 153.5 113.1
INDIANA 657,428.4 8,867.3 10,053.2 676,349.0 97.2 1.3 1.5 59.2 214.1 81.7
MICHIGAN 505,464.0 95,488.7 32i82O.4 633,773.2 79.8 15.1 5.2 92.3 209.1 127.7
MINNESOTA 157,825.9 4,872.4 15,173.7 177,872.0 88.7 2.7 8.5 62.3 196.0 63.9
NEW YORK 143,624.5 526, 724.0 13,146.1 683,494.6 21.0 77.1 1.9 117.7 194.3 B7.4
01110 1,027,147.5 8,304.9 3,630.5 1,039,082.8 98.9 0.8 0.3 95.2 224.1 122.6
PENNSYLVANIA 864,484.7 79,199.4 11.7 943,695.7 91.6 8.4 0.0 .95.5 210.9 146.7
WISCONSIN 245,320.5 2,856.6 13,751.5 261;928.5 93.7 1.1 5.3 86.4 189,9 81.5

GREAT LAKES
STATES TOTAL 4,290,089.3 771,283.4 118,025.0 5,179,397.6 82.8- 14.9 2.3 85.3 196.0 101.9

[Source: "Annual Summary of Cost and'Quality of Steam-Electric Plant
fuels 1975" Federal Power Commission]

The fossil-fuel mix figures for the seven remaining Great Lakes states
reliablLy portray the general situation in the coastal.counties. This is
especially true in Michigan in which.38 of the 45 f'ossil-fuel plants are located
in the coastal counties. Many of the plants in the Illinois-@-Indiana coastal zone
are designated as-coal/gas--@fired. The gas used is.a relatively small amount
however, generally supplying fuel for peaking units or as start-up fuel for the
large coal-fired boilers. The percentage of gas used in the coastal counties of
this area does not greatly differ from the states' fuel mix consumption figure.
An examination of kilowatts produced in the coastal counties of Illinois and
Indiana show that approximately 4% of the fossil-fuel electrical generating
capacity is'provided by natural,gas. Therefore a substantially'accurate extrapo-
lation concerning fuel mix in the coastal counties can be derived from review of

the statewide MIX.

The present fuel mix of the Great Lakes states depends on enormous
quantities of coal. 'Ohio, Pennsylvania, Illinois and Indiana are the four
largest coal consuming states for electric generation in the nation [547]. Oil
and. natural gas are minor sources, of fuel in the region. In absolute terms
though, the Great Lakes Region provides a substantial market for the national
consumption of oil and natural gas.

306.

Problems with the availability and price of natural gas make this-fuel
increasing unreliable as a primary fuel for power generation. Demands for space
heating and industrial applications further remove natural gas from consideration
as a primary fuel for electric production.
Petroleum, another versatile fuel, will most likely continue to decline
in importance as a base load fuel for power production.' The cost of petroleum is
growing increasingly prohibitive, but petroleum still has certain environmental
advantages over coal-fired plants and generally requires lower initial capital
costs for plant construction.
'Being more-limit,ed in its applications than oil or gas, coal will continue
to be the primary fuel for power generation. New technologies.which utilize coal
(i.e., fluidized bed, liquefaction and gasification, etc.) are aimed at reducing
many of the detrimental effects.of coal-fited generation.
A developing trend suggests that electricity will take up much of the
slack left by reduceduse of oil and natural gas due to the end use versatility
of electricity. However, the continuation of any such trend is.very dependent
on the progress made in acceptable means of,utilizing coal for power production.
This issue hinges on the problem of sulfur. Changes in the amount of
coal used depend on the development of efficient desulfurization technologies

either before or after combustion.
Hydro-electric power currently comprises 5% of the region's generating
capacity and is not expected to increase to any degree in the future. This type
of generation is centered primarily in New York wh ere it meets approximately 24%
of the current state power needs [466].
The utilities have planned to increase nuclear capacity rapidly over the
next twenty years to.the point where it will comprise some 30-35% of the total
generating capacity. The continuation of this trend is predicated upon the
resolution of many.serious problems currently plaguing the nuclear industry.
These factors would include the availability of fuel, a reduced construction
period, a greater public acceptance, and a solution to the problem of nuclear
fuel waste disposal. S.ome.seve,n or eight nuclear generating,facilities in the
Great Lakes Region have been hard hit by plant cancellations and deferrals.
Those deferrals,.combined with the rising costs and long lead.times for construc-
tion of nuclear facilities, indicate a continued heavy r eliance on coal over the

next ten years or so.

307

Nu'clear.facilities have grown-rapidly and now contribute 12% of the
power generated'in the region. The future deve'lopmene of nuclear generating
capabilities will'depend on the industryls-ability to surmount the problems
mentioned above. The relative price and availability of the major fuels for
electrical power generation will play a major role in determining their future

use.
TABLE 53

1975 Fuel Mix by Fuel Type for 11ower Generation (percent B.T.U. contributed
by State)
State Oil Gas Coal Hydro Nuclear
Illinois 8% 4% 63% .1% 24%

Indiana 3% 2% 9 3%' 1 % 0%
Michigan 10% 6% @2% .1% 10%
Minnesota 3% 12% 63% 2% 19%

New York 39% 5% 15% 24% 17%

Ohio 4% 2% 94% 0% 0%

Penn. 14% 1% 74% 1 % 9%

Wisconsin 1% 9% 57% 1% 28%

Regional
Weighted
Averape 13% @4% 66% 5% 12%

Source: FPC, 'NRC, FEA

(4) Cost and Use By State and Region
The cost of primary fuels has increased greatly since the early 1970's.
The most significant price increases have affected users of nuclear fuels and
residual oil for power generation. The relatively greater increase in the price
of these two fuels compared to coal indicate'coal's favorable cost position.
However, the costs of transportation and insuring environmentally sound use of
coal are expected to rise in.the future. For many reasons the price of.all
primary fuels for power production are expected to rise in the future, with coal
prices possibly rising least of all. The price in 1975 for the four primary fuels

in the Great Lakes states was:

308

Coal 85(@/10 6 Btu
Nuclear 55 ,@/106 Btu*
Oil 196010 6 Btu *Based upon U308 at
.Gas 102(,1/106 Btu twenty.dollars/pound.
The costs of transportation,and extraction will play an increasingly larger role
in the future price of ele ctricity.

(5) Transport of Fuels for Power Production
The movement and distribution patterns of fuels for power production.in
the Great Lakes Region evolve through couplex interactions among the transporta-
tion mode, commodity, and the commodity's origin. Fuel movement and routing are
subject to constant change. Competition between fuel carriers insures a high

degree of flexibility in the transportation pattern. It is through the existence
of such a network that fuels used in the Great Lakes Region can originate from
such diverse areas of the country as the Louisiana Gulf Coast or the Nor th Slope

of Alaska.

Historically, coal, oil and natural gas have been transported by rail,
waterway, truck or pipeline throughout the Great Lakes states.
The railway system is comprised of more than 200,000 miles of track,
with the greatest concentration existing in the eastern half of the country.
Coal, as a high bulk commodity, is well suited to transport by rail. @Railroads
haul 78% of the coal and less 'than 3% of the oil and gas in the country [3641.
Recent innovations, particularly the advent of unit trains, have substantiall-
y
lowered the costs of hauling large volumes of coal. Approximately 20% of all
coal mined in the United States presently movesby unit train [147]. The unit
train "consists of a dedicated set of haulage equipment loaded at one origin,
unloaded at one destination each trip, and moving in both directions on a pre-
determined schedule. The unit train combines three principle factors: design
efficiency, equipment balance, and intensive use. To achieve the lowestpossible
transportation costs, all elements of the operation must be i n balance; the
loading, haulage, and unloading facilities must be designed and scheduled for
intensive use but not to a degree that would bring intolerable maintenance costs;
the haulage capacity must be in balan ce with supply, with the consumer's needs,
and With amortization requirements" [3101.

TABLE 54

IC FUEL FIGURES
STEAM-ELECTR

MARCH 1975-FEBRUARY 1976

New York Penn. Ill. Indiana Mich. Ohio Wis. 14.1nn. TOTAL

3
1975 oil delivery 86,128 13, 105 7,365 l.'530 15,879 1,373 471 773 126,624 x 10 bbl
Avg. cost/bbl $11. o $12.74 $12.16 $112.41- $12.36 $13.90 $11.24 $12.35
Number of reporting 22 31- 15 13 14 25 8 10 160
plants
Percent of total 77.1% 8.8% - 5.4% 1.2% 114.6% 1.2% 1.22 2.4% 14.6%
-A-TU 36,733.3 33,499 30,968 21,361 46,860 11,552 8,797 196,242 x 1()31
1975 coal delivery 5,972 tons
Avg. cost/ton $28.31 $22.45 $15.28 $12.57 $21.84 $20.86 $18.35 $11.18
Number of reporting
plants 10 27 25 26 25 35 18 17 183
Percent of total 211% 91.1% 90.67. 97.14% 80.1% 1 94.17 94.1% 89.6% 83.1%
Btu
Gas 2.3%
Total energy used
for power plants 11.9,016 160,037 143,361 124,402 101,323 188,818 46,679 35,965 911,000
in [email protected],j,x 103
Ma I Pnt-) -

Compiled from FPC data.

310

Unit trains in the Great Lakes Region have primarily hauled coal to the
consumer directly'from the mine. Unit train rates were developed through major
long-term contracts for all rail coal movement from mine to consumer. Railroads
,have been unwilling to offer such rates to portsand terminals. Rail companies
would naturally prefer to contract for coal movement to the final destination
rather than short-hauling for transshipment to lake carrier. The Lake Carriers
Association recently received a favorable ruling concerning the establishment of
unit train rate's to the Lake Erie ports. Additional litigation on this-matter is
expected. Unit train transportation is not excluded from all ports on the Great
Lakes. Of,notable exception is the transshipment facility in Superior, Wisconsin.
Unit trains 100 cars in length are loaded in Montana and hauled 800 miles east to
deliver 10,000 tons of western coal to the coal transshipment facility at Superior.
Operations of this sort represent a significant improvement in the historical
.transportation of coal by rail.
Rail transport of coal, traditionally parochial in nature, is expanding
to markets well beyond the regions of production. Efficient utilization of rail
transportation on this scale.relies on rapid turnaround time in loading and un-
lo,ading as well as, stable and well constructed road beds capable of withstanding
the stresses of 10,000-ton unit trains.
The shipment of coal by rail accounts for 57% of 'the total coal movements
for electric utilities in the Great Lakes states. The two largest coal consuming
states in the country, Ohio and Pennsylvania, move 34% and 36% of their coal for
electricity by rail [604]. The rail network, although extensive in these states,
competes with the inland movement by barge and truck to utilities. However, it
should be stressed that these competing modes of transportation occur largely
outside the Great Lakes Basin. Some of the largest,coal mines are located near
the Monongahela and Ohio Rivers, which assume a large portion of the coal
traffic by barge. Economical movement by truck is generally restricted to the
regions of coal production located well inland of the coastal counties. There-
fore, the rail system, unencumbered by the geographical and economic restraints
affecting river or truck transportation, primarily serves the coal demands of the
Pennsylvania and Ohio utilities located in the coastal counties along Lake Erie.
Illinois and Indiana are also large producers of coal. The percentage of
rail transport for electric utilities is considerably greater in these midwestern
states than in Ohio and Pennsylvania. Indiana and Illinois move better than two-
thirds of the coal used for electric power generation by rail. This traffic

311

supplies fuel for the enormous industrial and residential power demands in the
Lake Michigan coastal counties.of Illinois and Indiana. More than half of the
coal moved by rail for electric utilities is produced within'the states' borders.
Recently the influx of low sulfur western coal has taken a larger share of the
coal movement by rail. Thirty-eight percent ofthe rail movement to Illinois
originated in Montana and approximately 15% of Indiana's coal for electric power
generation was produced in Wyoming. As demands for low sulfur coal increase, rail
traffic can be expected to realize an even greater share of the coal transporta-

tion market in Indiana and Illinois.

The four northernmost Great Lakes states of Minnesota, Wisconsin,

Michigan and New York are north of the bituminous border that runs through
Illinois, Indiana, Ohio and Pennsylvania. The northernmost states must import
virtually all their fuel supply for electric power generation. The transportation
sector, particularly the railroad industry, benefits from this situation. -This
is especially true in Minnesota and New York, whose geographic location have
historically precluded extensive coal traffic on the Great Lakes. In 1975 over
80% of the coal used by utilities in Minnesota was transported by rail. All but
15% of this coal was mined in Montana. New York similarly received approximately
80% of the coal delivered to utilities by rail. This coal was mined primarily in-
eastern Pennsylvania and West Virginia. Although the percentages for rail traffic
are high in these two states it should be noted,that'the total tonnage of coal

consumed by utilities in New York and Minnesota are the*lowest of the Great Lakes
states. Combined, these s tates consume only about 8% of all.coal use for electric
power production in the Great Lakes states. Michigan and Wisconsin consume more
than twice the coal used in New York and, Minnesota. Here again rail transporta-
tion is the dominant method of coal movement. These states, however, are well
suited for coal transport by lake vessel. Consequently, rail shipments to
Michigan and Wisconsin constitute a slightly smaller portion of the total coal
movement than in Minnesota and New York. In 1975, Wisconsin received 66% of its.
coal for electric utilities by rail. Most of this coal originated in Illinois
and Kentucky., Almost 30% of this fuel was mined in Montana or Wyoming and
transported by rail. Eastbound rail movement from Montana and Wyoming can be
expected to increase in the near future. Two p lanned power facilities in
Wisconsin's Lake Michigan coastal counties, Edgewater and Prairie View,
anticipate delivery of western coal by unit train. Although Michigan has more
shoreline than the remaining seven Great Lakes states, rail movement comprised

312

71% of the total coal shipments in 1975., More than 80% of this rail movement
originated in Ohio and West Virginia. The dominant position of rail over water
transportation in Michigan can bepertially attributed to the locations of the
major load centers in the southern portion of the state. The growth of unit
train movement directly to utilities1n the Detroit area has affected the tradi-
tional short haul by lake vessel from the coal loading ports on Lake Erie.
Railroads, as previously mentioned, prefer to control the commodity's
transportation from mine to consumer. They are not, however, interested in totally
displacing the coal commerce of the lake carriers. Each major coal shipping port
is serviced by a particular rail company which delivers coal to the facility.
An extensive rail network supplies the lake ports with coal for.transshipment to
the waterways. Other rail companies not directly serving the ports may do so
indirectly by delivery to a number of inland "turnover points" where coal is
transferred to the rail company serving a port for final delivery. The
Louisville and Nashville Railroad Company indirectly serves many of the Lake
Erie coal ports in this manner.
This symbiotic relationship with railroads is necessary for economical

coal movement by lake carrier. Michigan and Wisconsin are the only Great Lakes
states that receive appreciable tonnages of coal by lake vessel. In 1975,
Michigan received 29% of the coal for electric power generation from Great Lakes
vessels. Approximately 40% of the lake traffic to Michigan originated in West
Virginia and Kentucky and was transshipped via the Lake Erie ports [604]. The
coal destined for Wisconsin ports primarily originated in the midwestern coal
fields of Illinois, Indiana and Kentucky and moved onto the lakes through the
port at. South Chicago. This movement of coal has diminished almost by half over
the last ten years.
Western coal, notably from Montana, is presently taking a larger share
of the coal movement on the Great Lakes. Originating from a new transshipment
facility in Superior, Wisconsin, western low sulfur coal traffic on the Great
Lakes represents a reversal of the traditional patterns.of movement by lake
carriers. Historically, iron ore and coal have been complementary commodities
for dry bulk transportation on the Great Lakes. Vessels hauling iron ore down-
bound from Lake Superiorto Lake Erie could reload with coal for the return
upbound passage.
The advent of western coal movement on the lakes complicates this
traditional commodity exchange flow. The additional coal traffic from Lake

313

Superior has spurred construction of new bulk cargo vessels. The dimensions of
new vessels on the Great Lakes are increasing with the capacity of the locks to
accommodate them. The completion.of the'Poe Lock at Sault Ste. Marie in 1970
increased the limitations on'vessel dimensionsto 1,000 feet length and 105 feet
beam. This development permits construction of vessels with a carrying capacity
over 56-.000 tons or'approximately twice as much'as any prior lakers [2511.
Although the number of commercial vessels on-the Great Lakes has decreased by
.one-half since 1960, the increased capacity of vessels presently on the lakes has
compensated for this'decline so that there is a.total decrease in carrying
capacity of only 10% [2901.
The extension of the-shipping season on the IGreat Lakes may also have a
minor impact on the waterborne movement of coal. Coal is generally stockpiled
on site in quantities sufficient for the demand over the winter months. The
beneficiaries of.an extension in the shipping season would most likely be the
smaller, older shoreline plants located primarily on the-western-shores of Lakes
Michigan and Huron. These utilities with smaller storage.facilities must
presently supplement winter stockpiles with deliveries by rail. With season
extension the percentage increase in coal tonnage shipped on the Lakes would be
less than 5% [243].
take vessels also transport crude petroleum and petroleum products. The
development of an extensive pipeline network throughout the region has substan-
tially reduced tanker transport of these liquid fuels. Petroleum, a minor fue 1
commodity for electric power generation in the coastal counties of the Great
Lakes, can be expected to continue to decline in movement on the Lakes with
additional pipeline construction in the region. The heavy fixed investment and
economies of scale are cited as reasons for the favorable share of the market
assumed by pipeline transportation [147]. The possible movement of oil onto the
lakes by ocean-going tanker is restricted by the limitations of the St. Lawrence
Seaway and the connectin g channels,of the lakes.
On a much smaller scale there is barge movement of oil on.the lakes for
power production. Specifically, the oil-fired energy facilities in Oswego,
New York, receive oil by barge. Originating from oil storage facilities in
Montreal, barges supplied the Niagara-Mohawk Oswego facilities with.approximately
4.5 million barrels in 1975. Coal is also transported by barge. The Common-
wealth Edison Company uses barges to deliver four to five million tons of coal
per year to electric facilities in and around Chicago. Low sulfur western coal

314

is transported,by tail to a transshipment poi nt on the Illinois River near
Peoria. Barges move up river delivering 1,250 to 1,450 tons 'of coal per barge.
The Conmonwealth Edison Company has long been committed to this method of coal
transportation and anticipates continued use of barges for fuel transport.
Movement of crude oil by pipeline is routed from Duluth-Superior through
Michigan to Sarnia, Ontario, and another line from the same origin runs parallel
to the western shore of Lake Michigan around the southern end of the Lake and
across Michigan to Sarnia. Additional supplies of crude are delivered from the
Gulf region to the major refining facilities along the Illinois and Indiana
region of Lake Michigan. Refined products from refineries throughout the Great
Lakes states are transported via a major refined products pipeline network
concentrated in the major industrial load centers throughout the Great Lakes
Region. Pipelines can also carry a coal slurry. Finely pulverized coal can be
mixed with water and pumped through a pipeline at.about three and one-half miles
per hour. At the destination point coal is removed from the water by a filter.
A coal slurry pipeline once delivered coal to the Cleveland area. Completed in
1958, operations ceased in 1963 when railroads lowered their rates to compete
with the line. Future development of coal slurry pipelines is presently
constrained by the inability to acquire legal rights-Of-way across private
property, particularly railroad property. These pipelines also require consi-
derable quantities of water for the slurry mix. Availability of water is a major
limiting factor to the development of slurry lines.

b. Electricity

(1), Power
Use of electricity is growing faster than use of any other form of energy
in the United States. While the national average growth of energy consumption
was 4.8% per year from 1961-1972, the growth in electrical energy consumption
grew at an annual average rate of 7.3%, or doubled approximately in 10 years.
[576). A continuation of this rate would require approximately an eight-fold
increase in the present generating capacity, transmission capability and fuel
requirements by the year 2000. Improved efficiencies would slightly reduce the
magnitude of this increase. Though the amount of fuel would necessarily increase
proportionately, the mixture of fuel types used for power production has and will

continue to change.

.315

TABLE 55
U.S. DISTRIBUTION OF ENERGY CONSUMPTION BY:TUEL AND BY SECTOR

Fuel 1968 1973

Coal 22% 18%

Petroleum 44.2%_ 46%

Nuclear .2% 1%

Hydro 1.3% 4%

Natural Gas 32.3% 31%

[5761

Broken down further by sector use (1968) Office of the Secretary of Transportation

report, relative -importance of energy source:

Sector Coal % Gas % Pet. % Elec. % Total

Commercial 8.3 26.8 49.2 15.7 100

Industrial 26.2 43.3 20.9 9.6 100

Transport ..l 4.0 95.8 .1 100

Residential 50.1 34.8 15.1 100

For the period 1971-1975 annual growth in net electricity produced.varied
from a high of 8.6% during 1971-1972 to a low of 0.4% for the 103-1974. The
average for the 5"year period was 5.1%, with the growth rate during 1974-1975
being 2.6%.. These are national electricity production figures which should not be
confused with the increase in installed generating.capacity, which (over the 5-year
period) increased at an average annual rate of 8.2%. These statistics reflect
fairly accurately the conditions of.the eight Great Lakes states.
Nationwide, the production of electricity accounted for over 25% of the'
primary energy consumed annually. The electric utility sector's demand for energy
is.growing faster than that of any other sector, at approximately 8% per year
(pre-1973). Since the Arab oil embargo of 1973, the utility,sec.tor's demand for
energy has lessened-in response decreased consumption of electricity, due to such
factors as the increased cost of power and the depressed state of the economy,
As will be seen further on in the study, assessing future demand for electricity
is a most difficult task. The historical growth rate of approximately 7% is

316

no longer assumed to be the case in the post-1973 world of higher energy prices,
capital shortages, conservation measures, and economic misfortunes.
The economic growth of an area will often indicate a rapid rise in the
demand for electricity. Similarly, the growth in population and its electric
energy consumption habits will greatly influence the demand for electric power.

TABLE 56

CONTRIBUTION OF EACH FUEL'TO THE UTILITY SECTOR

U.S.
10 6kwh
prod. Coal Oil Gas Nuc. Hydro.
1960 57.3% 9.5 26.1 7.1

1973 1,859,120 45.7% . 16.8 18.3 4.5 14.6
1974 1,854,847 44.5% 16.1 17.2 6.0 16.1
1975 1,908,784 44.6% 15.1 15.7 8.7 15.7

Electric use growth rate (1973)

Residential 8.2

Commercial 9.6

Industrial 5.8

Transportation -

Electricity demand by sector (1973) (% used)

Residential 32%

Commercial 22%

Industrial 42%

Other uses 4%

317

(2) Populatioh
'@ically, population has been growing at a rate of 15% per decade, and
Histor
for the last few years the U.S. population has been growing at an annual rate of
just under 2% [U.S. 1975 statistical abstract]. In, comparison, the power gener-
ating capability in the U.@S. since 1955 has been growing at an annual rate of
approximately 7%. This indicates to some degree the increasing consumption of
energy per capita in the U.S. Tables 57 and 58 indicate the growth in energy
consumption that has taken place in the last few decades.

TABLE 57

PER CAPITA POWER GENERATION

Total Power
Pogulation Kilowatt-hours. Installed Kw Generated*
Year (10 people) per capita per capita (109 Kw-hr)

1955 164 3853 0.44 633

1960 180 4718 --0.53 849

1965 194 5969 0.68 1157-

1970 205 8100 0.93 1660

1975 (est) 221 10450 1.19 2310

1980 (est) 2,31 14000 1.60 3300

[U.S. Statistical Abstract]

TABLE 58

TOTAL AND PER CAPITA ENERGY CONSUMPTION

Total Per Capita
10 12 B.T.U.) (10 6B.T.U.)

1920 19,782 182

1930 22,288 181

1940 19,107 181

1950 34,153 226

1955 39,956 243

1960 44,816 249

1965 .53,969 278

1970 67,143 330

1974 73,121 346

[U.S. Statistical Abstract, 19751

318

The preceding tables illustrate the growth in energy consumption in the
U.S. As population growth begins'to level off in the future, demand for energy
can be expected to continue increasing, although at a reduced rate.
The projected population of the U.S. as of July, 1976, is 211,909,000.
At the same time the populations of the states within the Great Lakes Region,

were:

N.Y. 18,111,000
Penn. 11,835,000
Ind. 5,330,000

Ill. 11,131,000

Ohio 10,737,000
Minn. 3,917,000
Wisc. 4,566,ooo
Mich. -9,098P00O
74,725,000

The Great Lakes states contain 35.27% of the total U.S. population. Of the states
in the Great Lakes Region, the coastal zones (figures by counties) comprise 26%
or .19,415,897 of the total population of the eight Great Lakes. states. Table 59
shows the population'o.f the states' coastal zones as of July, 1975.,

TA BLE 59

GREAT LAKES STATES POPULATION BY COASTAL ZONE

Percent
Number of Coastal Zone Total State ,Population in
Counties opulation Population Coastal zone
N. Y. 10 2,696,600 18,111,000 i4.89

Penn. 1 273,780 11,835,000 2.31

Ind. 3 749,000 5,330,000 14-03

Ill. 2 5,765,700 11,131,200 51.8
Ohio 8 2,855,700 10,737,000 26.6

Minn 3 233,500 - 6.34

Wisc.. 15 1,928,400, 4,566,000 42.23

Mich. 41 4,898,200 9,098,000 53,83

(U.S. Census Bureau]

319

Major'changes-in the-p6pulations' of the eighe,"Great Lakes states do not
@'appear-likely; What does-'appear to be happening within th&states is the
continued growth, in both numbers-arid density, of the Various Standard Metropoli-
tan Statistical Areas around the large cities. The growth of these areas has
implications for the concentrating-of the utility's-load centers. This concen-
tration of population and load centers around-the large metropolitan areas will
affect the siting of facilities@and the flow of electric power in and out of the

Great Lakes coastal zone.

(3)_ Power Flows in the Great Lakes Coastal:Counties
The relationship of el6ctical power flows moving,in and out of the
coastal counties is a major considerati6n in attempting to assess the importance
of electric generating facilities in the future. Power flows in and out of the
coastal counties are fiot'constant with respect to both'direction and amounts.
Further, once electricity leaves the generating unit it is' virtually impossible

to determine its final destination.

Electric power flows-within the co.astalcounties.of Lake Michigan are
easily*defined on a large scale. On thesimplest level, powergenerated in rural
coastal counties flows inland from the coast, whereas power generatedin urban-
metropolitan coastal areas is generally consumed within the coastal counties.
Beyond these simple observations, el ,ectrical energy flows vary according to
region and are a function of a particular power pool's varying requirements.
The Michigan Electric Power Pool a combination of Detroit Edison and
Consumers Power Co.) regulates electrical flows throughout the state, constantly
monitoring loads, @osts 'of power generation, and related factors in the effort
to provide the lowest cost, most efficiently derived electric power. Given that
power flows within the state are not the same on any two days,-attempts to
specify coastal counties' electrical energy flows.are impractical. However, what
can be determined is the direction of average flows for large cities near the

coast.

Generally, electric,power flows into cities such as Detroit, Chicago, and
Cleveland. The Chicago area has more than 5 million people living in.its two

Communicatio n, Michigan Electric Power Pool.

320

coastal counties-and only four coastal power generating units. The Chicago
metropolitan region-is the load 'center for Commonwealth Edison, whose service
area extends over most of northern I-11inois. For the Chicago region there is a
constant need to bring electricity into the coastal counties, predominantly from
the-south and west. With-the difficulty of obtaining sufficient coastal
properties within the Commonwealth Edison Service Area and transmission rights-
of-way in the metropolitan area, additions to generating capacity which involve
new coastal sites would seem unlikely, so there will be a.continued reliance on
noncoastal zone electric power supplies.
The Detroit Edison Company, with a service area of 7,600-square miles, is
an example of a utility with its primary load center and a high percentage-of
generating capacity located in the coastal zone. The generating facilities
located within the Detroit metropolitan coastal counties produce power less
efficiently than those located on the St. Clair River and Lake Erie, so that on
light load days only 10% of Detroit's power is generated within the metropolitan
area, the other 90% coming from the north and south. On heavy load days., only
75% of Detroit's-power comes from these areas, because the output from the
inefficient Detroit plants is increased. The St. Clair River, Detroit River,
and Lake Erie generating facil ities are largely located in the coastal zone,
making intracoastal power flows predominant in the eastern Michigan area.
With a service area of 1,700 square miles, Cleveland Electric Illuminat-
ing Company has both a very concentrated load.center and, by comparison to
Detroit Edison and Consolidated Edison, a concentrated service area. The

Cleveland municipal plant has the ability to generate 90% of the portion of
the needs in its,service areas. However, there are three generating facilities

that produce with greater efficiency and at,lower cost most of the metropolitan
areals,needs. Cleveland Electric Illuminating Company's generating facilities
are closer to its load center than either Detroit Edison or Commonwealth Edison,
with the major plants located close to Lake Erie. As with Detroit Edison, the
power which Cleveland Electric Illuminating Company generates is consumed within

the coastal zone.

Communication, Commonwealth Edison.

Communication, Detroit Edison.

Communication, Cleveland Electric Illuminating Company.

321

The Milwaukee metropolitan area is the largest-consumer served by the
Wisconsin Electric Power Company. The area's industrial sector uses approxi-
mately two-thirds of the power produced by the utility. This high percentage
reflects the heavy industrialization of.the Milwaukee area. The electric power
is generated on the coast, with much of this within the Milwaukee metropolitan
area. The remainder of the Milwaukee base load is generated in the coastal
zone north of Milwaukee at the Point Beach.plant (this assumes the Oak Creek
plant to be in the Milwaukee metropolitan area). The power flows for Milwaukee

are intracoastal.

More power is produced within the coastal zone of New York than is
consumed locally. The inland location of many New York population centers,
combined with the difficulty of siting power facilities in many parts of the
state, suggests the reason for intensive energy facility siting in the coastal
zone. Generally, power flows from west to east in New York State. Areas such
as Oswego are rapidly:becoming major energy exporting centers. The number of
power plants and transmiss ion facilities existing and being planned suggests the
importance of the coastal'zone in supplying inland areas with large blocks of
power [449]. (For example, utilities such as Long Island Lighting Company and
Orange and Rockland Utilities, Inc. are joining in construction of Oswego area
power facilities.) The Niagara Falls-Buffalo area produces large amounts of
power,-but due to heavy industrialization, exports smaller quantities of electri-

city to more eastern areas.
The variations that have developed in electrical energy produced in
the coastal zone and its end use are the result of the needs of the regional
power pools, availability of facility sites and transmission line rights-of-way,

and location of fuel and water resources.

Communication, Wisconsin Electric Power Co.

Communication, New York Power Pool.

322

-- --- --------

3. EXISTING ENERGY SUPPLY FACILITIES

a. Electrical Generation

(1) Types by State and Region
The types of generating facilities in the Great Lakes region are currently
reflected in the region's fuel mix, described in Section IV.B.2.a.(3). The
average capacities of the different types of facilities varies. Modern nuclear
facilities average between 900-1000 MW each whereas most coal-fired units are
around 600 to 800 MW. The majority of hydroelectric and gas facilities are quite
small and are often used for,peaking purposes.
The locational requirements for the different generating types varies
considerably, according to fuel types. Hydroelectric facilities have the most'
obvious restrictions as to where they may site. These restrictions suggest a
limited future role for hydroelectric power. The possible exception to this
would be a further development of pumped storage facilities, but these also have
very stringent locational restrictions.
A primary'siting consideration for fossil-fuel,plants is the location of
existing or planned fuel transportation. In the past few years environmental
considerations have become a major factor in determining the location of a
fossil-fuel generating plant. Air quality.regulations are especially pertinent
to coal-fire,d facilities. In addition to.environmental and fuel considerations,
fossil-fuel plants have and will continue to locate where water is available.
The location of nuclear facilities has been dictated by two primary
considerations: (1) availability of water, and (2) availability of enough land
for the, required zone of exclusion. Fuel transportation is not a major considera-

tion in the location of nuclear facilities.

There does not appear to have been a preference of one fuel type over
another in locating in the coastal, zone. Recent trends, however, suggest that a
higher percentage of nuclear,facilities have and will be located in the coastal
counties. Future preference for locating in the coastal zone will be dictated by
the following considerations: (1) water availability, (2) access to fuel transport
routes, (3) environmental quality standards, and (4) land in sufficien t quanti-
ties for exclusion areas. The following shows.a rough breakdown of the quantity
of each state's generating capacity.

323

Table 60 POWER GENERATION BY STATE

ILLINOIS

Elec. produced 94,480 GWh
Installed gen. cap. 25,942 MW [F.P.C. News June 4 12/31/751
Gen. cap. in C.Z. 3267.25 MW [322]
% of total cap. in C.Z. 12.5%
Future scheduled or planned gen. cap. 16,880 (planned through 1984)
Planned expansion in C.Z. None

WISCONSIN

Elec. produced 35,063 GWh
Installed gen. cap. 8,881 NRC
Gen..cap. in C.Z. 5574.3 MW
% of total cap. in C.Z. 59.6%
Future scheduled or planned gen. cap. 5333 MW
Planned expansion in C.Z. 1,560 MW

MICHIGAN
Elet. produced 72,074 GWh
Installed gen. cap. 18,926 MW
Gen. cap. in C.Z. 17229 MW

of total cap. in C.Z. 73%
Future scheduled or planned gen. cap.'10232 MW
Planned expansion in C.Z. 9557 MW (include D.C.,Cook unit 2)

OHIO

Elec. produced 105,665 GWh
Installed gen. cap. 25,225 MW
Gen. cap. in C.Z. 5514.4 MW"
% of total cap. in C.Z. 21%
Future scheduled or planned cap. 10,077 MW
Planned expansion in C.Z. 5,300 MW

INDIANA
Elec. produced 65,421 GWh
Installed gen. cap. 13,315 MW
Total cap. in C.Z. 2,918.956 MW
% of total cap. in C.Z. 20.4%
Future scheduled or planned gen. cap. 6,516 MW
Planned expansion in C.Z. 685 MW (nuclear) (indef.)

324

MINNESOTA
Elec. produced 28,289 GT& [F.P.C.-I
Installed gen. cap. 6,707 M-
Gen. cap in t.Z. 324.329 MW
% gen. cap., in C.Z. 5%
Future scheduled,or planned gen. cap. 2,,820 MW
Planned 'expansion in C.Z. - None.

PENNSYLVANIA

Elec. produced 111,762 GWh
Installed gen. cap. 28,770 MW
Gen. cap. in C.Z. 118 MW [3221
% of total cap. in C.Z. .4%
Future scheduled or planned gen. cap. 13,120 MW
Planned expansion in C.Z. 800 MW

NEW YORK

Elec.. produced 109,521 GWh
Installed gen. cap.,29,500 MW [F.P.C. Jan. 1, 1976]
Gen. cap. in C.Z. 7,968 MW
% of total cap.., in C.Z. 27%
Future scheduled or planned gen. cap. 15,829 MW [F.P.C. Jan.. 1, 19761
Planned expansion in C.Z. (1100 Nuc) 3,950 MW

.(2)- Electrical Transmission

With the development of the electric reliability councils during the
mid-1960's @the electrical transmission network within the Great.Lakes Region has
become.increasingly reliable. A primary function of these councils is to promote
the comprehensive.planning of both generating facilities and transmission net-
works-Theireliability councils have helped to coordinate overall design of the
transmission grid for the purpose of balancing power flows between load centers

and the generating units,,the sharing of power between utilities, and the overall
efficient operation of,,the region's generating capacity. Further, inter-utility
buying and selling of power has been encouraged by the development of a compre-
hensive transmission networki One benefit of pooling power is the reduction in
generating capacity needed by an individual utility to compensate for emergency

generating outages or days of extra heavy load.

325

The development of power pools such as the Michigan Power Pool or CAPCO
was predicated-upon the ideas of sharing and coordinating resources and providing
the least expensive power possible. The practices of the utilities and power
pools have become very complex, such that at any given time it is nearly impos-
sible to determine the,destination of locally generated power. With the develop-
went of inter-utility electric reliability.councils and power pools, the siting
of new generating units is no longer heavily dependent upon proximity to large
load centers. To assure transmission line stability and interregional power
reliability, some new generating uni ts may locate outside of the general proximity
of large load centers.
The development of a comprehensive and efficient transmission network has
increased the flexibility in energy facility siting. The.D.C. Cook nuclear
.facility, located in Michigan and owned by the Indiana and Michigan Power Company,
is a good example of a generating unit able to locate hundreds of miles from the
load areas it serves, due to the availability of an efficient long distance
transmission network. Cooling water from Lake Michigan was the primary reason
for the selection of the Michigan site, while the EHV (345 and 765 kV) transmis-
sion network made it economically feasible to serve the widely dispersed demands
of the American Electric Power grid.
The bulk transmission system of the region is predominantly comprised of
345 kilovolt (kV) lines. The use of high voltage transmission lines allows large
transfers of power at a very high efficiency. The overall efficiency of the

electric transmission network is lowered each time the power is stepped down to
a lowercapacity'line, so it is beneficial to transmit power along the higher
voltage power@lines over long distances. Future transmission network plans call
for the development of 765 kV transmission lines which will allow the transfer of
more power at a higher efficienc y than that of the 345 kV lines. The 765 kV
network presently operating in the Great Lakes Region is currently transmitting
the power generated at the D.C. Cook facility to the southwestern Ohio region.
The trend in transmission lines is towards larger, more efficient lines. A
continued emphasis is being place d on reliability and coordination of the entire
generating-transmi'ssion system.

326

b. Fuel Transshipment and Storage

(1) Facility Type and Size
Ports on the Great Lakes have shown a pattern of growth and development
towards efficient,and rapid handling of bulk commodities. Rapid growth in many
phases of transportation, particularly those concerned with the handling of bulk
commodities, forced the gradual disappearance of the old general cargo facility.
Typically located close to the downtown metropolitan area, these ports became
obsolete due to increasing demands for extensive land areas, access to major rail
facilities, waterfront dockage capable of accommodating larger vessels, and
closer proximity to outlying industrial complexes.
Bulk cargo terminals are designed specifically to handle materials such
as grain, ore, coal and oil efficiently and quickly. Fuels, coal and petroleum
products account for a significant portion of the bulk commodity trade on the

lakes.

(a) Coal

In 1974 the 35 million tons of coal shipped on the Great Lakes accounted
for about 17% of the total foreign and domestic freight shipped on the lakes.
This was the third largest single commodity handled that year. Coal is shipped
from three primary regions on the Great Lakes: southern Lake Erie, south Chicago,
and Superior, Wisconsin. Together these ports shipped over 95% of the totallake
coal traffic in 1975 [2901.
The Lake Erie coal ports of Toledo, Sandusky, Lorain, Conneaut, and
Ashtabula transship coal originating in West Virginia, Pennsylvania and Ohio.
The combined tonnage of coal shipped from these ports was over 33 million tons,
or .85% of all coal shipments on the Great Lakes in 1975 [290]. This massive
commodity shipment is partially counterbalanced by receipts of iron ore from
mines in the upper Great Lakes for.use in the iron and steel industries located
along the Ohio River and its tributaries. The ports developed as the gateways
for coal demanded by,northern utilities and industries and iron ore demanded by
foundries in Ohio and Pennsylvania.
A brief survey of the ports follows.
0 Toledo--The port of Toledo typically handles more coal traffic than the
remaining four major facilities on Lake Erie. Coal shipments in 1975 increased
11% from 1974 to 14.6 million tons [2901. This was a reversal of the previous
four-year downward trend. Four of the six coal piers are served by the Chessie
System while the Baltimore & Ohio and Pe nn Central service the remaining piers.

327

The port has.no coal storage areas employing direct-rail-to-ship transfer. The
combined unloading speed for the six piers is 15,900 tons per hour.
e Sandusky--This port is served by the Norfolk and Western Railroad.
Its"unloading equipment can handle 3,500 tons per hour. In 1975 Sandusky shipped
4.3 million tons of coal. This was a slight increase over coal shipments in 1974
but less than the tonnage figures for the 1972 and 1973 Phipping seasons.
Storage capacity is 910,000 tons.
Lorain--Lorain is the smallest of the LakeErie coal ports. Served by
the Chessie System, the port has lost,more than half its coal traffic since 1973.
In 1975, Lorain shipped 1,264,954 tons. The port uses very little of the
approximately 80 acres available for storage. It can load coal at a speed of
2,700 tons per hour.
e Asihtabula'@.-Pomparable to Sandusky in coal traffic volume, Ashtabula
coal shipping was up approximately 400,000 tons,over 1974. Penn Central serves
this port, which is capable of loading 8,000 tons per hour. Total coal storage
capacity is presently 1.4 million tons.
0 Conneaut--Conneaut ranks second in coal tonnage shipped from Lake
Erie ports. Between 19,74 and 1975 this port increased tonnage shipped almost 20%
to 8.3 million tons.. Conneaut has direct rail connections with the Bessemer and
Lake Erie Railroad. Itcan store 4 million tons and has a loading speed of,

10,000 tons per hour.
Four.million tons, or 10% of the total coal. shipments on the,Great Lakes
in 1975 were shipped out of the South Chicago port facility. This facility is
the major coal,shipment area on Lake Michigan. In 1975, 3,943,165 tons were
shipped from this port...The facility,is,served by the Belt Railway Company of
Chicago and is a transshipment point for coal mined in western Kentucky, Indiana
and southern and,central Illinois. Coal shipments from this facility have
steadily declined.t,o essentially half of what they were in 1967. The port can load
two vessels simultaneously at a total of 5,000 tons.per hour.
A new port in Superior, Wisconsin, presently competes with.the South
Chicago and Lake Erie ports. Superior has become the third ma*or coal shipping

port due to the attractiveness of low sulfur western coal. The new Superior,
Transshipment Terminal presently receives coal from Burlington Northern Railroad
unit trains. The unit trains consist of 100 cars each hauling 100 tons. Coal
is loaded in Montana and travels 800 miles east to the Superior coal facility.
This terminal has the capacity to transship 14 million tons annually. The

328

facility is designed for an eventual expansion to 20 million tons throughout. Coal
is unloaded from the train, transported by inclined conveyor to a 1,200 foot
long elevated truss which evenly stockpiles the coal beneath it. The storage
area has capacity for 7 million tons. Coal is reclaimed by four rotary'plow
feeders beneath the stockpile which feed the coal to a 96-inch conveyor capable
of moving 11,000 tons-per hour. This conveyor feeds the shiploader, which is the
largest in the world in terms of volume handled per'unit time [605]. In 1976
Superior harbor will ship 2.2 million tons. By 1980 it is expected that through-
put will increase to 8 million tons.
Table 61 shows the tonnage of coal shipped and received at the major Great
Lakes ports in 1974. The ports and terminals that receive and store coal are
typically comprised of many private facilities designed to accommodate the fuel
needs of a specific factory or power plant. For example, the 6.5 million tons
received in Detroit in 1974 is the combined total for 23 separate coal facilities
reported to exist at the Detroit Harbor. Twelve are situated along the Detroit
River; nine are located on the Rouge River and two are on the Short Cut Canal.
The combined storage capacity of these facilities is 5 million tons [584].
Table 61 shows that coal received in Chicago does not arrivevia the
Great Lakes. The waterborne movement of coal to Chicago is handled primarily by
barge traffic up the inland waterway system connecting the Great Lakes with the
Mississippi River Basin. There are 17 facilities that handle coal in the Port of
Chicago.- Eleven facilities report a total storage area of 68.7 acres. The
remaining six.facilities have a combined coal storage capacity of 2,360,000 tons
[5831.
The existence of the many private coal unloading and storage facilities
.within a port indicates that industry has found there are positive economic and

environmental benefits to the direct C .ontrol of coal deliveries. Offsite un-
loading and storage results in increased costs from additional handling to
transport the.coal to the site of consumption and added environmental impacts.
For example, the Upper Peninsula Generating Company in Marquette had no storage
facility at the plant site until recently. Coal was held for the company at the
Marquette Dock Company, four miles away, and transported by rail to the power
plant. The intermediate transportation of coal was costly and restrictive. The
company anticipated expansion of generating capacity, so it constructed a new'coal
facility, located approximately 600 feet from the plant to receive coal directly
from self-unloading vessels. The harbor has a storage capacity of 500,000 tons

329

Table 61

MAJOR COAL SHIPPING OR RECEIVING FORTS, 1974
(Thousands of Short Tons)

Foreign Domestic
Total Overseas Canadian Coastwise Lakewise Internal
U.S.. Receiving [email protected]

Port of Detroit 6,571 1 6,570 -
Port of Chicago 5,024 - 1 5,023
St. Clair River, Mich. 3,046 3,046
Muskegon, Mich. 1,919 1,919 -
Green Bay, Wis. .1,606 1,606 -
Marquette, Mich. 909 909, -
Duluth-Superior 892 892 -
Milwaukee, Wis. 890 890
Total 20,857 .0 1 0 15i833 5,023
Percent of Total 100% - - - 76% 24%@

U.S. Ship2ing Ports
Toledo, Ohio 12,732 2,911 - 9,821 -
Conneaut, Ohio 6,719 - 4,699 - 2,020 -
Port of Chicago 4,150 2 37 - 4,113 -
Ashtabula., Ohio 4,186 - 3,017 - 1,169 -
Sandusky, Ohio 4,059 60 2,257 - 1,742 -
Lorain, Ohio 2,015 2,015 -
Duluth-Superior 821 12 13 796 -
34,682 T_ 21,676 0
Total @_2 12,934 0
Percent of Total 100% 0.3 37.2 62.5% -

Sources: Waterborne Commerce of the United States, Part 3, Waterways & Harbors,
Great Lakes, 1974.

and is designed for eventual expansion to accommodate three new generating units
in Marquette. This new development is but one of the numerous and highly site-
specific coal unloading facilities that exist throughout the Great Lakes system.
Greenwood's Guide to Great Lakes Shipping lists 90 such facilities.
Storage capacity at these coal unloading docks ranges from 2.5 million to 5
thousand tons. Most of the facilities are owned by electric utilities or steel

and cement industries.

330

A fairly recent design feature that has become commonplace among the coal
receipt docks is coal delivery from self-unloading vessels. The development of
the self-unloading vessel.has eliminated the need for much of the expensive
unloading equipment-that previously dominated coal unloading sites. A self-
@unloading vessel has hoppers with a V-shaped bottom located in the hold of the
ship,,which allow the coal.to be dumped onto-a conveyor belt located in a tunnel
at the bottom of the ship. Bucket elevators then life the coal out of the hold
to another system of conveyors which swing out from either side of the ship and
dump the coal directly onshore. These ships can carry 35,000 tons and unload at
a rate of 3,600 tons per hour. Once in storage the coal is then fed mechanically
or by bulldozer.to a belt conveyor'feeding the plant [5661.

(b) Oil
Oil is another major fuel commodity transported on the lakes. In 1975,
shipments of petroleum products totaled 11,545,789 net tons, which is approxi-
mately equal to 86,600,000 barrels. This represents a 9% decrease from 1974 and
a 23% decrease from shipments in 1973 [2901. The development of pi eline facili-
p
ties around the lakes has accelerated the decline in transport of petroleum
products by lake carrier. The network of pipelines and the physical limitations
of the Great Lakes-St. Lawrence'Seaway System have substantially restricted
movement of crude petroleum through the ports. In 1974, less than..o'ne percent of
the petroleum moved on the lakes was crude petroleum. Refined products,
particularly distillate and residual fuel oil and gasoline, are the major liquid
fuels carried by lake tankers.
Table 62 lists the major shipping and receiving ports for petroleum
products. Commodities considered in developing this table were crude petroleum,
crude tar, oil, gas products, gasoline, jet fuel, kerosene, distillate fuel oil,
residual-fuel oil, coke, petroleum coke and liquefied gases.
The bulk of products refined in the U.S. destined to be transported by
lake vessel-originates from the Indiana Harbor area of Lake Michigan. In 1914
Indiana Harbor was the shipping terminal for 77.,3%-of the gasoline, 81.3% of the
jet fuel, 70.4% of the kerosene, 70.6% of the distillate fuel and 40.0% of the
residual fuel oil shipped on the Great Lakes [5361. This facility is served by
one of the largest refineries on the Great Lakes, Amoco's Whiting refinery,
which has a capacity to process 360,000 barrels of crude petroleum per day.
There are eight major transshipment facilities located in Indiana Harbor. The

331

433 storage tanks in.the harbor have a combined capacity of approximately 15
million barrels [607]. Movement of refined products on the lakes through this
facility has remained fairly constant over the last 10 years. Crude petroleum,
,a minor commodity which was not handled in the harbor in 1974, is primarily
refined in the area for shipment as a refined product. The other,major petro-
leum shipping ports in 1974 were Chicago (10%) and Toledo (12%), which together
with Indiana Harbor (61%) handled over 80% of the petroleum products shipped on

the Great Lakes.

Table 62

MAJOR PETROLEUM SHIPPING OR RECEIVING PORTS, 1974
(Thousands of Short Tons)

F o r e i g n D o m e s t i c
-1,qn
Total Overseas Canad' Coastwise Lakewise Internal

U.S. Receiving Ports

Port of Chicago 3,776 - 7 - 682 @,087
Oswego Harbor 721 - 710 - - 11
Indiana Harbor 550 - - - @442 108
Milwaukee Harbor 534 - 6 - 522
Port of Detroit 314 - 210 4 100 0

Total 5,895 933 4 1P746 3,212

Percent of Total. 100 15.8 0.1 29.6 54.5

U.S Shipping Ports

Indiana Harbor 3,325 - - 3,325 -
Port of Chicago 1,111 - - - 556 555
Toledo Harbor 649 - 7 - 642
Port of Buffalo 244 - 12 - 227
Port of Detroit 201 3 198

Total 5,536 22 4,948 560

Percent of Total 100 0.5 89-4 10.1

Source: Waterborne Commerce of the United States, Part aj Waterways & Harbors,
Great Lakes, 1974

332

The Port of Chicago is the major receiving port on the Great Lakes.
Eighty percent of the petroleum traffic in.this port occurs-internally and
reflects movement by barge in and ar5und the facilities on the Chicago Sanitary
and Ship Canal and Calumet River.
In 1974 1.1 million tons of Canadian petroleum products were received by
U.S. ports. Most of this was residual fuel oil (913,779 tons). Of that amount
78% was received at Oswego, New York, and 10% was handled in Detroit.

(2) Capacity
There is a.subtle but important distinction to be made between port
capacity and port capability. The distinction reflects the difference between
historic perf ormance (capability) and estimated potential performance (capacity).
Capacity is in many respects an unrealistic term when applied to port activities.
Though often used, the term is often misunderstood. Capacity implies an upper,
limit to the quantity of cargo throughput and storage. The nature of port
operation tends to preclude such absolute characterization. Port capacity is not
a simple function of,the loading/unloading speed. The constraints of ship
scheduling, rail movements, traffic interruptions and delays each contribute to a
port's capacity to handle cargo. Additionally, the activity of a port can be
deceptive. Ports are designed to accommodate the reasonable seasonal and inter-
mittent peaks in demand. Therefore a certain amount of inactivity is programmed
into the function of a port and doesn't necessarily indicate thecapacity is in
excess of need [251]. Consequently, capacity is a constantly fluctuating value
dependent not only on the space and equipment at the port but also on the coordi-
nation, availability, and transshipment limitations of the various shipping and
receiving modes of transportation. The U.S. National Academy of Science [5481

points out:

It would be possible, of course, to design a port facility.so that
its capacity would be fully utilized at all times. Under this
situation, variations in demand would have to be accommodated by
delaying ships, forcing them to wait at anchorage until vessels
that arrived previously had been serviced. Also, cargo awaiting
ships would be delayed or would be routed through a competing port.
Although this approach to port operations would maximize the cargo
handled at a port for a given set of facilities, an economic
analysis incorporating both vessel cost and port facility costs
would show that such an extreme case of port operations would
represent a highly uneconomic use of resources. Conversely,
designing a port so that vessels are never forced to wait also
represents an uneconomic use of resources. As for any service

333

operation, the least total cost is obtained by minimizing the
sum of the costs of service facility construction.and operation
and the costs of ship and cargo'delays. This results in a level
of service at which vessels are infrequently forced to wait during
peak periods.

Determination of such an economic optimum point.requires a
complex and detailed analysis of each port. While queuing theory
and other concepts can be employed for the study of individual
facilities or elements in a port, the interconnections among these
facilities and elements are so complex that a sophisticated time-
oriented sim@lation procedure may be necessary to determine fully
the effects of modifications in facilities or changes in operating
costs of physical facilities requires simulations using as. inputs
varying numbers of berths, entrance channel configurations, storage
capacities, and operating policies and procedures. Such analyses
to determine the economic balance for a port are,-of course, costly
and time consuming, especially in the larger. and more complex ports.

The scope of this study precludes a detailed evaluation of the capacities
of the Great Lakes ports insofar as those capacities are determined through the
realization of a complex and largely site-specific analysis of the economic and
physical parameters of the port. In recognition of the variables associated
with port capacity, this study highlights the historic port transshipment capa-
bility.
The study briefly reviews the peak bulk throughput figures for. the major
fuel handling regions in the last ten years. A ten year time frame was chosen
because it was felt that a decade would provide an adequate rangeof yearly cargo
fluctuations with the least complications in equipment retirenie..nt and facility
modification.. This approach is felt to offer the most reasonable measure of the
Great Lakes ports' existing octential.forl,fuel transshipme nt. The approach is
conservative but appears realistic in terms of near, future coal and oil movement

on the lakes.

Coal shipments from the major coal ports of Lake Erie have declined 30%
within the last decade. This decline,is marked by an overall decrease of 13.9
million tons since 1966. In thatyear 47.2 million tons of coal were shipped
from Lake Erie ports. The year 1966 will serve as the high volume benchmark for
total shipments of coal from Lake Erie.' Over seventy percent of this total in
1966 originated from the port of Toledo This port has witnessed a decline of
19.1 million tons of coal shipments since 1966. Toledo has the present capability
to more than double its coal throughput.' Of the four remaining major coal ports
on Lake Erie only Lorain is regarded as presently operating considerably below

334

previous levels of coal throughput. This port,has had a nearly threefold decline
in coal traffic since 1973. In that year Lorain-shipped 3.6 million tons of coal.
In 1975 shipments had decreased to approximately 1.3 million tons. This port,
which primarily handles coal for electric power generation, plays an increasingly
minor role in the total Lake Erie coal traffic, contributing about four percent
to the combined coal shipments from Lake Erie in'1975. [2901.
The ports of Sandusky, Ashtabula, and Conneaut are presently running
either near or above peak levels of the last decade. Sandusky and Ashtabula
both presently ship approximately four and one-half million tons of coal and
are considered by their respective port officials to be operating comfortably
within the port limitations and foresee no major expansions necessary. Conneaut
is the only major Lake Erie port presently considering an extensive expansion of
facilities and storage.
In conclusion, Toledo could presently contribute an additional 20 million
tons of coal traffic to the system. Revitalization of smaller facilities such as
Lorain with additional growth in throughput from Sandusky, Ashtabula and Conneaut
could add substantially to this figure. Thus, in general terms, the ports of
Lake Erie are capable of nearly doubling present coal throughput. It should be
reemphasized however that such expansion is contingent upon the complex optimi-
zation of diverse activities such as coordinating rail-to-ship transfer and,
most importantly, upon a return to the high demand for coal originating in the,
Appalachian fields.

Shipments of coal from the South Chic ago facility have demonstrated a
decline similar in magnitude to the.Toledo facility. In 1975 this facility
handled less than half the coal it shipped in 1967. Resumption of coal trans-
shipment to 1967 levels would result in an additional four million tons of Great
Lakes coal traffic. Like Toledo, this area has historically transshipped coal
of a relatively high@sulfur content. The future revitalization of this port is
highly contingent upon the quality of coal originating from this port to the

lakes.

The new coal shipping facility at Superior, Wisconsin has been in opera-
tion only one year, so it is unreasonable to equate historic capability with the
,capacity limitations of the facility. This coal transshipment facility handles
low sulfur western coal from Montana. Reported to be the largest bulk handling
facility in terms of cargo handled per unit time, the Superior facility is
designed for an eventual transshipment capacity of 20 million tons per year.

335

This facility, in addition to expanded shipments through South Chicago and
Toledo, could essentially double the coal traffic tonnage moved on,the Great

Lakes in 1975..

The capabilities of the.system for coal movement on the lakes is
presently not in excess of need. This assumption is based on a nonspecific.
demand for coal quality and may vary considerably according to fuel quality. An
analysis of the factors affecting this demand is presented in the section on

regional scenarios.
The capacity of.facilities 'Shipping oil on the Great Lakes,i,s of lesser
concern in relation to a fuel supply for electric power generation in. the region.
The development of extensive oil movement by pipeline, combined with a negligible
future development of refinery capacity in the area, indicates at best a very
conservative rate of growth in shipping of petroleum products. Indiana Harbor,
the primary location of petroleum movement on the Great Lakes, reports operation
well within historic capabilities and anticipates no major-expansions.

(3) Demand
The pressures placed on the capabilities of ports and terminals.is a
function of the demand for fuels to be transported by lake vessel. The demand
for coal on the Great Lakes is largely generated by utilities, coke and gas
companies, and retail dealers. Coal.for utility consumption accounted for 51%
of the coal traffic on the lakes in 1975. Coke and gas facilities acquired 34%,
while 15% of the U.S. coal transshipped through U.S. and Canadian ports was
received by retail dealers and.other users. Of.the Great Lakes states only
Michigan, New York, Ohio and Wisconsin.were reported to receive bituminous or
lignite coal via the GreatLakes in 1975 [604.]. Nearly 47% of the present
market for U.S. coal transported on the Great Lakes is located in Canada [6041.
A number of projections havebeen developed forecasting thefuture demand
for Great Lakes coal traffic. These projections as analyzed in the Great,Lakes
Transportation System [1471 predict either growth or stabilization to occur on
the Great Lakes over the next 40 years.
The U.S. Army Corps of Engineers in 1961 projected coal movements on the
Great Lakes to increase steadily from 93.4 million tons in 19751to 148.5 million
tons in 2015. These projections were based on a study of the major consumers of
coal: electric utilities, steel plants and cement plants.

336

The projections by the Bureau of Mines (1970) assumed a growth rate of
Great Lakes coal traffic of 3.1% per year, commensurate with the national energy
needs through 1980. Increased development of nuclear power was assumed to reduce
this growth rate to 2.5% per year after 1980. This projection predicted that
73 million tons of coal would be shipped on the Great Lakes in 1995.
The International Great Lakes Levels Board (IGLLB) extended the Bureau of

Mines forecast beyond 1995, projecting stabilization of coal shipments at 74
million tons through the year 2020. This projection was balanced by their high
and low forecasts for Great Lakes coal shipping. The high forecast predicted an
increase of 73 million tons between 1970 and 1995. Beyond 1995 shipping levels
would stabilize at 134 million tons per year through 2020. The low projection
assumed a 1.25 percent growth rate until 1995 then.leveled off.at 43 million tons
through 2020. In either case the projections assume d the same ratio of-coal
production to shipping as postulated by the Bureau of Mines.
A recent projection of coal shipments for the Great Lakes Region,
published by A. T. Kearney Inc. in,1976 for the U.S. Army Corps of Engineers
[2431, seems the most likely of the trend projections (Table 63). The Kearney
study took a conservative approach in forecasting potential.western coal move-
ment on the Great Lakes and St. Lawrence Seaway (GL/$LS). Only the movements
currently planned were included in the forecast potential. Additionally the
study operated under the [email protected] that:
* Few, if any, existing facilities would be converted to western'
coal due to high conversion costs.

e Only new facilities that have announced plans for use of
western coal would be included in the forecast.

9 Stack gas scrubbers would be economically efficient and
available by 1990.

9 Current emission standards will remain unchanged throughout
the forecast period.

o Variances to burn high,sulfur coal will be extended until
stack gas scrubbing technology becomes available.

o Canada will adopt emission standards that will not preclude
usage of U.S. eastern coals.

o The development of nuclear power generation facilities will
be delayed and retarded by environmental, safety and economic
factors.

337

9 Environmental concerns regarding strip mining will not
restrict the growth of coal mine development in the West.

The Kearney projection of a 2% average annual increase shows coal move-
ment tripling by the year 2040. As the Kearney report points out, U.S. movements
assume the largest share of the total growth at 2.1% per year, while,Canada
initiates domestic movements and shows movement of 12.6 million tons by 2040.
This traffic is expected as a result of Canadian western coal movement to the
Lake Ontario facilities of Ontario Hydro.

TABLE 63

Potential GL/SLS Coal Movements
(Mi I I ion@i-of_T_o_ns)

United States Canada United States
Domestic Domestic to Canada Total

1972 Base 44.1 0 17.8 61.9
1980 58.3 5.0 22.7 86.0
i990 77.7 6.4 26.8 1.10.�
94.7 8.0 30.4 1-33.1
2010 114.9 10.1 34.3 15-9.3
2020 134.0 11.0 36.5 181.5
2030 156.7 11.7 38.7 207.1
2040 184.2 12.6 41.0 237.8

Source: A. T. Kearney, Inc.

Table 64 and Figure 36, adapted from Schenker [147] and with the addi-
tion of the Kearney projection, illustrate the variations among the previously
described demand projections of Great Lakes coal movement.
The demand for U.S. shipments of liquid fuels on th6'treat Lakes was, in
a projection by Schenker [147], determined to have difficulty competing with
pipeline transportation. Pipelines, as a long-term capital investment, maintain
a high rate of utilization once constructed. Therefore the continued development
of the pipeline network throughout the region was assumed to have a substantial
negative impact on the future demand for Great Lakes shipping of liquid fuels.
Rail movement, though usually more costly than waterborne movement, is important
to high volume consumers such as electric utilities, because of its reliability.

338

TABLE 64

PROJECTIONS OF U.S. GREAT LAKES SHIPMENTS OF COAL

(Millions of Short Tons)

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Corps of Engineers (1) 83.5 .93.4 106.7 114.6 124.9 130.3 135.0 139.6 143.2 148.5
(1961)

Bureau of mines (2) 53.0 [email protected] 62.0 66.0 69.0 73.0
(19,70)

IGLLB -High (3) 61.0 83.0 134.0 134.0 134.0
(1973)

-Medium (4) 53.0 62.0 74.0 74.0 74.0

-Low (5). 44.0 43.0 43.0 43.0 43.0
Kearney (1976) 81.0 104.5 105.1 149.2" 170.5

NOTE: The Kearney projections are for domestic traffic only
SOURCE: [1471

FIGURt 36
S@ort Tons
300 (Millions)
PROJECTIONS OF
U. S. GREAT LAKES COAL SHIPMENTS
(MILLIONS OF SHORT TONS)

200

100-

4
2

0 L
1970 1980 1990 2000 2010 2020

Year

339

The problems of storing large supplies of liq@uid fuels combined with the
seasonal nature of lake traffic encourages use of pipelines and rail transporta-
tion instead of waterborne movement. Schenker [147],, in considering expansion
of pipeline traffic and conservation efforts, suggests'the projection giving
slightly more weight to the immediate past is most accurate.

TABLE

TREND PROJtCTIONS,OF GREAT LAKES
AND ST. LAWRENCE SEAWAY SgIPMENTS OF
CRUDE PETROLEUM AND SELECTED PETROLEUM PRODUCTS
1975-1985

(Millions of Short Tons)

1975 1980 1985

Great Lakes

unweighted trend: 14.6 15.0 15.5

Weight of immediate past:

Slightly Stronger: 13.8 14.1 14.3

Strong: 13.61 13.7 13.9

Very Strong: 13.7 14.0 14.3

St. Lawrence Seaway

Unweighted trend: 4.5 5.4 6.14

Weight of immediate past:

Slightly Stronger: 3.9 4.3 4.7

Strong: 4.5 5.3 6.2

Very St rong: 4.6 5.5. 6.4

Source [1471

340

(4) Origins and Destinations 'of Fuels Handled
An important adjunct to the increased demand for fuels, particularly coal,
is the effect such demand will hav@ on the pattern of waterborne traffic around
the lakes. Competition between the various modes of transport, water, rail,
pipeline, etc., insures a constant flux in the patterns of movement between
origins and destinations.
Historically, the bulk of coal movement on the Great Lakes has originated
from the ports on Lake Erie. Located in proximity to the major Appalachian coal
fields these ports developed as transit points for coal and iron ore movement in
the region. Table 66 illustrates the destinations on a regional basis for coal
moving through Toledo, Sandusky, Lorain, Ashtabula and Conneaut.

TABLE 66

w,rUMINOUS COAL. SHIPMENTS TO UNITED STATES PORTS FROM LAKE ERIE

To U.S. To Lake To To To Lake To Lower To
Superior Sault Lake Huron Michigan Rivers Lake Erie Total
Toledo. 1,370,004 44,442. 301,878 1,427,757 7,254,639 823,954 11,222,674
Sandusky 725,539 40,590 100,090 45,857 511,177 78,742
Lorain - ... 161,507 --- 887,688 '215,759 1,264,954
Ashtabula 234,241 --- 192,244 267,976 37,494 --- 731,955
Conneaut 616,644 18,965 109,965 613,214 155,357 --- 1,514,345

Total 1975 2,946,428 103,997 865,693 2,354,804 8,846,555 1,118,455 16,235,932
Percent 11975 8.88 .31 4.06 7.10 26.67 3.37 48.94
Total 1974 2,521,287 232,090 1,210,502 2,568,195 9,576,23T 725,396 16,833,707
Percent 1974 8.46 .78 4.06 8.62 32.14 2.43 56.49

Thru
To Canada To Lake To To To Lower To Welland
Superior Sault Lake Huron Rivers Lake Erie Canal Total
Toledo 25,710 1,992,674 41,843 19,135 .32,839 1,319,745 3,431,946
Sandusky ... --- --- --- 51,005 2,785,050 2,836,055
Lorain - --- ... --- ---
Ashtabula 78,449 ... --- 943,606 943,737 1,887,061 3,852,853
Conneaut --- --- --- 1,937,872 2,781,988 2,098,794 6,818,654

Total 1975 104,159 1,992,674 41,843 2,900,613 3,809,569 8,090,650 16,939,508
Percent 1975 .31 6.01 .13 8.74 11.48 24.39 51.06
TotaI1974 229,145 1,791,127 48,269 3,151,810 1,487,482 .6,259,219 12,967,052
Percent 1974 .77 6.01 .16 10.58 4.99 21.00 43.51

SOURCE: Lake Carriers Association. Annual Report: Lake Carrier's Association. 1975.

341

The table shows that over half of the coal shipped from these ports is
destined for Canada. This trend is most pronounced at the ports of Conneaut and
Ashtabula, which ship 82 and 84%, respectively, of their coal to Canadian markets.
The cross-lake traffic in coal to Canada primarily supplies steel mills and the
power facilities of Ontario Hydro. Traffic to.utilities and the steel industry
accounted for 95% of the U.S. coal movement on the Great Lakes to Canada [6041.

The domestic movement of coal from the Lake Erie ports is dominated by
the Port of Toledo. Seventy percent of the Great Lakes coal movement to United
States ports originated from this po rt. Of this traffic over 60% was destined
for the steel mills and utilities of southeastern Michigan. The future of this

short haul movement from Toledo to the Detroit area is uncertain. Unit train
movements froff mine directly to the consumer and downbound traffic of western
coal from Lake Superior are satisfying a greater percentage of the electrical
fuel demands of this region.
Movement-of coal to Lake Superior from the port of Lake Erie remains a
major traffic movement. Nearly 50% of the domestic shipments from Sandusky are
destined for ports on Lake, Superior. The electric power facilities at Marquette
account for the majority of this traffic. While Sandusky supplies coal for Lake
Superior ports, over 60% of all coal shipped on the Great Lakes from this port
goes to Canada. Lorain, the only major coal handling port on Lake Erie,not to
export to Canada, shipped primarily to the electric power facilities of the
Detroit Edison Company. Regulations on the sulfur content in coal and competition

from rail traffic have been instrumental in the decline of Lorain as a major coal
facility.
The facility at South Chicago on Lake Michigan was the point of origin,
for approximately four million tons of coal shipped on the Great Lakes. Coal
from this port was destined primarily for the Consumers Power.units of western
Michigan and the facilities of the Wisconsin Electric Power Company. Coal traffic
from South Chicago has declined by about one-half over the last decade; largely
because of sulfur regulations.,
The new transshipment facility at Superior, Wisconsin, was designed to
benefit from the regulations on coal quality that have plagued many of the other
transshipment facilities. Handling low sulfur coal from western states, Superior
i.s the origin for low-sulfur coal-shipped to the electric power facilities of
Detroit Edison. Presently serving only Detroit Edison, extensive expansion to
other markets is anticipated. The Superior facility is designed for an eventual.
capacity of 20 million tons throughput.

Electric utilities provide the major demand for coal shipped on the
lakes. In 1975 48% of the coal.,-shipped,on the Great Lakes was destined for use

by utilities. Coke and gas plants consumed 28%, while retail dealers and others
consumed the remaining 24% [6041. These destinations were located almost
exclusively in either Michigan or Wisconsin. These states purchased 96% of all
domestic coal transported by lake for utilities, and Michigan alone was the
destination for 91% of the waterborne coal used by coke and gas plants.
Petroleum shipments on the lakes originated primarily from the ports of'
Indiana and Chicago on Lake Michigan's southern shore. These ports accounted
for-more than 70% of the petroleum products shipped on the Great Lakes.
The destination points for lakewise movements of these fuels are
scattered throughout the region with virtually every major port receiving and
storing liquid fuels. The widespread distribution of receiving terminals through-
out the region reflects the flexibility shipping offers over,pi pelines in smaller
scale delivery of this fuel.

(5) Planned or Scheduled.Facilities
Port expansion or new port,construction is often the direct-consequence
of the development of additional energy facilities. Such port development is
particularly applicable to the construction of coastal dependent coal-fired'
electric generating facilities, which historically have relied on waterborne fuel
delivery.
U.S. Great Lakes coal traffic originates from three major districts: Lake
Erie, South Chicago and Superior, Wisconsin. In 1975, the Lake Erie ports of
Toledo, Ashtabula, Conneaut, Lorain and Sandusky shipped 33.2 million tons of
coal, or 85% of the coal traffic on the lakes. Within the last,ten years coal
shipments from these ports have declined 28%. a decrease of 12.7 million tons
since 1965. Consequently, most of the ports in this region operate at.levels
well below their prev ious, capabilities. The only major Lake Erie coal harbor
presently contemplating extensive expansion is Conneaut. Conneaut, presently
storing four million tons and shipping approximately eight million tons, antici-
pates a substantial increase in coal traffic.
The proposed expansion will provide Isubstantially more storage space and
will include a conveyor belt system, travelling stacker, and bucket wheel
reclaimer. Much of the expansion is projected for Canadian use, particularly by
the Ontario Hydro utility facilities. Eighty percent of all coal shipments from

343

Conneaut ar6 presently destined for Canada. The expansion may double storage
capacity to 8 million and increase throughput to 13 million tons. Barring
delays in permit approval and construction, expansion completion is set for the
spring of 1978.. The ports of Sandusky, Toledo, Ashtabula and Lorain anticipate
no near term major expansions. Officials at these ports feel the facilities can
accommodate the expected increases in coal traffic.
The South Chicago harbor on Lake Michigan shipped eight million.tons of
coal in 1967. In 1975 this facility found market for about four million tons of
coal. There are no plans to expand. Much of the coal moving through this port
originates from the midwestern coal fields in Illinois. The high sulfur content
of this coal has accelerated the-decline in volume transshipped from this port.
A minor quantity of western coal'has moved through the Chicago port and-could
contribute to future- redevelopment of capacity capabilities.
The third major coal shipping region is located in Superior, Wisconsin.
This single facility completed in 1976 will have an eventual capacity to trans-
ship,20 million tons. Coal shipments have risen sharply in Lake Superior. In
1973, 130,592 tons of coal were shipped from Lake Superior ports. Completion of
the facility in-Superior, Wisconsin-in 1976 will add 2.2 million
tons to the'total coal.shipments from Lake Superior ports. The facility was
developed in response to-the demand from the Detroit Edison Company for low
sulfur coal. This utility contracted for 180 million tons of low sulfur western

coal from the Decker mine in Montana. This contract for western coal extends
over a 26-year period and was projected for use by Edisonis St. Clair and Belle
River power plants. However, construction plans for the Belle River plant have
b.een delayed due to financial difficulties,'and Detroit Edison is in the process
of analyzing alternatives for the consumption of coal originally designated for

Belle River.
A development similar:to the Superior facility is being@constructed at
Thunder Bay, Ontario, on Lake Superior. Low sulfur coal'originating from mines
in'Alberta, Saskatchewan and British Columbia will be delivered by Canadian
National and Canadian Pacific unit trains. Scheduled to begin operation at the
start of the 1977 shipping season, this facility is expected to initially ship
3 million tons of coal per year. These shipments are destined for Canadian
markets in Ontario and eastern Canada and may compete with future coal shipments
originating from the U.S. ports on southern Lake.Erie [147].

344

A major expansion in demand for coal receipts from Superior, Wisconsin,
may occur near Buffalo. The Niagara-Mohawk Power Corporation is planning two
850 MW coal-fired.plants near Dunkirk, New York, on Lake Erie for 1985 and
1987. Low sulfur western coal is anticipated for use as the fuel source.
Operation of the two Lake Erie power plants will require approximately six million

tons per year.
Niagara-Mohawk was faced with two major optioas for transshipment of their
western coal to the plants at Dunkirk. They could either have coal delivered to
Buffalo and then transport it by unit train or barge approximately 50 miles to
Dunkirk, or develop a separate transshipment facility at Dunkirk. Were coal
delivered directly to Buffalo high costs would be incurred both in the develop-
ment of a large coal facility at the port and in transportation rates by short
haul unit, train or barge to Dunkirk. Development of a new deepwater harbor at
Dunkirk also Appeared prohibitive in that the lake bottom in that area is
essentially bedrock.
The utility is present ly developing plans for an offshore unloading
facility at a site'in Lake Erie approximately eight miles west of Dunkirk Harbor.
This structure would consist of a number of concrete bresting and mooring
dolphins, one of which is designed with an open shaft to accept coal from the
self-unloading coal vessels. The coal will drop down the shaft to a conveyor
tunnel approximately 23 feet in diameter running beneath the lake bottom. The
tunnel would emerge onshore for reclamation.and distribution by conveyor to the
plant. 'The tunnel will also house a water pipeline to supply makeup water for
the plant. Total cost for the unloading facility and tunnel conveyor is
estimated at about $60 million.
Such a facility represents a unique approach to traditional coal trans-
shipment design. Projecting the development offuture facilities of this kind
at other Great Lakes sites is difficult as this facility may be the direct result
of the geological characteristics that hamper economical dredging activity at
Dunkirk. The Dunkirk plans represent a major addition in coal transshipment
facilities for power production in the Great Lakes thr ough 1985. Table 67
outlines the expected fuel origin, type, and method of movement for scheduled,
fossil-fuel power facilities greater than 300 MWe in the Great Lakes coastal
counties through 1985.

345

TABLE 67

FUEL TYPE, ORIGIN AND TRANSPORTATION FOR FOSSIL-FUEL
FACILITIES SCHEDULED THROUGH 1985

LIKELY
FUEL
GENERAL TRANSPORT
PLANT NAME UTILITY LOCATION FUEL TYPE FUEL ORIGIN METHOD

Edgewater Wisconsin Sheboygan, Coal Western Unit Train
Power & WI fields
Light

Prairie View Wisconsin Kenosha, Coal Western Unit Train
Power & WI fields
Light
Campbell 3 Consumers Holland, Coal Eastern Unit Train
Power MI fields
Karn 4 Consumers Bay City,, Oil Sarnia, Train-Sarnia
Power MI Canada and Pipeline -
Lakehead Superior,WI
pipeline
Belle River Detroit St.Clair,. Coal Western Lake Vessel
Edison MI, fields

Greenwood Detroit Port Huron, Oil Sarnia, Barge to
Edison Mi Ontario Pipeline
Dunkirk Niagara- Dunkirk, Coal Western Lake Vessel
Mohawk NY fields
Oswego #6 Niagara- Oswego, Oil South Ocean Tanker
Mohawk' NY America to Barge

The information in Table 67 was gathered from.each utility and is
presented as their current estimate for fuel supply.' Certain entries are, of
course, more definite than others. The Edgewater and Prairie View plants in
Wisconsin each anticipate utilization of western coal., Their geographic loca-
tions allow fairly direct access from eastbound unit trains. -The Edgewater site
could conceivably receive coal by lake carrier through Sheboygan, but the
officials at Wisconsin Power and'Light presently favor direct unit train'
transportation. The Consumers Power Company is investigating use of low sulfur
eastern coal delivered by unit trains for their Campbell #3 unit on Lake Michigan.
This utility anticipates that the low sulfur eastern coal will have better heat
value, be a more reliable supply, and have lower transportation costs than
western -coal.

346

Three of the eight new facilities listed in Table 67 are designed to
burn oil for power production. Both the Karn and Greenwood units are to receive
their -oil fuel supply from Sarnia, Ontario. Each utility assumes a different
approach to the transportation of this fuel. Detroit Edison's Greenwood
facility plans to transship fuel oil by barge from Sarnia across the St. Clair
River. Once across the river the oil would then be pumped into a pipelinethat
runs approximately 15.miles inland to the Greenwood plant.
The Karn unit near Bay City also plans to receive oil from Sarnia.
However, they intend.to receive fuel delivered by train. Additional oil from the
Lakehead pipeline will supplement the fuel deliveries from Sarnia. Karn units
.#3 and #4 combined will consume approximately 30,000 barrels per day. Seventy-
five percent of the fuel supply to these units will be delivered by-train while
the balance will be supplied by pipeline.
It is expected that fuel for the Oswego #6 unit,will be delivered by the
same barge system that presently serves the existing Oswego oil-fired units. @o
major expansions are planned for-fuel transshipment. Presently oil from South
America moves by tanker to refineries in the Caribbean. The refined product is
shipped northward into the St. Lawrence Seaway for delivery to storage facilities
in Montreal. Oil is transferred to barges in Montreal for delivery in Oswego.

C. Refineries

The total refinery capacity in the eight Great Lakes states is 3,513,380
barrels of crude per day .(calendar day figures are refiners' averages for the
number.of barrels per day a refinery yields on the average). Of this refining
capacity 1,045,185 bbl/day or 30% is located in the coastal zone. All eight
states have some refining capacity, with Minnesota,.Pennsylvania and Illinois
having no capacity,1ocated within their coastal zone With respect to the
,relative numbers of barrels refined within each state the breakdown is shown in
Table 68.

Current refinery construction in the Great Lakes states is presently
restricted to expansion of existing facilities. These expansions amount to only
95,440. bbl/day (includes coking operations) of which only 2,400 bbl (Sun Oil Co.,
Toledo, Ohio) are in the coastal zone area.

from Oil and Gas Journal, April, 1976.

347

TABLE 68
BARRELS OF CRUDE OIL REFINED IN EACH,GREAT LAKES STATE

Total Total
bbl/day Capacity bbl/day Capacity Percent In
(State) .(Coastal Zone)- Coastal Zone

Niew York' 111,385 111,385 1-00%
Pennsylvania 757,020 0
Indiana 561,160 436,000 87%
li-nois .1,176,800 01 0
M'f -_ h ian 147,200 65,000 44%
Minnesota 216,800 0 0
Wi 0 589,770 337,400 57%
Wisconsin 45,400 45,400

Great Lakes Total 3,513,380 1,045,185 30

U.S. Total 15,074,845 bbl/day

Gre.-_ "Lakes total
,,.of U.S. Total 23%
Grer@t Lakes Coastal
4o-e as % of U.S. 7%

t .0
Source: Oil and.Gas Journal, April, 1976

Texacols Lockport, Illinois, plant has announced a planned expansion of
input capacity of 25 x 103 bbl/day with an uncertain operational start date.

The Cirillo Brothers of Albany, New York have announced a new refinery of
20,000 bbl/day input capacity of uncertain operatlonal date and product output.
The largest new facility to be announced in the coastal zone is New England
Petroleum's Oswego, New York, refinery of an expected 200,000 bbl/day input
capacity. Again, no operational date or product output ahs,been announced for
this proposed plant.
High costs of-refinery construction combined with uncertainty about
long-range government energy policy has led to the smallest increase in U.S.
refinery capacity (1975 - 146,000 bbl/day) since 1965. Further, this increase
was approximately 240,000 bbl/day less than had been forecast. Nationwide, the

348

expansion of existing facilities accounted for most of the U.S. increase in
refinery capacity.
Each refinery is a speciall"j designed unit with the specifications and
requirements of the facility being very dependent upon the type of crude and the
products to be refined. Therefore, generalizations about refineries are often
inaccurate outside the context of site, product and process specificity. Allow-
ing for such, the following "rule-of-thumb" guidelines for refineries have been
suggested.
There are three main determinants of refinery siting: (1) proximity to
major product market area, (2) relative proximity to sources of crude, and
(3) availability and costs of various modes of transport. This last is a major
reason fo@ refineries' preference for .coastal siting.
Between 200 and 1,000 acres are needed for 100,000 bbl/day refinery
complexes, with the lower limit representing a simple fuels refinery with a
40-day storage',capacity and the upper.limit a complex fuels-petrochemical refinery
with a 120-day storage capacity. This large difference in land requirements
(with land generally being 5-10% of total refinery cost) represents the large.
variations in the, complexity of refineries as well as the' different storage
capacity requirements at specifid-refineries. Almost all refineries have
minimum storage facilities sufficient for a 30-day supply of crude oil plus
additional capacity for mixing and storage of refine d products I(i.e., heating oil
in summer or gasoline if delivery of crude is erratic). Refineries which are tanker-
fed (neces,sarily coastal dependent) requi re more storage area due to the non-
continuous nature of the tanker delivery system. This last factor tends to be
of smaller concern to Great Lakes refineries as they are predominantly pipeline

supplied.
A 200,000 bbl/day refinery capacity is considered an optimal size. Such
a size is needed to introduce the economies of scale neces sary to offset high
construction costs of new facilities so that they can be competitive with old
plants. These sizes are also necessary to keep operating costs to a minimum.
A few years ago, a rule-of-thumb cost for refineries ran approximately
$1500/bbl/day capacity. Now a more realistic figure would be $3,500 to $4,000/
bbl/day capacity, with some plants going as high as $6,500 to 7,000/bbl/day
capacity.

Communication, National Petroleum Refiners' Association.

349

For the past few years9 the national trend has been to build new

refineries outside the continental U.S., particularly in the Caribbean, to take
advantage of lower total taxes, less strict environmental controls . deepwater
ports and competitive transport costs. However, this trend is being reversed
(balanced expansion) somewhat by high tarkifs on imported refined products and
low domestic &rude prices, along with considerations for national defense policy.
The probable increase of national refining capacity coupled with refineries'
desire for close proximity to transport facilities and areas of demand may
indicate a renewed interest in the Great Lakes coastal zone for siting refinery

complexes.
The two major obstacles to new refinery development are high construction
costs and environmental considerations. Of the latter, by far the greatest
concern to refineries is, oxidant level requirements set by the Environmental
Protection Agency. According to the refining industry, the low levels.allowed
by EPA virtually preclude new refinery construction in already developed areas,
precisely where the refining industry wants to be. The major source of this
problem is.the emission of hydrocarbons (a 100,000 bbl/day refinery with 30-day
capacity may emit as much as 10,000 lbs/day, even with advanced 'containment
technologies), with most hydrocarbons released during storage and tank filling.'
Other pollutants associated with petroleum refining are particulates, sulfur
oxides, aldehydes, ammon ia, and hydrogen sulfide. Water use is being minimized
(H20/bbl capacity) by using water recirculating cooling systems. New refinery
construction is-depending more on air cooling, resulting in a lessened dependency
on large water resources. Further, better water treatment is being utilized,
which further reduces water consumption (by increasing usable life span of water)

and thus the coastal dependency of facilities.

New refineries are most dependent on environmental and economic consider-
ations, many of which are not easily controllable by the individual states. With
the problems of capital formation and air/environmental quality requirements, the
development of refineries in the Great Lakes Region would seem slim. A further
factor which dictates against Great L akes Region siting of refineries is the
relatively lower cost of refining mideastern and most domestic crude oil in the

Communication, National Petroleum Refiners' Association.

350

Gulf Coast states [3701. Refinery economics are 'Such that in most instances, it
is less expensive to pipe refined products to the Groat Lakes Region, than it is
to refine the crude locally. These three major factors would seem to dictate
against any large expansion of refinery capacity.
One factor which might influence further refinery development-in the
Great Lakes Region would be the piping'of Alaskan crude through the region.
proposed Trans-Provincial or Northern Tier pipelines could potentially bring
between 700,000 to' 1,000,000 bbl of oil daily'into Minnesota. Such a development
might necessitate the building of two'or three'new refineries, but would not
significantly influence the coastal zone.

4. PLANNED OR SCHEDULED FACILITIES FOR ELECTRICAL GENERATION

a. Types and Location by State and Region
Future electric power generation in the eight Great-Lakes states will be
very dependent upon coastal zone facilities. Of the eight Great Lakes states,
Illinois, Minnesota and Pen nsylVania currently have no confirmed plans through
1985 for new generating capacity within their coastal zones. A single 800 MW
coal-fired plant has been discussed for the Pennsylvania.coastal zone around 1990,
with the utility's land holdings at the projected site being sufficient for an
additional unit. The western portion of Erie County, Pennsylvania, iis largely
undeveloped, with a large percentage of'the land held by Penn Electric, United
States Steel, and the Boy Scouts. Hence, the potential for facility development
in Pennsylvania still exists.
Illinois also has a relatively small coastal zonei- but one of the
most highly developed in the Great Lakes states. The potential for future expan-
sibn is seen to be limited due to the difficulty of obtaining sufficient acreage
for energy facility development (5681. The pressures on the coastal zone area
for uses other than energy facility siting.are such that no major facilities are
currently being considered. Access to the coastal zone water resources and fuel
transshipment facilities for inland generating sites will most probably comprise
the major use of the Illinois coastal counties for electric generation purposes.
The utilities within the State of Illinois have currently planned eight coal-
fired facilities, five oil-fired and eight nucl:ear-powered generating units,
totaling 11,370 MWby 1984. This schedule reflects Illinois' continuing develop-
ment of a high nuclear generating capability.

351

The Minnesota utilities currently have no announced plans for generating
'facilities in their'coastal counties.. With respect to.1uture development the
Minnesota Energy Agency,suggests*that: "Water availability, population density
and location to relative load centers would all seem to@@point toward increasing
pressure on!,the coastal zone area especially if demand grows as rapidly as the
utilities project." Statewide, Minnesota currently has five coal-fired
generating facilities scheduled to come on line by 1984. 'No oil or nuclear

facilities have been announced for'the state. The curtailment of Canadian oil

will proba bly further the,development.of coal-fired facilities., One event which
may alter Minnesota@'s energy future is the transporting of Alaskan crude oil
through the state via the proposed Northern Tier pipeline or the Trans-Provincial
pipeline. Such a circumstance might alter the future fuel mix for electric power
generation or reduce the substitution of electricity for other energy sources,
thus reducing projected demand for electric power.
Indiana currently has one schedLled facility in its coastal tone, the
645 MW Bailly nuclear facility, the coastal zone of Indiana is fairly.industrial-
ized, with 22 miles ofthe 45 mile coastal zone industrially developed and 17
miles devoted to, public' recreation lands [436]. Future development in this area
may.be restricted by air or water quality regulations. As with Illinois, Indiana
may only be able to utilize the,waters of the coastal zone for inland energy.,
facility sites. The Indiana utilities have currently planned 10 coal-fired and
3 nuclear powered generating fac.ilities,,totaling 9,220 MW by 1984 (this includes
the one coastal zone.facility).
Wisconsin has seven coal-fired facilities scheduled, three of which will

be in the coastal counties. With 140 miles of their 619 mile coastal zone
currently agricultural or undeveloped, the potential for new generating,facilities
in the coastal zone is large [436]. The two Koshkonong nuclear 900 MWunits
scheduled.for 1983 and-1984 have been deferred until 198.6.. Similarly, the Tyrone
nuclear station has been deferred indefinitely. The-coastal zone resources of
Wisconsin, as in many states, will be in greater.demand in the future due to
limited availability of inlandwater in quantities.suffi.cient for a modern
generating station. The Pleasant Prairie plant is an,example, of a station that.
will site near existing transmission and fuel transportation systems but close.
enough to the coastal zone for economical utilization of lake water. For many

Communication from R. D. Visness, Minnesota Energy Agency.

352

future facility sitings the access to coastal zone water resources will be of
high importance. The availability of western coal combined with the deferment
of nuclear facilities will emphasiza the use of coal in the near future.
The States of Michigan, New York and Ohio have the most ambitious plans for
developing energy facilities in their coastal zone. This reflects their rela-
.tively longer coastal zones, the lack of adequate inland sites, proximity of the
coastal zone to load centers, and the generally higher energy demand in these

three'states.
All planned facilities in Michigan (with the exception of the Midland
plants) are scheduled for the coastal zone (as defined by the first tier of counties
and a use or impact of/on coastal zone resources). Of these facilities four are
coal-fired, two oil-fired and five nuclear-fired, totaling 10,550 MW by 1984.
Nuclear generating capacity comprises almost 50% of planned capacity,
with the oil and coal being respectively 16% and 33% of the scheduled generating
capacity. This scheduled fuel mixture represents an increased emphasis on
nuclear generating capability in Ohio and New York, similarto what has been
found in Illinois. Within Michigan a number of nuclear facilities have been
delayed or cancelled for such reasons as lack of capital, equipment delivery
delays, inflation, questions over fuel availability"and safety, etc. Nuclear
generating facilities have been hardest hit by delays and cancellations. The
problems currently faced by the Michigan utilities apply to all types of electric
generating plants as well as to utilities in the other states. The current
decline in electric energy demand coupled with high reserve margins and lack of
utility capital have been the main reasons for the delay in Michigan's scheduled
generating capacity additions. These problems notwithstanding, the coastal
counties of Michigan have the most ambitious energy facility development plan of
any Great Lakes state. The justification for siting in the Michigan coastal zone,
ease of fuel transportation, proximity to load centers, relative availability of
coastal land, sufficient quantities of water and the design of the power grid,
will continue to be the reasons for power plant siting there. Currently, the
utilities plan to continue construction of coal-fired plants for the mid-term,
hoping that nuclear generating capacity can be added soon to prevent future
electric power shortages.
The Ohio utilities are also planning a large nuclear power generation
development program. All plants scheduled for the Ohio coastal zone through 1985
are nuclear facilities. Currently, only one nuclear facility is being planned

353

outside of the coastal zone, with the remaining scheduled capacity for the state
consisting of eight coal-fired plants totaling 3,815 MW. The pressure on the
Ohio coastal zone for energy facility siting is expected to continue to grow.
The demand on the coastal zone will be for both siting and water resource access.
The Ohio utilities face many of the same problems as the other Great Lakes states'
utilities with respect to construction delays, capital shortages and siting
problems. The intensive development of nuclear power in the Ohio coastal zone

indicates a shift in the fuel mix of the state from almost total coal-fired base

load generation toward a more balanced nuclear-coal mix.
The New York state fuel mix for electric generation deviates from the
seven other Great Lakes states through its heavy reliance on oil- and gas-fired
generation. The scheduled changes in capacity indicate a lessening dependence
on oil and a relatively large increase in nuclear generating capacity. Statewide,
seven nuclear, four coal- and three oil-fired plants have been scheduled through
1984, totaling approximately 12,000 MW (3031. Of these facilities four hav e been
located in Great Lakes coastal counties: two nuclear facilities, one coal-fired
facility and one oil-fired facility. Of New York's 292-mile Great Lakes shore-
line, approximately 134 miles of this is agricultural or undeveloped [436]. Due
to the problems of siting and water availability within the state, the pressure
for energy facility siting in the coastal zone will increase. As indicated
earlier the power flows in New York are generally east'and south, with areas
such as Oswego becoming major exporters of electric power. The role of nuclear
'generating capacity can be clearly seen as expanding. The future role of coal is@
projected to increase slightly statewide, while the use of oil is.projected to

decline in relative terms.

On a regional basis more nuclear generating facilities have been
scheduled than either oil or coal facilities. However, the number of delays and
cancellations announced during 1974-1975 reduce significantly the amount of
nuclear capacity that will come on line during the next ten years. This gap in
generating capabilities will more than likely be made.up by fossil fuel-fired
plants (predominantly coal), giving the/utilities time to see how post-1973
growth patterns develop with respect to both demand and fuel type. During the
mid-1980's the utilities' on line capacity will increasingly reflect their effort
.to cope with foreseeable fuel, legal and environmental restraints.

354

TABLE, 69

CHANGES IN NUCLEAR UNIT SCHEDULES DURING 1972-1975
(All changes listed involved change in the year of commercial operation.)

During No. of units Plant-yr No. to No.
Year changed added indefinite cancelled
1972 54 72 3
1973 52 67
1974 104 201 16 9
1975 102 116 Gil 12
Data taken for the most part from ERDA tabulations of industry
information.
Nearly as many units were changed in 197 5 as in 1974, but the total
impact was lower in some respects.
It is noteworthy that 34 new unit orders were entered in 1974 while
9 were cancelled. In 1975, only 4 new orders were entered while
12 were cancelled.
The 1974 changes (104) affected 56% of all nuclear units on order
or under construction through 1974. The 1975 changes (102)
affected 59% of the units remaining on order or tinder construction
through 1975,

Power Engineering/April, 1976.

b. Estimated Capacity and Projected Demand
The ability of an electric company to meet a future electric power demand
level is dependent upon many factors, most of which are not controlled by the
utility. Availability of electric power in the future,.depends on present
planning and construction based upon future estimates of demand. This current
planning and construction for future needs is very sensitive to long-range fore-
casts, capital availability, assessments of fuel availability and a host of other
factors which since 1973 have become difficult problems for the utilities.
The first problem faced by the utilities is what will the future demand
for electricity be? Historically, demand has grown 7% annually, but during 1974
the growth rate was near zero. Current best estimates assume 5.5% growth rate
in demand, .tapering off somewhat after 1985 [344]. Some utilities, however, feel
that demand may once again return to historical rates. Whatever the future
demand may be there is an inherent difficulty in planning and constructing for
unknown future demand levels in the context of the present uncertain consumption
patterns. In addition to uncertain demand levels, current low load factors and
high reserve levels further confound the future energy demand picture. Over the
last few years total electricity demand has grown less than peak demand, resulting
in lower load factors [364]. A shift towards increased peak demand in the
utilities' load schedule has required a large increase in peak load generating

.355

capabilities and produced a large reserve capacity. This accentuation of the
peaks in the load schedule necessitates the construction of capacity to meet
small peak load periods (Figure 37).

Figure 37
WEEKLY LOAD CURVE

100

N
N.
90 PEAK

0 60 INTERMEDIATE

LU
.....................
50
....................
LL
..........
0
. .........
...........
...................

z
............
LU 40
.......................
...... . ........
.....................
......................
...........
......................
30 .........
............ ...........
...........
. ........ . ........
......................
.............. BASE
....................
.............. ........
X-M4X-M............. ... .......... .. .........
............. ........
Xe "N'

...........
......... .......
...................
................. .........
..........
10 ............
...................
.......... .... . .
X X ................ . . :-*-'-' . :
....................
. ...........
.. ...........
0
L ----TWEDNESDAY!l THURSDAY -F F
SUNDAY MONDAY T ESDAY RIDAY SATURDAY

An increase of 10% in the load factor (e.g., from 50% to 66%) would
result in a 10% reduction of total capacity, and about 40% less peaking capacity
[344; p.4401. To bring about increased load factors and reduced peaking capacity
requirements, peak load pricing has been suggested. Peak load pricing will
result in redistribution of costs to various end users, but its aggregate effects
on electrical energy demand and in fact its very workability are less certain
[3441.

356

The Federal.Power. Commission has suggested somereasons for the problems
in :utility planning:

lapid increases 'in energy prices, the downturn in economic
@i.activity, the s *luggish growth of electricity demand following
the Arab oil emb.argo, curtailments of natural gas service to
industrial customers and embargoes on new gas hookups, and the'
talk of moving toward oil import independence in part through
increased reliance upon nuclear and coal-fired electricity
generation have cr .eated-a good deal of uncertainty about the
growth.of future 'loadsi. Will the "pause" of 1974 be matched by
a 11spurt" at some laterpoint in time? Will recent historical
growth rates reemerge, but from a lower-thanm-anticipated base?
Or will growth rates continue to be lower than in the past?
Utilities are finding it necessary to adapt their methods o f
planning for system expansion to include the effects of consider-
ably more uncertainty in load growth than heretofore 1@341.

Besides uncertain load growth factors the utilities are facing difficult
problems in assessing the future availability of primary fuels for electric
power generation. The.utilities' low priority in@the FPC's natural gas allocation
program and the nation's desire to reduce the dependence on foreign oil suggest
the limited future use,of these two fuels for base load units [5341. However,
the'cost and difficulty of switching operating units using-oil and gas to coal-
-fired units indicate that there wi 11 be a continuing.demand for these fuels by
theAitility sector.@ Many utiliti Ies, having accepted the limited future of using

o
il and gas for base laad genera tion, are confronted by a number of constraints
l

which until resolved-'serve to increase the uncertainty of future power avail-
ability. Assuming that coal and uranium are the only fuels readily available for
large scale power generation, some of the restrictions faced by the utilities may
be:.a lack of a'firm Icommitment by the'government to the use of coal and/or.
uranium, delays in developing new coal mining capability, especially of western
low-sulfur coal,@doubts about th6 adequacy of coal transport facilities, contro-
versies over clean'air regulations, uncertainties surrounding the mining and
milling of uranium, unresolved issues of the nuclear fuel cycle, and questions
about the availability of technology for clean coal utilization [421]. Many of
these problems can only be remedied by1egislative or governmental administrative
action, which again se rves to compound the problems surrounding future power
availability. The question of future fuel mix for power generation is dependent
on many factors of which neither the utilities nor government have complete

control.

357

A last major factor in determining the availability of future electric
supplies is the financing of construction. The utilities, already one of the
most capital-intensive industries in the U.S., are facing increased costs.from.
both owning and operating their generating units, while at the same time suffer-
ing from a reduced earning power. Inflation, tight money and eroding investor
confidence have contributed to a general rise in the cost of capital financing
[5341. Environmental standards and-,construction cost escalation have also
boosted the cost of investing.in'new capacity, The Federal Power Commission has
suggested,some reasons for the utilities' reduced.earnings:

The delay by some utility managers in seeking.adequate rate relief,
compounded by the lag in some regulatory commission responses to
such requests, lower than expected sales, * and sharply rising
costs of fuel and other inputs have been the principal sources of
earnings deficiencies. They have seriously impaired,the industry's
,ability to carry out construction programs and may have put pressure
on some utilities to reduce these programs to levels dictated by
their current ability to raise capital, rather than by their judge-
ment concerning long-term growth expectations [5341.

All the above factors are shown in an attempt to understand the magnitude
and complexity of the problem of providing sufficient future supplies of electric
power. Other issues such as system reliability and delays in expanding capacity
also bear upon the problem of assessing the adequacy of future electric power
supplies. The question of the adequacy of presently planned generating capacity
with respect to some future demand level for electric power is one surrounded by
many problems. Given the number of delays and cancellations in new I generating
capacity over the past two or three years, there is a possibility of a serious
inadequacy of electric power if growth rates return to their historical levels
[5641. The combined planned-and scheduled generating capacity of the eight
Great Lakes. 5tates is 74,067 MW through 1984. If load factors and reserve margins
were held at 1973 levels this capacity might be expected to accommodate an annual
growth rate of 6 percent.

c. Implications of Emerging Tec ologies
Over the next 15-20 years no major changes in the technology of large-
scale power production are expected to be implemented on a commercial basis. This

Temporary decreases in sales serve to reduce current revenues without
necessarily reducing current capital requirements.

358

is to suggest that current technologies will continue largely unchanged for the
I
next twenty years. Efficiencies of the generating process will continue to
improve as will those of the transmission networks. The nuclear technologies
are not expected to change as to type or process; but rather an improvement in
the engineering and fuel cycle aspects of nuclear technology might be expected.
An increasing reliance on emerging coal technologies may alter the existing
patterns of coal use. These might include-fluidized bed combustors, gasification
or liquefaction, low Btu gasification for use in combined cycle systems, and the
development of technologies cleaning up coal's adverse impacts. In short, major
technological changes in electric power generation systems are not expected to
play a large role in the next 15 to 20 years.
The.pressure on the Great Lakes coastal zone from energy facilities will
continue to increase in the future. The increase in demand for energy, the
restricted thermal capacity of many inland water supplies, the proximity to load
centers, and access to transport routes all suggest that demand for the coastal
zone water resource (either direct siting on the coastal zone or simply access to
the resource) will increase in the future. Tables 70 and 71 compile the
'announced generating facilities in the Great Lakes Region through 1984.

359

TABLE 70

PLANNED OR SCHEDULED ADDITIONS IN GENERATING
CAPACITY IN THE COASTAL ZONE, 1976'

(Plants over 300 We)

State and Date Source of
Plant Name Fuel Type Mwe County in Service Information

Illinois

Notte --- --- --- --- 303

Indiana

Bailly Nuclear 685 Porter Indefinite 303

Michigan
Greenwood #1 Oil 815 St. Clair Indefinite 303
Karn #3 Oil 605 Bay May, 1977 303
Belle River 01 Coal 697 St. Clair Indefinite 303
Belle River #2 Coal 697 St. Clair Indefinite 303
Campbell 03 Coal 770 Ottawa May, 1980 303
Enrico Fermi 02 Nuclear 1,215 Monroe Indefinite 303
Greenwood #2 Nuclear 1,341 St. Clair Indefinite 303
Greenwood #3 Nuclear 1,341 St. Clair Indefinite 303
D.C. Cook #2 Nuclear 1,100 Berrien Indefinite 303

Minnesota

None --- --- --- 303

New York
Oswego #6 Oil 850 Oswego Hay, 1979 450
Lake Erie #1 Coal 850 Sheridan or Pomfret Nov., 1985 450
Lake Erie #2 Coal 850 Sheridan or Pomfret Nov., 1987 450
Nine Mile Pt. #2 Nuclear 1,080' Oswego Nov., 1982 450
Sterling Nuclear 1,150 Sterling May, 1984 450

Ohio
Davis Besse #1 Nuclear 906 Ottawa April, 1977 325
Davis Besse f2 Nuclear 906 Ottawa April, 1983 325
Davis Besse 03 Nuclear 906 Ottawa April, 1985 325
Erie #1 Nuclear 1,200 Erie April, 1984 324
Erie #2 Nuclear 19200 Erie April, 1986 324
Perry #1 Nuclear 1,205 Lake Dec., 1981 325
Perry #2 Nuclear 1,205 Lake June, 1983 325

Pennsylvania

None --- --- ---

Wisconsin
Pleasant Prairie #1 Coal 617 Kenosha April, 1980 303
Pleasant Prairie #2 coal 617 Kenosha April, 1982 303
Lakeside Coal 310 Milwaukee April, 1982 303

TABLE 71
PLANNED AND SCHEDULED ADDITIONS IN GENERATING CAPACITY IN THE GREAT LAKES REGION

1976 - 1984

(Plants Over 300 MW)
NOTE: No. of facilities indicated in brackets,

ILLINOIS INDIANA 2 MICHIGAN 3 MINNESOTA 4 NEW YORK 5 OHIO 6 PENNSYLVANIA 7 WISCONSIN 8

state Total Coal 4,04OMW [81 5,31511W 110 2,154 131 3, 46Q4w 51 2,703MW 141 3, 8153W C 8 1 3,60OMW 131 3, 3 3 714W 71

Percent o f Total 27% 65% 26% 100% 227 38% 28% IOU

State Total Oil 2,50OMW (5j 1,443MW f2l None 2,OOOMW [3) None 1,191MW f2l None

Percent of Total 16% 17% 9%

State Total Nuclear 8,536MW [81 2,905MW (3) 4,622MW [51 None 7,35OMW 17 is 6,262MW 161 8.01OOMW [51 None.

Percent of Total 57% 35% 56% 61% % 62%

Constal County Total Oil None None 2,154MW [31 None 850MW [I] None None 1,560 MW (31 0

Percent of Coal 100% 46% 47Z

Percent of Oil None None 1,443MW [21 None 850MW [11 None None None

100% 42%

Coastal County Total None 645MW [11 3,35111W [31 None 2,25OMW [21 4,222MW 141 None None
Nuclear

Percent of Nuclear 22% 73% 31% 67%

I Reference No. 199 and 303 (a) Announced between 1985-1990 (8) nuclear plants
2 303 totaling 10,30OMW plus 3,OOOMW of pumped storage.
3 303 and 395
4 303
5 303 and 450 NOTE: Data developed from FEA information.
6
7 236 and 303
8 199 and 303

361

Chapter V

REGIONAL SCENARIOS OF ENERGY DEVELOPMENT

A. INTRODUCTION TO SCENARIO APPROACH

The rates of growth in demand for electrical power and the fuel mix used
to generate that power are the key variables in attempting to evaluate the
electric energy future of the Great Lakes coastal zone. To facilitate the assess-
ment of the future pressures put on the Great Lakes coastal zoneby electricity
generating facilities, four alternative fuel mix scenarios have been postulated.
The basic approach is to make certain assumptions for each fuel mix future and
then examine the possible impacts if they were to hold true. The scenarios will
then be evaluate'd in the context of three electrical demand growth rates to
provide an indication of the resources required for future energy facility

development.
This study shall define a scenario as a set of assumptions relating to a
particular fuel mix and its ab ility to generate electric power in required
quantities. A scenario should not be confused with a forecast. Each scenario
is developed on assumptions which provide a basis foranalysis of the possible
future. It is not based on conclusions or predictions as to what the future will
be. Furthermore, scenarios do not assess the feasibility of the political,
economic, and social events which must take place for any particular scenario to

,occur.
The number of potential fuel mixes for future electric power generation
is essentially unlimited. The scenarios have been selected to be representative
of the major potential fuel, mix development routes. This method allows for a
comparison of their associated impacts and suggests the range of future fuel
mixes that can occur. The values assigned to each scenario represent a reason-
able level of supply and utilization.that might be associated with the different
technologies of the scenarios.

362

The attempt has been made to evaluate those scenarios which, under vary-
ing situations and circumstances, have a potential of occurring within the 20-
year time span being considered. A comparison of multiple alternatives serves to
illustrate many of the variables influencing the Great Lakes Region's energy

future.
A further objective of the scenario ai- roach is to identify and evaluate
pp
possible problems and impacts of future developments, thereby aiding policy
.decisions for power facility siting. It should be noted that no one set of.
policy options is associated with a particular scenario. Although the relation-
ship between energy production and the economy has not been thoroughly investi-
gated in the context of this study, it is assumed to be uniform throughout the
four scenarios. The basic energy demand for end use is constant for each

scenario.
The four scenarios are based on variations in the fuel mix used for
electrical energy production. As differences in the relative capital costs and
environmental considerations among types of generating facilitie's have been used
elsewhere in this study, the fuel mix for power generation becomes the critical
issue. (Another important issue is that of development of controlled technology
for the environmentally sound use of these fuels.) The availability, price, and
environmental and social impact of primary fuels for electric energy generation
are major questions which point to the important role fuels will play in the
future. The future fuel mix is_dependent upon factors such as: federal and state
regulations, commercialization of new technologies, availability of foreign fuel
sources, and other facts which will be discussed as they relate to fuels for
electricity production.

363

B. DESCRIPTION AND DETERMINANTS OF SCENARIOS

1. SCENARIO I RECENT TRENDS,

The nature of the utility industry is such that plans for the next ten
years have been fairly well established. Such planning is directed by the lead
times necessary for developing and constructing new generating facilities.
Development time for nuclear facilities is often 9-12 years and 5-7 years for
large fossil fuel plants, from planning through operation. Given the planning
requirements of utilities it would appear that the capacity mix.used for power
generation is "locked in" until 1983 or so. Thus, the recent trends scenario
includes the 1976-1983 time period and the facilities scheduled to come on line

as its base.

The assumptions within this scenario suggest that present fuel mix trends
will stay relatively unchanged over the,next 20 years, except that future
capacity will continue to grow some 35%. Future fuel requirements might be
predicted by extrapolating the current consumption patterns at a given electrical
demand growth rate.
As mentioned previously, these scenarios have been developed.to show
what the relative pressures and resource demands on the Great Lakes coastal zone
might be in the future. Essentially, recent trends is a continuation of presently
utilized fuel mix site selection process and power generating technologies. The
recent trends scenario assumes no major change in regulatory policy or in the
social instituttions which may affect the use or supply of electric power.. This
base case scenario is one with whi ch the other scenarios will be compared and
shall be used as the departure point for developing the o.ther cases.
Recent trends is the only scenario which deals explicitly with oil- and
gas-fired generation. As the percentage of power generated from oil and gas is
expected to hold fairly constant until the early 1980!s and then decrease, the
role of these fuels in power generation will only be discussed in the context of

the recent trends scenario.

Three major variations appear in currently used fuel mixes. The States
of Ohio, Michigan, and Pennsylvania use the highest percentage of coal for power
generation. Wisconsin, Minnesota, Indiana, and Illinois use somewhat less.
New York State uses the least amount of coal of any Great Lakes Region state
[192/4211. A weighted average was used to determine the present regional fuel
mix (of which a.breakdown appears in Table 75). The. current planned.and scheduled
facilities were then worked into the regional generating fuel mix. The result is

364

TABLE 72

SCENARIOS: MAJOR ASSUMPTIONS

FOR BASE LOAD GENERATION

FOR THE REGIONAL SCENARIOS

RECENT TRENDS HIGH COAL HIGH NUCLEAR NEW
TECHNOLOGIES

ECONOMIC

Fuel Costs Oil and natural Less expensive High fuel costs Increasing for
gas increasing fuel costs due to incomplete conventional
faster than coal. than,recent fuel cycle and fuels.
Overall increase trends increasing.
through 20-year scenario, but scarcity, plus
period increasing delay in breeder
f due to environ- development
mental consi-
derations

Capital Tight for next
Availability 5 years then
expanding, Federal Assistance
closely related
to state of
economy

G.N.P. growth overall between
3 and 4%

DEMOGRAPHIC
Population OBERS "E"
assumptions

RESOURCES
Coal Local resources
stated in study,
national
resources;
1975 BOM est.

Labor Available

Water Available, but
at higher costs
due to env.
considerations

Oil & Natural gas Available, but
decreasing after
mid-1980's.
Foreign supplies
also,available

365,

SCENARIOS: MAJOR ASSUMPTIONS (Continued)

NEW
RECENT TRENDS HIGH COAL HIGH NUCLEAR TECHNOLOGIES

ENVIRONMENTAL

Air/Water Existing
standards/ meet
new schedules

Land Stricter stip- Increased siting Little change
mine laws control from R.T.

TECHNOLOGY

Electric Minor increases Major increases
.Production in efficiency in the overall
efficiency of
energy production
process

Plant factor minor increases
I

Environmental Improvement in Acceleration of Same as R.T.
pollution control R.T. development
technology

Fuel Research Continue present Increase in
trends research for new
technologies

INSTITUTIONAL
Anti-trust/ No major change
tax structure

Nuclear Power No significant More anti- Polic ies which No major change
change nuclear policy promote nuclear
development

Price regulation Gradual de-
regulation.of
all fuels

State/local No limitations
Policy to growth

366

a projected.1995 fuel mix comprised of'50% coal-fired generation, 30-35% nuclear,
.and 15% oil, gas, and hydroelectric.

2. SCENARIO II HIGil COAL ELECTRIC
With the recent trends scenario extending until 1982-1983, a'high coal
fuel mix would not be evident before the mid-80's. A possible exception to this
supposes that a change in the fuel mix of currently planned facilities, combined
with an increase in demand for electrical power, would favor the growth of fossil
fuel plants to meet this demand, due to their considerably shorter construction
period. The variations among current fuel mixes in the eight Great Lakes states,
shown on Table 75, indicate that many states currently have what might
be termed "high coal" fired generation.' For these states the variations between
their present fuel mix and the high coal scenario may not be substantial.
There are certain conditions ne .cessary for the development of a high coal
scenario. A primary condition would be the further development of reliable
technologies for the clean utilization of coal, including desulfurization and
removal of particulates and.NOx. At the same time, actions such as a reduction
in air quality standards 6n a case-by-case basis remaining consistent with
health and'environmental standards), the development of more mining and transpor-
tation activity and a political commitment sufficient to sustain the increased
utilization of coal for power generation would be needed for coal to play a
larger role in generation of electric power. Furthermore, strenuous use o f coal
would be facilitated by a higher relative cost for nuclear power or the imposi-
tions of restrictions on nuclear facilities development.
It is assumed here that the coal fuel mix will be approximately 15-20%
higher between 1990 and 1995 than in the recent trends scenario. The fuel mix
for the high coal scenario will break down as follows: 70% coal-fired, 15%
nuclear and 15% oil, gas, and hydroelectric.
An additional factor influencing the rate of coal use is the rate of
conversion of oil-fired generating plants to the burning of coal. This would
apply to both currently operating and planned facilities. The federal, govern-
ment will be the primary factor in determining the rate at which conversion will
take place, assuming that some policy position will be forthcoming on oil to coal
conversion of generating facilities. Currently, two plants in New York, the

367

Albany and Danskammer, have been ordered to convert to coal by the Federal Energy
Administration. (The order for the Albany Station-is not presently effective.)

3. SCENARIO III - HIGH NUCLEAR ELECTRIC

The high nuclear scenario suggests a rapid development of nuclear
generating capabilities exceeding that associated with recent trends. Nuclear
generation of electrical power remains one of the few fuel mix options suffi-,
ciently developed to assume a major role as a regional power supplier. Nuclear
power currently provides 10-12% of the Great Lakes Region's electrical energy
demand. As is projected in the recent trends scenario, by 1995 it will comprise
approximately 30-35% of the,generating capacity. The nuclear scenario then
further assumes that the Great Lakes Region's nuclear generating capacity will
be approximately 45% of the 1995 total generating capacity.
Nuclear development on such a scale would require major actions by both
the utilities and the fe deral government. The acceleration of the siting process
in conjunction with the alleviation of capital cost and formation problems of
nuclear facilities would be necessary in order to achieve a high nuclear scenario.
Furthermore, problems in the entire nuclear fuellcycle, from scarcity of fuels
and transportation security to radioactive waste, require serious consideration
and improvement. In short, the questions being raised regarding the expansion
of the nuclear power industry, combined with the long lead time for planning and
construction, indicate that a firm commitment to continue building will be

needed in the near future.

The high nuclear sc enario will reflect the continued decrease in the use
of oil and natural gas as primary fuels for base load power generation. Coal-
fired units will make up the remaining required generating capacity (45%), with
few large coal units-scheduled past 1985.

4.. SCENARIO IV - APPLIED EMERGING TECHNOLOGIES

The fourth scenario assumes a more rapid development of new technologies
for power generation than is presently anticipated. During the 20-year period
under consideration, the rate of new technology implementation is dependent on

Personal communication, Brookhaven National Laboratory.

368

the price of conventional fuels (including nuclear), the emphasis on commerciali-
zation of new technologies, and the size of electricity demand. Problems with
the use of the two primary fuels for future power generation might limit the
rate at which facilities fired by coal or nuclear fuel come on line. Such a slow-
down would provide additional impetus for the development and commercialization
of new power producing technologies.
The environmental and social problems of coal use have been investigated,
but there remain many unknown factors associated with coal utilization. The
questions of siting, nuclear wastes and the availability of fuel.are crucial to
the further development of nuclear facilities. Thus, the degree to which the
two primary fuels may be utilized in the future is an unanswered issue.
One new technology would be,the use of a low Btu coal-gasification
process for production of fuel in a combined cycle generating unit, resulting in
higher heat rate efficiencies and prevention of the more deleterious effects of
coal utilization. Such a project is currently planned by Commonwealth Edison
on a 100-200-MWe scale, with future development in some degreeidependent on the
facilities' operating record.
A fuel mixture composed of garbage-coal or biomass.(i.e., crops grown
specifically for combustion on energy plantations or simply agricultural,wastes)
could be utilized in conventional generating facilities, thereby reducing
resource pressure and the negative impacts of conventional fuel,use.
Although no firm commitment has been made by private industry or govern-
ment, high Btu gasification or liquefaction could potentially make an impact on
electrical generation systems by 1995 (by decreasing the demand,due to end use
substitution). The use of fluidized bed systems for combusion of coal would
reduce the negative effects of coal utilization as well as increase generation
efficiencies. (This changes only the process and not the primary;fuel, but as
a new technology it is included in the fourth scenario.)
Further new technologies might include: wind-actuated;electric power
generation; small-scale "total energy" systems for commercial or,industrial use,
which would greatly increase overall efficiency; bioconversion processes for
natural gas production and use in electrical generating facilities; solar-assisted
heating units which would decrease electrical demand thereby possibly,altering
the fuel mix; fuel cells for thermo-electric generation; and generally, combina-
tions of technologies which produce electric power and reduce the pressure on
the primary fuels.

369

The future of any of these technologies is uncertain. Given that these
and other technologies have potential for development and implementation in the
next 20 years, their possible impact should be noted.

Under optimum conditions the generation attributable to such technologies
would be 15 to 30% of the region's total by 1995. The remaining generating
capability would come from standard sources with conventional coal boilers
constituting approximately 40-50% and nuclear accounting for 20-35%.

C. INTRODUCTION TO DEMAND PROJECTIONS

While the fuel mix for electric power generation is fairly well set for
the next several years, the demand for power is not. Of the two critical
variables for future electric power production, the demand variable is the most
difficult to estimate over the time horizons of this study. The demand rate for
electric power, then, may be the only major surprise in the electric power
equation for the Great Lakes Region.
Historically, electricity demand has been the major factor,in determining
the rate of electrical power supply. With the advent of higher prices and
shortages of primary fuels for generation, demand for power is no,longer the only
variable to consider. Factors such as fuel shortages, rapid increase in prices,
fluctuating demand levels, and governmental regulation have increased the
difficulty and complexity of projecting future demands for electric power [549],.
But the long lead time necessary for power plant planning is the very reason,why

forecasts must be made.

Electrical demand forecasts have been studied in order to give an idea,

of the possible future pressures on the Great Lakes coastal'zone due to the need
for siting increasing numbers of power generating facilities. A combination of
different growth rates with fuel mixes may give an indication of the resource
requirements necessary for various electrical power futures. 'These requirements
may then be used to develop policies for future power plant-planning..@
The electrical demand growth rate is that figure which represents 'the
percentage increase over the previous time period (defined as one year) in
electrical power consumed, as determined by the additional number of kilowatt
hours consumed. Before 1973 this figure had grown at an average rate of
approximately 7% per year, or doubling every 10 years. Since.1973 the demand for
electrical energy has fluctuated greatly. It is currently 5.4% per year, but

370

the future level of this number is one of great contention [4211.
The variations among electrical energy:growth forecasts are tremendous,
largely due to the absence of a stanaard methodology and a single set of reliable

facts..

Given'the speculative nature of forecasting and its reliance on past
trends, 100% accuracy should never be expected. Growth forecasts are generally
derived from a model describing the process.that is under-study. These models
vary greatly with respect.to. scope, specificity, assumptions, emphasis, etc.
Development of a single, comprehensive model is not recommended [45]. The
degree of sophisitication and variation among forecasting models is a significant
factor in assessing the usefulness or.accuracy of growth models. Regardless of
their,sophistication, econometric models always depend on statistical observa-
tion and interpretation,of the past-[549] and hence are,only valid as long as
structural changes of relationships or independent variables do not occur
during the models' time frame [5491.
To suggest that prediction is the purpose for which models have been
developed would be misleading. Rather their purpose is to identify, organize,
and clarify the parameters and variables influencing electrical power demand,
hopefully giving improved information as to how the future may develop.
When analyzing electric energy forecasts there are a number of major
points which should be kept in mind, including: the time span being studied, the,
need to understand key assumptions and how they are incorporated into the fore-
cast, for whom and by whom the studies are prepared, the comprehensiveness of the
model, and the degree of detail it covers. In addition, the capabilities of the
forecasting model (particularly in adapting to policy and technology changes) and
its economic aspects (i.e., inter-fuel and regional competition, determinants of
supply and demand).[45] are important,to understand.
Actual projection 'analysis is based on certain key factors which are
representative of the individual variables that have been selected as effectors
of future demand for energy. The factors to be considered and their weighted
importance in the analysis are very important, as the potential for altering the
analysis and outcome is greatly influenced by the factors selected. As in the

Dr. Miller B. Spangler, An Appraisal of Future Energy Developments Affecting
the National and Regional Economic Outlook for Nuclear-Generated Electricity
During the Next Forty Years. March 1976.

371

selection of the methodology and assumptions to be employed for an analysis, the
key factors are selected on the basis of their judged relative importance by the
group doing the analysis.

The factors used in assessing future demand for electrical energy are
different for long- and short-term projection analysis. These factors also vary
among-projections which analyze the same time period. "The short-run projections
(2-3 years) must recognize the experienced factors such as the current recession
period, level of unemployment, and the leading economic indicators as the key
variables" [394]. "Long-run projections, on the other hand, hinge on factors
such as trends in population growth, household formations, changes in stock of
appliances, long-term business and economic outlook, availability of fuel
substitutes and their prices, environmental regulations, and technological change"
[3941. Somewhat differently, Oakridge National Laboratory considers population
growth, per capita personal income, price of electricity, price of competing
energy sources and price of electric appliances as the key factors in assessing
future electricity demand. The key factors used in a projections analysis are
as important in shaping the final output of energy demand modes as ate the
assumptions and methodologies employed.

D. REVIEW OF PAST PROJECTIONS

1. OVERVIEWS OF AVAILABLE PROJECTIONS'

The projected growth rates analyzed for this study vary'-greatly with
respect to region, fuel mix, approach and results. Projections relevant to the
demand for future electrical power were gathered to assess the variations
described above and how they might relate@to the Great Lakes coastal zone. Given
that no projection has been done specifically for the Great Lakes coastal zone,
the growth rate for electrical power in this,region can only be inferred.
Table 73 lists the projections reviewed, along with a number of major factors
which should be considered during a review of the projections.
The degree of diversity between the projected growth rates can be
explained by the various assumptions., methodologies and key factors used in the
respective studies. As might be expected-there is some degree of correlation
between the party preparing the projections and their implications for future
growth rates. Those groups having a direct relationship to electrical energy
production (i.e., utilities, component producers, or independent firms hired by
utilities) tend to develop higher rates of projected electrical energy demand

372

TABLE 73
OVERVIE14 OF ELECTRIC POWER PROJECTIONSi/

FORECASTED
AVERAGE COMPOUND
RATE OF ANNUAL
FORECASTER DONE FOR REGION PERIOD DEMAND GROWTH % COMMENTS

Duane Chapman, E.C.A.R. 1974-1980 2.6% Agricultural economist,
Cornell University

New York Power Utility planning late 4.0% declining
p\ 1970's-1990
Pool pur use New York to 3.5% by 1990

Stanford Research Wisconsin Wisconsin 1975-2000 4.5%
Institute Utilities Assoc.

Jim Griffin U.S. 1974-1981 4.8% Economist, University
of Pennsylvania

Michigan Public Detroit Edison 1979-1982 4-5.6% Re-forecast of companyts
Service Comm. Service Area forecasts, same
Consumer Power 4.6-5% methodology, different
Service Area assumptions

Detroit Edison Planning use Detroit Edison 1974-1985 5.6%
Service Area

Consumers Power Planning use Consumers Power 1974-1985 5.0%
Service Area

Dept. of Interior U.S. 1975-2000 5.5% Revised Edition
(Bureau of Mines) -

Edison Electric U.S. 1975-1980 6.0%
Institute

Utilities Ohio Power Siting Ohio 1974-1985 6.13%
within states Commission

Cincinnati Gas 6, Ohio Power Cincinnati G.& E. 1976-1986 6.7% Service area of 3000 sq. mi.
Electric Co. Siting Comm. Co. Service Area and 1.7 million people

R.T. Cornell U.S. 1977-1990 8.0% Utility Securities Analyst
for Institutional Investors,
E.F. Hutton Co.

Westinghouse U.S. 1975-1980 9.1%

Adapted from Forecasting Electric Enersty Demand in Michigan, by Waino H. Pihl and Iawrence M. Glazer, February, 1976.

growth than groups not so involved. This is not'to suggest that either group's
projections are deliberately biased. Differences are due to the different natures
of the groups, the emphasis placed on different variables, and human judgement.
The differences in the projections, between what might be termed vested interest
groups and independents, should further emphasize the need for projections from
many sources in assessing the needs for future power requirements.
The majority of the states within the Great Lakes Region have limited
capability for making independent electrical energy demandforecasts. The Public
Service Commissions (in some states Public Utility Commissions) within the eight

373

states rely heavily upon the utilities for their future demand forecasts. Due
to limited staff, budget, resources, etc., these'commissions' forecasting
capabilities are often limited to analyzing the utilities' projections. * More
often the commissions' role has been to act on a request for a construction permit,
deciding whether or not a new plant should be approved.
Many of the state energy agencies' electrical demand forecasting
capabilities are also very limited,,such that in many states only the utilities
have the capability of making long-range energy fore-casts. Minnesota, as an
example of a state having forecasting capabilities, has two forecasting groups:
one concerned with reviewing the utilities'. forecasts and a second producing
independent energy forecasts working with the Minnesota Energy model. Wisconsin,
in conjunction with the University of Wisconsin, utilizes the Wisconsin Energy
model (WISE) in assessing the fut ure state electrical demands. Overall the eight
Great Lakes states have limited forecasting capabilities. Hence there tends to
be a reliance solely on utility forecasts to assess the future needs for
electrical energy.
The Ohio Power Siting Commission and the New York State Board on Electric
Generation Siting and the Environment are the only state agencies within the
Great Lakes Basin that deal specifically with the issue of the siting of electri-
cal generating facilities. The Ohio Power Siting Commission has the capability
of making electrical demand forecasts independently of the utilities. This fore-
casting ability allows for verification of and comparison with the projections
prepared by the utilities. The commission also reviews the utilities' projections
"for compilation of the state's ten-year forecast for electric power [5141. The

format and content'of the forecasts are specified by the commission with a
'primary goal of the process being the need for the utilities to justify the
rationale thatunderlies their decisions to strive for a given resource require-
ment [514]. Towards this end the commission has'stipulated that all assumptions
and special information related to the forecasts@be listed and explained. The

Commission reports:

While most of theutilities complied with the requirement
(9-01(D)(3)) to list the assumptions used in the preparation of

Personal communication, Office of Energy Emergency Assistance, Wisconsin.

374

the forecasts, some reporting utilities either failed to justify
the inclusion of these assumptions or described the assumptions in
such'general terms as t'o be meaningless. Further, the impact of
the assumptions on their ba!Tic forecast was not adequately addressed
[5141.

Other issues which the commission felt to be inadequately addressed in
the utilities' forecasts included the impact of alternate rate structures on
demand, the effect of changes in the relativeprice of electricity, and the
optimal use of generation capacity. The role of the Ohio Power Siting Commission,
.as both reviewer of utility forecasts and forecaster, is to "review and comment
and certify the need for new facilities" in Ohio [514).

2. ANALYSIS OF SELECTED PROJECTIONS

A detailed analysis of energy projection models has been performed by
Argonne National Laboratory. This study gives useful insight into the workings
and, problems of energy modeling. The following comments were developed to better
understand differences.between projections, what they were designed to do, how
the@ developed, as well as shortcomings of the energy modeling situation.
Argonne's purpose was to evaluate several existing energy models to
determine their usefulness for ERDA@s Regional Studies program and identify areas

where future work should be undertaken due to certain weaknesses found in the

models. Three basic criteria were used in evaluating the models: (1) model
capability, (2) economic aspects, and (3) model comprehensiveness.
Projection models can be divided into "local impact," used for substate
or state regions, which are particularly useful for end-use details, and "National
synthesis," which analyzes energy availability and/or consumption on a larger
scale [45]. These two basic groups differ markedly irr their abilities and out-
puts, such that in many instances combining the two provides a more comprehen7-
sive result. For instance, if a regional policy'affects the national energy
picture (such as high energy facility development in the Great Lakes coastal
zone), this output could then be used as input for the larger national model.
Conversely, a national model could provide a regional energy supply and demand
analysis consistent with national policy as input for a local model [45]. The
point being that rarely will a single model be sufficient to cover all relevant
relationships, suggesting that more than one projection should be utilized in a

decision-making process.

375

The Battelle Col.umbus-EPA Energy Quality model, the Proejct Independence
Evaluation System, and the Wisconsin Energy model are representative of sophisti-
cated energy projection models that vary in methodology, scale, and type of out-
put. "The Battelle-EPA Energy Quality model is a large linear' program that
determines a minimum national cost of the distribution of coal, natural gas,
residual oil, distilate oil, and nuclear power in the contiguous United States
under specified conditions of supply, price and demand.' The model's,output
describes the fuel policy and use schedule for each region (PAD or AQCR) and a
schedule of fuel shipped from a supply to a use'region [45]. Due to its spatial
detail and regionalized energy consumption and costs (including transport) it is
considered of value when undertaking regional energy studies [451.
"The Project Independence model QIES) of the nationts energy system is
probably the most comprehensive and all-inclusive energy model yet produced."
.This national model has the capability of analyzing regional energy situations on
an interregional basis with.the end product being an instrument against which
policy and technology development fornational and regional energy strategies may
be measured and evaluated. The model provides for total energy demands to be
linked to economic growth. With the detail in the.level of supply and demand,
interfuel competition canbe assessed [45]. The PIES model has been criticized
for underestimating capital and environmental costs, the uncertainty in supply
and price of fuels, and the lack of constraints on production [451.
With -respect to the."local impact" type model the Wisconsin Energy model
(WISE model) has "stressed flexibility with maximum room for innovations" in
developing their modular f ormat. "The main subcomponents of the system are the
sociIoeconomic, primary.energy source, end-use demand, electricity production,
and environmental impact models," [45] which provide excellent evaluation.capa-
bility on the state level. The model can evaluate local regulatory policies,
provide for analysis of regional technology options, include engineering design
parameters, and assess the social and economic impacts of energy systems [451.

Battelle Columbus Laboratories, A Proposal to Develop Energy Price and
Availability Projections, p. A-2, April, 1973.

Federal Energy Administration, Project Independence Report, Project
Independence, p. 18, November, 1974.

Foell, W.K. The Wisconsin Energy Model:A Tool for Regional Energy Policy
Analysis, Energy Systems and Policy Research Report No. 101, p.6, November,
1974.

376

The model further permits a description of future changes i n policy and tech-
nology to examine the resulting.energy scenario. The WISE model "does not predict
the future, nor constrain all future trends to be like the past" [45]. With
modification the WISE model could be utilized by other states and as a data base
input into inter-regional (national synthesis),energy projection models.
The primary,results of Argonne's analysis of these state energy projec-
tion models is as follows: (1) all models were found deficient in that they
failed to.consider interregional competition.and did not integrate energy supply
and demand forecasts with economic growth, and (2) none of the models studied
were able to-adequately predict and analyze regional effects of national.energy
actions [45]. This analysis should help to emphasize that the variations among
projection models,.due to differing methodologies,assumptions, and purpose, are
quite large. They also indicate that relying on a single model or source in
developing policy or plans for future energy demand should be avoided.

3. SELECTED GROWTH RATES FOR PROJECTIONS

For the purpose of evaluating future potential pressures on the Great
Lakes coastal zone, a number of potential fuel mix scenarios have been postulated.
The actual pressure-on the coastal zone will be a function of the increase in the
demand for electric power, the utilities' ability to construct sufficient
capacity, and the type of fuel chosen for the new gene rating capacity. The
choosing of an average or best-gues electrical demand growth rate would assume
that accurate knowledge of the future energy picture is known. The use of high,
medium, and low growth rates encompasses a number of possible energy futures.
More importantly it gives a range to the potential impacts of new energy facili-
ties from which it may be-possible to determine the requirements for fulfilling
the various scenarios. The integration of these growth rates with the four
scenarios described earlier will give an indication of the resources that might
be required by a certain fuel mix and electrical demand growth rate. These
figures can then be used by interested parties in developing policies that relate
to the fuels (need, transport, cost, etc.), siting, and regulation of future
plants.
To this end, three growth rates have been chosen representing a low
(3% per annum), a medium (5.5%) and a high (8%). The low growth rate might be
tied to high conservation rates; the medium rate will be close to the electrical
demand growth rate since the 1973 Arab,oil embargo; and the high growth rate

377

might be associated with an intensive electrification process due to substitution

for other fuel types.

E. IMPLICATIONS OF SCENARIOS

The direct extrapolation-of generating capacities does not take into
consideration critical factors which will greatly influence the determination of
quantities and types of current generating capacity. Thus, in conducting the
resource impact analysis, a number of assumptionswere made which have@a direct
bearing on the results of the analysis.
The mix of new generating facilities is assumed to be the following:
75% base load, 20% intermediate load, and 5% peak load capability. Coal and
nuclear facilities will compete for base load generation capability and for half
of the intermediate load. Oil, gas, and hydroelectric facilities will be used
primarily in intermediate and peak facilities. (Oil will continue to be used in
decreasing amounts as the base load fuel source.) Load factors for the new

facilities are assumed to be 65%.

Prices of primary fuels for electric power generation were not considered
in the analysis, but availability and price will play a major role in determining

the types and numbers of facilities constructed. No assumptions were made as to

the-substitution of electricity for other energy end use purposes, but such a
trend would be reflected in.higher rates of demand for electricity. The analysis
further assumes a standard 1000-MW unit size with the option to locate multiple
units on a site. Further expansion of present utility sites and reconstruction on
retired sites were assumed, thereby potentially lowering demand for total land
requirements by-15-25%. Two nuclear units were assigned to each site with
potential of up to 4'units per site before additional land would be,required.
Approximately one-half of the water required for a closed-cycle system is
consumed. The assumption was made that facility retirements would not substan-
tially affect the.amount of new capacity to be installed.
There are a number of critical points which .greatly.affect the demand
for electricity which have been ignored in this analysis. Any one of these
issues could greatly alter the demand for electricity and the capacity needed
over the next twenty years.,
The analysis does not consider the effect of prices on the demand for
electr icity, a central issue in most projections. No account is taken

378

@of the potential slackening in demand as population growth levels off or as
some saturation level for electricity is approached. Straight extrapolations of
present generating capacity do not c7onsider-increasing efficiencies over time in
the generation, transmission or end use of electricity. The present situation
of high reserve capacities and low load factors,.which may delay need for
additional capacity (increasing load factors will substantially reduce short-
term.need to increase capacity), is not addressed. Also not considered is the
regional or power pool level of demand-analysis which allows for a potential
reduction in required generating capacity due to better management and-the
sharing of,power through well-developed transmission networks. This partial
list of "critical factors not accounted for" suggests the many weaknesses of the
analysis. The point should be emphasized, however, that the analysis was
conducted as a demonstration of the magnitude of the resources required, should
certain capacity expansion schedules be followed, and not as a forecast of
capacity expansion in the Great Lakes Region.
Based on present (1975) generating capacity an&ele ctricity demand (by
state), future generating capabilities and demand levels have been postulated,
using the three growth rates (3%, 5.5%, 8%) at time increments of 10 and 20 years.
Using a simple compounded interest formula, the current electrical power capacity
.and demand levels were extrapolated at the three growth rates to give an indica-
tion of future potential resource requirements needed for new energy facilities.
While both capacity and demand projections were made for analysis-purposes only,
.electric generating capacity will be used in the assessment of future resource
requirements.
Working through projected required capacity figures provides a graphic
display of how fast new capacity would be required at various growth rates.
Given certain assumptions, such as traditional load factors and utility opera-
ting practices, a number of possible resource requirement schedules for the
,different growth rates can be postulated. The purpose of such an exercise is to
give a rough indication of what future demands for electric power might mean in
terms of land,. water, and fuel resources required for the new capacity. When
these resource requirements are combined with the four scenarios, some indica-

tion of the number and types of facilities may be estimated.

379

F. PROJECTED GENERATING CAPACITY AND RESOURCE REQUIREMENTS

On a regional level, using a.standard 1000-MW generating unit, the
additional projected capacity needed at a 3% growth rate through the year 1995
would be roughly 126,686 MW. Similarly, for the same time span, the amount of
capacity needed at growth@ rates of 5.5% and 8% would be 300,.677 MW and 575,642 MW
respectively. These numbers were determined by taking each state's 1975 genera-
ting capacity and extrapolating at-the three growth rates over a twenty year
period. Assuming no present facilities decommission, a rough estimate of the
number of new 1000-MW generating units (multiple units may be located on one
site) needed by 1995 would be 126 at a 3% growth rate, 300 at a 5.5% rate, and
575 at 8%. Due to the nature of the assumptions previously listed these figures

contain a substantial margin of error..

TABLE 74
NEW GENERATING CAPACITY REQUIREMENTS FOR 1995 (in MW)

(1975) Projections (1995)
State Base 3% 5.5%. 8%

Illinois 25,500 46,055 74,402 118,854
additional capacity 20,555 48,802 93,354
Indiana 13,315 24,048 38,850 62,060
additional capacity '10,733- 25,535 49,745
Michigan 18,926 34,316 55,437 8 8,558
additional capacity 15,390 36,511 69,632
Minnesota 6,700 12,100 19,548 31,228
additional capacity 5,400 12,848 24,528
New York 29,000 52,377 84,614 135,167
additional capacity 23,377 55,614 106,167
Ohio 25,780 46,561 74,943 120,159
additional capacity 20,881 49,163, 94,379
Pennsylv 'ania 28,770 51,961 83,943 134,095
additional capacity 23,191 55,173 105,325
Wisconsin 8,881. 16,040 25,912 41,393
additional capacity 7-,159 17,031 32,512

Region Total 156,872 283,556 457,547 732,512
total additional capacity 126,686 300,677 575,642

380

The land, water, and fuel resources required for these facilities could
be determined by using figures available for existing facilities. The result
represents an.average or ideal facility requirement and is subject to debate.
For coal-fired plants, fuel requirem ents are assumed to be 228 tons per
hour, or approximately 2 million tons of coal per year.. The Btu value of the
6
coal averages 20 x 10 per ton. For low Btu western coal, the heat value could
be 15-20% lower. Conversely for a higher Btu coal the heat content could be as
much as i5-20% higher.
Land requirements for. a 1000-MW coal-fired facility are 400 acres per unit.
This includes the land required for the plant with on-site ash and SOX disposal,
natural draft cooling towers, and storage for a six-month coal supply. Depending
on the mix of these variables, total land requirements can vary as much as 100
acres. Water requirements vary substantially between closed-cycle cooling systems
and open-cycle or once-through cooling, such that two sets of numbers will be
postulated to represent each system. The water requirements for a natural draft
cooling tower are 700,000 gallons per minute (gpm) (assuming a 12*-13'F tempera-
ture rise across the condenser) for the open-cycle and 10,000 gpm for closed-cycle

system.
Resource requirements for nuclear units vary as greatly as those of a -
coal-fired station. The fuel requirement for nuclear units has been deleted from
this analysis due to the unique problems posed by the handling,'transport, and
processing of nuclear fuels. Land requirements average 1,335 acres per unit
(135 for the actual facilities, and the additional 1,200 acres as exclusion zone).
Nuclear facilities, unlike coal facilities, are able to economize by siting
multiple units on a single site, requiring no additional land for up to 4 units.
Nuclear facilities require more water than do coal facilities, averaging
an additional 15,000 gpm for a closed-cycle system, of,which approximately 50% is
consumptive use, and up to I million gpm for an-open-cycle system, with some
consumption (assuming a 15*F temperature rise across the condenser).
These resource requirements are used in conjunction with the four
scenarios to indicate potential pressures on the Great Lakes Region in the siting
of new electric generating facilities. With the major exception of New York,
the Great Lakes states rely primarily on coal for base load generation, with an
average of 66%. The remaining capacity is made up of hydroelectric, 5%
(expected to provide a decreasing percentage of electric power as suitable sites
become scarce), oil and gas-fired, 17%, for base and peak supply, and nuclear,
currently 12% and expected to comprise roughly 35% by 19.90. The question of

381,

oil-fired generating units is somewhat more crucial to New York State, as it
presently accounts for about'40% of the state's power.

TABLE 75
1975 FUEL MIX BY TYPE FOR POWER GENERATION (Btu percentage by state)

State Oil Gas Coal Hydro Nuclear

8W
Illinois 4% 63% .1% 24%
Indiana 3%, 2% 93% U 0%
Michigan 10% 6% 72% 1% 10%

Minnesota 3% 12% 63% 2% 19%_

New York 39% 5% 15% 2 4%. 17%

Ohio 4% 2% 94% 0%

Penn. 14 /% 1% 74% 1% 9%
Wisconsin 1% 9% 57% 1 Z 2_8%
Regional
Weighted
Averap-e 13% 4% 66% -5 /% 12%

..The recent trends scenario suggests that nuclear generating capability
,Will grow to,approximately 35.% of the total generation over the next 15 to 20

years.
Based on 1975 figures, determined by weighted average of t he eight Great
Lakes states' fuel mix distribution, this works out to approximately 70,000 MW,
or 70 nuclear units, and 40,000 MW, or 40 new coal units, at the 3% rate by 1995.
This would bring the nuclear capacity up to 35% of the generating capability for.
the region with coal.comprising 50%, and oil, gas, and hydroelectric making up
the remaining 15%, accounting for roughly 18 new units.

The method for arriving at these figures involved determining the current
generating capabilities by fuel type for the states and weighing them,
accounting for differences.in each state's generating capacity, and coming
up with an average regional fuel mix. These figures were then used to
determine the approximate amount of capacity for each fuel type in the region.
Then, with the additional capacity required by the three growth.rates, the
number of new units was determined by multiplying the expected capacity
percentage for each fuel type by the to\tal capacity in 1995 and subtracting
the present capacity.'

382

Land requirements for nuclear facilities in the recent trends scenario
at a 3% growth rate are on the order of 46,725 acres for the region. This
assumes that two units per site woL require no additional land. 'Additional
units per site would reduce land requirements further. 'The water require-
ments for these 70 nuclear facilities, using a closed-cycle cooling system,
are 1,512 x-106 gallons per day (gpd), while for a once-through.cooling system,
1,008 x 108 gpd would be needed. Similarly for the coal-fired uni Its, land
requirements total 16,000 acres and fuel consumption would equal 80 x 106 tons
per year. Once-through cooling water equals some 403 x 108 gpd, and a closed-
6
cycle system would utilize some 576 x 10 gpd. As is evident, even at a low
growth rate the number of new 1,000-MWe units required by 1995 is substantial
an(i indicates the need for rational long-term planning.

The amount of new capacity required at a 5.5% growth rate would be
141,000 MWe. or 141 nuclear units and.121,000 MWe, or 121 units, for coal-
fired generation. Oil, gas, and hydroelectric might contribute up to an
additional 35,000 MWe.
Nuclear facilities would require 93,120 acres of land, 3,046 x 10 6 gpd
of water for a closed-cycle system, and 2,030 x 10 8gpd for a once--through
cooling system. The coal-fired facilities would require 48,400 acres of land,
242 million tons of coal -per year, 1,220 x 10@ gpd for a once-through cooling
6
system, and 1,742 x 10 gpd for a closed-cycle cooling system.

Table 76

ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR
SCENARIO I, RECENT TRENDS

Growth Rates
Type 3% 5.5% 8%

Nuclear (units) 70 141 238
land requirements (acres) 46,725 94,120 158,865
water requirements (gpd): 8 8 - 8
once-through 1,008 x 106 2,030 x 10 6 2,427 x 106
closed-cycle 1,512 x 10 3,046 x 10 5,141 x 10
Coal (units) 40 121 185
land requirements (acres) 16,000 48,400 - 74,000
fuel requirements
(millions of tons/year) 80 242 370
water requirements (gpd): 8 8 8
once-through 403 x 106 1,220 x 10 6 1,865 x 106
closed-cycle 576 x 10 1,742 x 10 2,664 x 10

383

At a growth rate of 8%, approximately 238,000 MW, or 238 nuclear units,
would be required and 185,000 MW, or 185 units, for coal-fired generation. The
nuclear. units would need 158,865 acres of land, 5,141 x 10. 6 gpd of water for a
8
closed-cycle cooling system, and 3,427 x 10 gpd for-a once-through system. The
coal units would require 74,000 acres of land, 370 million tons of coal,
6 8
2,664 x 10 ,gpd of. water@ for a closed-cycle cooling system, and 1, 865 x 10 gpd
for a once-through system.
The second scenario postulates a fuel mix,for the year 1975 comprised of
70% coal, 15% nuclear, and 15% oil,and gas. At the 3% growth rate the number.of
new facilities required by this scenario will be approximately 96 coal units
(1,000 MW each), 24 nuclear units, and about 20 oil or hydroelectric units. The
resource requirements for these facilities are shown in Table 77.,

Table 77

ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR
SCENARIO II, HIGH COAL ELECTRIC

Growth Rates
Type 3% 5.5% 8%
Nuclear (units)' 24 50 92
land re quirements (acres 16,020 33,380 61,410
water requirements (gpd):
once-through 346 x 10 8 720 x 10 8 1,325 x 10 8
closed--cycle 518,x 10 6 1,080 x 10 6 l,'987 x 10 6
Coal (units) 96 217 410
land requirements (acres) 38,400 86,800 164,000
fuel requirements
(millions of tons/year) 192 434 820
water requirements (gpd): 8 8 8
once-through 968 k 106 2,187 x 106 4,133 x 10 6
closed-cycle 1,382 x 10 3,125 x 10 5,904 x 10

The third scenario assumes that nuclear generating capability will equal
that of coal-fired generation. The fuel mix breakdown for this scenario is
approximately: 45% nuclear, 45% coal, and'10% oil.
The fourth scenario postulates a rapid development of new technologies,
hence, a somewhat reduced dependence on more conventional generation.technologies.
It suggests a fuel mix having the same proportions between fuel types as that of
recent trends, but with a reduction of 20-25% in the number of new coal and
nuclear facilities required. Given this similarity, the resource requirements
for the new technologies scenario are assumed to be 70-80% of those postulated

for the recent trends scenario.

384

Table 78

ADDITIONAL FACILITIES REQUIRED BETWEEN 1975-1995 FOR
SCENARIO III, HIGH NUCLEAR

Growth Rate's
Type 3%' 5.5% 8%
Nuclear (units) 104 177 311
land requirements (acres) 60,420 118,150 207,590
water requirements (gpd): 8 8 8
once-through 1,498 x 10 6 2,549 x 10 6 4,478 x 10 6
closed-cycle 2,246 x 10 3,823 x 10 6,718 x 10
Coal (units) 12 91 227
land requirements (acres) 4,800 36,400 90,800
fuel requirements
(millions of tons/year) 24 182 454
water requirements (gpd): 8 8 8
once-through 121 x 106 917 x 106 2,288 x 10 8
closed-cycle 173 x 10 1,310 x 10 3,269 x 10

G. COASTAL ZONE RESOURCE IMPACT ANALYSIS

1. RELATION OF PROJECTED DEMAND TO POWER PLANTS

The implications of these figures vary greatly from county to county in
the Great Lakes coastal zone. The limitations of the analysis notwithstanding,
the potential impact of energy facility siting can be estimated by assessing the
current importance to the states of coastal county energy facilities and then
assuming that this current proportion will hold constant in the future.
For the States of Illinois, Pennsylvania, and possibly Indiana, the
future of their coastal counties with respect to energy facilities will most
probably be limited to demands for access to the water rather than the physical
siting of facilities on or near the shoreline. This aspect of coastal,zone
utilization is further limited by the difficulty of siting new generating units
in the.already heavily developed Indiana and Illinois counties. Pennsylvania's
coastal county, being somewhat less developed, has a slightly higher potential
for access. It may turn out, however, that as an increasing number of facilities
require water supplies no longer obtainable from inland sites, there will be
increased pressure to transport coastal waters further inland.
Minnesota currently has the lowest number of energy facilities in the
coastal zone. The current percentage of coastal zone generating facilities of
the state total is roughly 5%. Further, there are no plans at present to
construct any facilities. If land presently categorized as agricultural or

385

undeveloped were considered potentially available for the siting of energy
facilities, Minnesota would have 11 mile's of coast land available for energy

facilities.

By taking the total new generating capacity required by the four
scenarios and determining Minnesota's portion based on the percentage of
current capacity, a tough idea of the number of new Minnesota facilities required
could be derived. (This procedure will be followed for the remaining states.,)
Minnesota's share of the postulated new-facilities would range from 6 plants at
a 3% growth rate to 23 facilities at an 8% rate. Maintaining 5% of its total
capacity in the coastal counties, only one or two new coastal facilities would be
required. These facilities would take approximately 1000 2000 acres of land,
with the water and fuel resources presenting little additional burden to the
coastal zone. Assuming a pressure to site an increasing percentage of the state's
tot al generating capacity in the coastal zone, the number of new facilities there
may rise to five or six.
Following the same procedure, the pressure on the coastal counties in
Wisconsin is seen to be substantially greater than that in Minnesota. Currently
59% of Wisconsin's generating capacity is located in coastal counties. With
8,881 MWe, Wisconsin comprises 6% of the Great Lakes Region's total generating
capacity. Based on these figures, the potential number of new facilities required
in the Wisconsin coastal counties ranges from 8 at a 3% growth rate to 20 at 8%.
The resources required for these new facilities will*vary depending upon the
scenario. Assuming equal development of both nuclear and coal facilities the
requirements in the coastal counties might be the following: land requirements--
from 5,870 acres for 8 facilities to 10@,675 acres for twenty; water requirements--
for a closed-cycle cooling system from 100,000. gpm to 250,000 gpm, and for an
open-cycle cooling system between 6.8 x 10 6 gpm to 17 x 106 gpm. With one-half
of the new facilities being coal"fired the fuel requirement would range from
8 million tons/year to 20 million tons/year.
Ohio's current generating capacity is approximately 25,225 MWe of which
21% is located in coastal counties. Under the regional projections, Ohio's
coastal counties would need to accommodate 4 new generating units at the 3% growth
rate and 19 at the 8% level. Again, assuming equal numbers of both coal and
nuclear facilities the resource requirements would be within the following range:
land--from 2,135 acres for 4 units to 10,140 acres for 19 units; water--for closed-
cycle systems between 50,000 gpm and 237,500 gpm, and for open-cycle systems,

386

6 6
requirements would fall between 3.4 x1o gpm and 16.15 x 10. gpm. The fuel
requirements for the coal-fired facilities vary between 4 million tons/year and
19 million tons/year.
New York's generating capacity is currently 29,000 MWe of which 27% is

in coastal counties. The number@of new facilities in the coastal counties would
range from 7 plants at a 3% growth rate to 29 at the 8% rate. With these numbers
of potential new coastal zone facilities the additional pressure on the coastal
zone would be significant. The resources required for these new facilities break
down as follows: land--from 3,740 acres to 15,480 acres for 29 new units; water--
from 87,500 gpm for 7 units closed-cycle cooling to 362,500 gpm for 29 units.
For open-cycle cooling these numbers range from 5.95 x 10 6 gpm to 2'4.65 x 106 gpm_
Coal requirements would fall between 7 million tons/year for the 3% growth pro-
je,ction to 29 million tons/year for the high growth rate.
The State af Michigan has the highest percentage (731%) of its generating
capacity (18,926 MWe) located in coastal counties. Michigan's coastal counties'
share of the projected new capacity would be 11 units at a 3% growth rate and 51
units at the 8% level. The requirements on Michigan's coastal counties break
down as follows: land--between 5,870 acres and 27,220.acres; water--in a closed-
cycle-cooling system between 137,500 gpm and 637,500 gpm, and for the open-cycle
5 6 6
system between 9.3 x 10 gpm and 43.35 x 10 gpm. The coal requirements,
assuming an approximate 50% coal fuel mix for projected base load generation,
would range between 11 million tons/year and 51 million tons/year.
The,number of postulated new facilities in the coastal counties associated
with the 3% growth rate might be assumed to accurately represent the minimum over
the next twenty years. This is supported by the following: (1) "best guess"
estimates for growth in energy demand hover around 5).5%, hence a 3% growth rate
might reduce the errors in many of theassumptions made in the analysis, (2) the
thermal.loading of inland waters will increase the pressure on the Great Lakes
for cooling purposes' (a good example of which might be the Ohio River system),,
and (3) the proportion of generating capacity currently located in the coastal
zone (or utilizing.land and water resources) may rise in the future rather than
remain constant. At this time, it should be apparent.that the demand for
electricity over the next twenty years will be a major factor controlling
pressures on the Great Lakes coastal zone with respect to energy facility siting.

387

2. RELATION OF PROJECTED ELECTRICAL AND FUEL DEMANDS TO FUEL TRANSSHIPMENT
AND STORAGE

The future demands for electrical energy production interact with the
expansion and development of fuel transshipment and storage facilities in a
complex and diverse manner. The discussion of this topic will center primarily
on the effects coal movements mayhave on the future of these facilities.
Oil, presently contributing a smaller percentage of the region's fuel
mix, is expected to have a minor impact on the future development of ports and
terminals. It was felt that the facilities were adequately developed to handle
liquid fuels and that competition from pipelines and rail movement would, in the
future, further reduce the@relative percentage of this fuel moved on the lakes.
Additionally, the questionable role of oil in the future generation of base load'
power was taken into account.
Coal, which is expected to contribute to the major fossil fuel demands
for power generation in the region, will continue to depend heavily oft movement
through transshipment facilities.
Assessing the adequacy of these facilities1s complicated by a number of
intrinsic and external variables. In previous sections of this report the
capacity of ports and terminals was analyzed from a historical perspective. In
examination of the prior ten-year period it was determined that the system could
presently double the coal tonnage moved on the Great Lakes. This would invo.1ve
additional shipments of approximately forty million tons. -The assessment, how-
ever, does not specify the quality or origin of the coal transported. @Under
this evaluation, higher sulfur eastern and midwestern coal would contribute
heavily to the total shipments through the facilities on Lakes Erie and Michigan.
The,relative percentage of eastern versus low sulfur western coal moved on the
Great Lakes is crucial in any assessment of future impacts of coal on ports and
terminals. This eastern/western mix is largely dependent on the@development of
low-cost technologies of sulfur removal either before or after combustion.
The competition between rail and lake vessel movement is also central to
an examination of future demands on ports and terminals. In 1975, 4.4% of the
coal used in the eight Great Lakes states for electric power generation was moved
on the Great Lakes [604]. Fluctuations in this relative percentage will
naturally affect the impact that coal shipments on the Great Lakes will have on
transshipment facilities.

388

@The pre ious section developed a number-of-scenarios based on the future
v

fuel mix:for electric power generation. An examination,of the scenario,projecting
.a high coal fuel mix is most relevant to the future coal movement'on the Great
Lakes.:,A--general discussion of impacts.on ports and terminals can be developed
through examination of this scenario. Analysis of projected activities:at
particular ports on the lakes is not feasible and would be highly speculative,
conside ring the vagaries of'future compIetition from other modes,of transport,and
the relative utilization of-high or low,sulfur coal. It is possible,. however, to
analyze the.overall implications of such a high coal scenario on transshipment

facilities.

Taking the 8% growth rate developed in the high coal scenario for
electric generation as an upper bound, the fuel requirements are projected as an
additional 820 million tons of coal for the eight Great Lakes states. Assuming
Lake traffic contributes 4.4% to the total movement of coal for electric power
generation, waterborne coal movement,would increase by 36 million tons.' It must
that this figure is the product of extended extrapolations and as such
becomes increasingly removed from the eventual realities of coal. transshipment..
Based on a relative fuel mix at a given growth,rate,' assuming an average heat
value of.coal and a relative percentage of 1ake movement, the figure of an
additional 36 million tons by 1995 for utility;use on the lakes,should be viewed
with guarded skepticism. This tonnage figure will be used strictly,as representa-
tive of a substantial increase in coal traffic on.the Great Lakes and may rise to
higher levels if shipping takes a larger share of the total transport market of

coal to electric utilities.

The impact of this additional tonnage demand on transshipment.facilities
can be discussed on a regional level varying the coal origin (eastern versus
western) as it relates to the geographically specific,locations of transshipment.
If one assumes that utilities, in.an effort to comply with air quality regulations
and in the absence of efficient sulfur removal techniques, purchase western low
sulfur coal, then the pattern and movement of Lake traffic of coal will shift
substantially. A considerable increase in western coal utilization of the
magnitude previously described would place enormous stress on the facilities
presently in use. This is compounded by the fact that generally western coal has
a lower heating value than coal from eastern mines, necessitating even greater
volume throughout. Facilities at Superior, Wisconsin and perhaps Chicago would
handle much of the additional load. However,'with the cost advantages inshipping

389

over long distances one would expect that additional facilities would be requi.red
and expansion of.present coal handling ports would occur. It is difficult to
project the location of the additional facilities on a site-specific basis, but
relative to cost reduction in delivered price one wo uld assume a maximation of
the direct waterborne portion of transportation, encouraging further developments
on the western end of Lake Superior.
The high coal scenario hinges primarily on the absence of efficient'low-
cost sulfur technologies,. With such development the pressures on transshipment
facilities may return to the ports of the lower.Lakes and specifically to the
facilities on Lake Erie. The long-established and highly developed ports of this
region would require less overall new development and expansion than would be
expected for increases in western coal use. The upbound movement from these
ports would facilitate the continuation of the traditionally economically
beneficial iron ore/coal interchange at the Lake Erie ports.
Either extreme of strictly western versus eastern coal is unrealistic.
In this discussion the pressures on the transshipment facilities are examined from
.a perspective of the relative emphasis of coal origins. Utilities commonly
blend coal of varying sulfur contents to achieve a mix that will meet air quality
standards. Future demands on the movement of coal through transshipment facili-
ties are largely a function of what thefuture mix will be as related to the
economies and technologies of coal-fired generation and emissions control-.

391

Chapter VI

POLICY OPTIONS RELATED TO THE SITING OF ENERGY FACILITIES
IN THE GREAT LAKES COASTAL ZONE

A. INTRODUCTION

The principal objective of this study is the development of a full range
of policy options for the siting of energy facilities in the Great Lakes coastal
zone. Institutional arrangements and technical-environmental-economic appro aches
are emphasized in the options. The institutional options cover options for:
(1) siting policy, (2) organizational arrangements, (3) functional responsibili-
ties, (4) siting procedures, (5) siting criteria and standards, (6) financial
mechanisms, and (7) intergovernmental relations. The technical options.include
options for: (1) the exclusion of all new facility development from the coastal
zone management area including access to coastal waters and related fuel trans-
shipment; (2) exclusion of all new facility development from the coastal zone
management area, but allowing coastal water access, re lated fuel transportation
and product transmission through the coastal zone; and (3) inclusion of new
facility development in the coastal zone management area except in designated
sensitive areas in which additional development would be precluded.
These options are only suggestive. No recommendations are made that a
state or program should adopt any of the options proposed. The situation ineach
state will dictate the kinds of options it might employ in planning for and
managing the effects of energy facilities sited in or near the coastal zone.
Some of the options would entail major reorganization of institutions or revi-
sion of siting criteria, regulations and standards. Other options suggest use..
of existing institutional arrangements or augmenting present siting criteria and
regulation.

392

Selection of,certain options will preclude choosing other options.
However, selection of combinations of options within and among the categories
mentioned above are essentially unrestricted.
This listing of options is comprehensive, but is not intended to be
exhaustive. The agencies affected will probably identify additional options and
develop the details of these options as they relate to their respective programs.
The energy growth rates used in this study (in Chapter V) do not affect
which options might be chosen, but they do serve to suggestt how much emphasis
a particular state might place on developing an energy facility siting program;
how comprehensive that program might be in terms of facilities and fuels; what
the areal extent of the program jurisdiction should be; which levels of govern-
ment should be involved with the program; what involvement the state.coastal
zone management program might have in such a program; and what authorities and
sanctions should be vested in the program.

393

B. INSTITUTIONAL OPTIONS

1. INTRODUCTION

Options discussed in this section were derived from the study of exist-
ing state programs for the siting of energy facilities and of various proposals
for improving such programs. Where an option can be identified with a particu-

,lar state program, the state is indicated by its two-letter postal service
abbreviation in parentheses. In this manner, the interested reader is directed
to the appropriate st.ate program description or to the state itself for addi-

tional information.

The options discussed in this section range from general approaches to more
specific procedures and,criteria that may be employed in the regulation of
energy facility siting. The seven categories are: Siting.Policy, Organizational
Structure and Arrangements, Functional Responsibilities, Siting Procedures,
Siting Criteria and Standards, Financial Mechanisms, and Intergovernmental

Relations.

2. SITING POLICY
Energy facility siting is closely related to numerous traditional
functions of state government. In establishing policies to regulate,energy
facility siting, a state may choose to specify the relationship of the siting
program to one or more of these functions, thereby imposing a philosophy of
operation on the siting process. Several of these relationships and their
possible impacts are described below. The lack of any such relationship would
imply that utilities and other energy producers/distributers have almost com-
plete freedom in site selection.

a. Traditional Utility Regulation
This approach represents the status quo in most states that have not re-
cently enacted energy facility siting legislation. Traditional utility regulation
has received criticism for avariety of reasons, including: failure to consider
.al1aspects of the siting issue; lack of earl y public participation; the multi-
plicity of independent local and state agencies with responsibility over some
phase of siting; and the delays that result from this process. However, these.
11problems" do not seem to be inherent features of traditional utility regula-
tion. The process may be improved by means of interagency agreements or orders

394

of the Governor, while maintaining the basic.system of-responsibilities.
ILn2lications. Possible consequences of this arrangement include subordi-
nation of environmental considerations and the inability to address the broader
issues of energy pol icy and land use. Without a legislative mandate it may not
be possible to assure that the criticisms.listed in the above paragraph are
with adequately. Utility regulatory commissions are'traditionally con-
cerned.primarily with economic matters affecting.service charges and return on
utility investment and the.safety and engineering,,aspects of facilities. The
resolution of conflicts over economic and environmental issues, which are com-
mon in energy facility siting, may requireexpanding,the regulatory commission
".to include members with appropriate backgrounds.

b. Energy Policy
The siting function may be.handled in the broad context.of.state energy
policy. The emphasis would be on regulation/allocation of fuels to assure
adequate supplies of each type for essential or best purposes, and also to
assure adequate supplies of electricity. The program may include methods of
,limiting electricity demand and conserving energy,in all forms..
Implications.- Projections.of (electrical) energy demand indicate an esca-
@ating demand for sites. The siting.function would be simplified if the demand
for sites could be reduced by means of an.aggressive state energy conservation
program. Thus, the option of foregoing sites is.contingent,uponl.reducing

demand.
Another aspect of energy policy, the interchangability offuels to provide
energy, is also closely related to siting questions. For example, the fuel
type of a power plant has definite environmental implications that affect the
suitability of a site, while the choice o,f,lfuel type must be made in light of
state or national requirements for alternative uses and for environmental pro-
tection. Extraneous factors that affect siting decisions,might include the
environmental degradation accompanying the strip mining of. coal,,the scarcity
of natural gas and its requirement for other, industrial, and domestic purposes.
the precarious situation entailed by dependence onjoreign supplies of oil, and
the problems associated with the reprocessing and.disposal of nuclear wastes.
Combining the responsibilities for siting regulation-and energy policy in one
agency would facilitate these decisions. Lack of.a.cohere.nt national
energy policy also affects local and regional facility siting regulation by not

395

providing adequate direction for future fuel use, and thus the types'of plants

that should be constructe&

c. Land Use Policies

This option would treat all major construction projects, including energy
facilities, as significant impac.ts requiring state approval. The emphasis would
be on patterns of land development and-regional economic and environmental
impacts. A corollary to this option would be to limit land use control1juris-
diction to the coastal zone. Such.an approach would recognize the unique and
valuable aspects of coastal lands and the heavy development pressures they are
subject to. Whatever energy facility siting process applied to the remainder of
the state would necessarily be closely coordinated with the coastalzone manage-'

ment function.

Implications. For the state to assume land use control requires the
retaking of authority that has traditionally been relegated to local units of
government. This may not be a popular approach, and heavy restrictions on the
size and type of facility or project or-the geographic area that would be sub-
jected to state control may be required.- It may be appropriate to recognize the
regional nature of many large facilities, including power plants and o .ther
energy facilities, and provide for state control of their siting. Restricting
control to the coastal zone would recognize the critical importance of this
region and would satisfy the requirements of Section 306(e)(1) of the Coastal
Zone Management Act. Less direct state land use control in the coastal zone is

also an option under the Act.

d. Pollution Control/Environmental Protection
This option would place emphasis on pollution standards and the relevant
technology to. assure protection of air, land and water resources. Siting con-
trol would probably reside with the state's environmental protection agency.
Critical or fragile areas would be heavily protected.
Implications. Environmental protection*is a,primary concern in energy
facility siting. Historically, utility regulation commissions have placed more
emphasis on adequate provision of energy than on environmental issues associated
-with energy production. In many states the environmental protection agency
already has major responsibilities for,issuing permits and certifying the
environmental compatibility of facilities. It would generally be only a small

396

step to enable suchagencies to haveoverall.authority for site certification.
However, it may be difficult to obtain unbiased decisions from an agency with an
historic emphasis in one direction.

e. Scope of Facility Siting Regulation
Two basin options exist for the types of energy facilities subject to
state regulation, though the intervening ground is a continuum between the two.
One one hand, regulation may apply-to all energy facilities: power plants,
transmission lines, pipelines (gas and oil), refineries, transfer and I storage
facilities, and coal gasification and liquefaction facilities, and perhaps large
scale solar collectors, etc. On the other hand, regulation may be limited to
facilities constructed by regulated monopoly utilities (i.e., gas and electric
companies). This approach might even limit itself to power plants and trans-
mission lines, in light of their high public visibility and the need to balance
the demand for electricity with the protection of the enVironment and economic

issues..
lalications. The scope of facility siting regulation may depend on the
ov erall responsibility or emphasis of the primary siting agency. If the state
has a program to deal with energy policy, it may be feasible to regulate a broad
range-of facilities, whereas maintenance of the traditional system of utility
regulation with a slightly broader scope to address siting is sues might dictate
a limiting of the regulatory process to utility-owned facilities.

f. State Power Authority
A state may elect to compete with or supersede public utilities in the
matter of construction of base load power plants. A state power authority could
construct and operate power plants and sell power at'.cost to utilities for ulti-
mate distribution to customers. The power authority would have primary respon-
sibility for selecting facility sites that are compatible with all aspects of

environmental and economic concerns.

Implications. Recent economic developments affecting interest rates,
construction costs and fuel costs have raised doubts concerning the ability of
investor-owned, privately managed utilities to meet the future demand for elec-
tric power. I Numerous power plant plans have been. delayed or cancelled. Imple-
mentation of the state power authority concept would be a response to percep-
tions of the present or potential severity of this,situation. The state

397

authority would be able to borrow money at lowerrates through the is6uance'of
tax-exempt bonds and would not be required to pay stock dividends.
The critical question in establishmentof a 'State energy authority is:
Who may best serve the public in the production of electrical energy; the pri-
vate sector or the public sector?, The private sector may argue that they have
traditionally served the public well, that the profit motive guarantees con-
tinued high quality service, and that the current'regulatory process is a major
source of difficulty. An evaluation of the relative merits of each-side -of the
question is beyond the scope of'this -report. Intereg ted persofis'might obtain
the Brickley Commission Report, Gove-knor's'Adviso-ry Commisslon-on Electric'Pou'Ter
Alternatives, State of Michigan, August 1976.

3. ORGANIZATIONAL STRUCTURE AND ARRANGEMENTS

Within any of the general policy mechanisms discussed in the previous
section, a variety of agency structures are possible for the regulation of'
energy facility siting. A state may elect to forego establishment of formal
siting procedures, in essence leaving siting regulation in the hands of local
zoning authorities.' Howeveri compliance with the Coastal Zone Management Act
requires, at the least, that states establish criteria and standards to'guide
local authorities in establishing zoning Irestrittions-in the coastal zone, sub-
ject to state review and enforcement of compliance.'
The organizational arrangements,discussed below ate intended to apply to
an agency or formal program for the regulation of energy facility siting. Sub-
Sequent institutional options will not necessarily require the establishment of
a siting agency.

a. Multi-stop Process
This option requires review and approval by each agency with an interest
in the various aspects'of energy facility siting And is the process that has
evolved in many states (IL, IN, MI, PA). The Public utilities commission, Air
and Water pollution control agencies,'local zoning boards And perhaps several
other state and local agencies would all be involved in the siting pIrocess.
Within this framework, it is possible.to establi-sh a coordination mechanism
that provides for the timely Siting of facilities and minimum duplication
through a unified application procedure and'condur-tent hear ngs.
Implications. This option takes advantage of existing expertise within

398

various state agencies and does not unnecessarily tie up a permanent staff for
infrequent siting work. However, even with provisions for coordination,.the
process will lack the ability to resolve conflicts among competing interests
in the siting process, since no single body has such authority.' The lack of
public participation at the decision-making levels may adversely affect the
credibility and responsiveness of the agency.

b. Consolidation of Authority
Again using existing agencies, but shifting primary responsibility to
one or two agencies (WI), this option facilitates the siting process by stream-
lining it and providing for consideration of conflicting interests by a single
agency. (Even where two agencies share responsibility, each would consider
several opposing issues.) Primary candidates for this arrangement would be the
public utility commission and the environmental protection agency. Local
authority would be preempted.
Implications. A shift in responsibilities of this magnit ude would prob-
ably require legislative action. The public utility c ommission would be in-
volved only with regard to regulated utilities, so that in a program encompas-
sing an extensive range of energy facilities it would be more appropriate to
place major responsibility for site approval in an environmental protection
agency, perhaps acting through a siting council within the agency. Certifica-
tion of facilities constructed by regulated utilities would still be under the
purview of the public utility commission.

C. Siting Agency Composed of Heads of State Agencies
The principal siting agency would be composed of the heads (or their
designees) of the state agencies whose missions relate to or are affected by the
siting of energy facilities (MD, WA' OR). T his could include representation of
the department of natural resources (DNR), the state environmental protection
agency (if separate from the DNR), the public utility commission, the department
of economic development or commerce, the department of public health, the depart-
ment of transportation and possibly others. It would also be possible to in-
clude a representative of the state coastal zone management program on this coun-
cil. The council would meet several times during the site approval process and
engage existing agency staffs for requisite research and information functions,
The chairman of such a council'@@ould be the head of the state agency in which

399

the state CZM program is situated. If organizational arrangements would pre-
clude this, then the chairmanship could be shifted to the.head of the state
agency which has responsibility fof the state CZM program when the proposed
facility affects the coastal zone.
Implications. This approach would insure direct involvement in the
siting decision process of the concerns,and interests represented by.the prin-
cipal state agencies and draw on the varied expertise of the agency heads.
It would also permit efficient transfer of information between supporting staff
and siting agency members by using the existing lines of intra- and inter-agency
communications, or by minor modifications thereof. The administrators are
familiar with the details of their respective-policies, programs, and legal
authorities and.are well equipped to evaluate siting proposals in terms of these
factors. Adequate consider ation of coastal zone policies could be achieved if
the CZM program were represented directly or if the DNR representatives were to
represent coastal zone interests as part of overall DNR concerns.
This option does not provide for direct public participation in siting
decisions. It would be necessary to provide extensive opportunities for public
access to information and for the expression of public opinion. Insurance of
adequate consideration of a wide range of the problems and needs associated with.
energy facility siting would be dependent on the.comprehensiveness of the agency
programs and the structure of the overall energy facility siting program.

@d. Public Members

A siting council may be composed entirely of public members or only
partially so. Public members would most likely be appointed by the Governor,
possibly with state senate approval. The backgrounds.of members may be speci-
fied in order to insure a wide range of expertise or.experience in applicable
fields. It may be desirable to restrict the past and future employment of
council members by those regulated (potential applicants).
implications. Direct public involvement enhances credibility with public
members either representing the broad public interest or with a balance of biases
(backgrounds) specified by law. Specification of backgrounds helps assure a wide
range of expertise. Employment restrictions further enhance credibility and may

be applied to nonpublic council members as well.
'Including public members on a council of state agency heads (MN) would

400

enhance credibility while taking advantage of existing exertise in matters
related to siting.

e. Hearings Examiners
Various proposals exist for establishing a siting council based on the
legal system. The council members would have both legal and technical back-
grounds and would act as hearings examiners. The various interests involved
would'all be represented and the case would be decided on the merits of the

arguments.
-Implications. The court system is currently used as a last resort in
the adjudication of siting issues. Relegating siting responsibility to hearings
examiners may reflect an increasing difficulty in reaching decisions under an-
other system and a desire to obviate court action. This may be an effective
means for rational decision making on siting issues, relying on the professional
integrity of the small (three to five member) board of hearings Iexaminers.

f. Independent Staff
Within the structure of an energy facility siting council such as c.,
d., or e.. above, there may be established an independent staff to collect and
analyze data on energy demand and other matters, to conduct environmental stud-
ies on proposed sites, and to provide whatever other information the council

requests.
Implications. The requirement for an independent staff may be predicated
on the.amount of work to be done (number of facilities to be sited) which may
depend on the range of facilities addressed. There are probably sufficient num-
bers of power plants projected for each of the Great takes states to warrant an
independent staff. The staff would help determine the need for energy facili-
ties and could establish itself as a source of expert information on all aspects
of energy facility siting.

9. Ad Hoc Member(s)
This option entails ad hoc representation on the siting council by a
citizen of the region being considered as a possible site. Appointment may be
by the legislative body (municipal or county) with jurisdiction over the pro-
posed site, and the representative may or may not be a member of such body.

Service on the council would be for the duration of deliberations on that site.

401

Implications. This option promotes credibility by assuring that the
views of the affected community are expressed and considered in the siting
process. But if the application process requires consideration of alternative
sites, there may be two or three (competing) representatives of the several

candidate communities on the council.

4. FUNCTIONAL RESPONSIBILITIES

Several functions are associated with the regulation of energy facility
siting. Of the functions listed in this section, not all would necessarily be
performed in each state. Those which are performed may come under the purview of
any of several organizational entities, including federal, interstate, state,
intrastate, and local governments; the private (corporate) sector; and the
general public. Within each of these categories, consideration is limited to
the agencies that have been established with authority to undertake such respon-
sibilities. The discussion of each function will attempt-to identify those en-
tities most likely to assume responsibility for that function and the possible
consequences of such delegation of authority.

a. 'Long Range Planning
Utilities and other potential constructors of energy facilities engage
in long range,planning, but such plans are often proprietary, leading'to a "plan-
disclose-defend" paradigm of energy facility siting. Long range planning, in-
cluding demand-projections and evaluation of alternative prospective sites, is
an essential part of the overall siting process. If a state finds a need to
regulate energy facility siting, one of the first steps is to'regulate the pre-
paration,and-disclosure of long range plans. so that a comprehensive view of
expected-future development may be obtained. The desirability of such a future
may then be,evaluated and siting decisions made in terms of their impacts on the

future.

-(1) Long Range Energy Planning and,Forecasting Performed by Private
Sector Without State Intervention

Under this option, determination of long range energy demands and
forecasts and evaluation of potential sites would be the function of the power
industry. Plan disclosure would not be required, and the corporate sector
would operate under its own guidance.

402

Implications. This option recognizes the technical expertise and
monetary and personnel resources available to the private sector to invest in
long range energy planning. If a state chooses not to engage in its own inde-
pendent planning and forecasting, this approach assumes that the factors con-
sidered and the assumptions employed by the private sector adequately reflect
the problems and needs of the general public. Preliminary evaluation and
selection of prospective sites would.be based primarily on economic criteria
and on compliance with existing federal and state environmental protection
laws. There would be no assurance that there would be adequate consideration
of the full range of problems and needs expressed by the general public. Since
public disclosure of plans and forecasts would not be required under this
option, public accountability of energy facility siting decisions would be very

limited.

(2) Independent Long Range Planning and Forecasting Performed by
the State

Independent long range planning and forecasting conducted by the state
could be concerned with projections and trends of future energy-tise, and with
future site andfacility requirements.
Implications. There are some advantages associated with state indepen-
dent energy site planning and forecasti Ing. First of all, the state is able to
maintain a better overview of the total energy picture in the state. Factors
affecting the various sectors of energy development,and consumption could be
evaluated in a comprehensive, coordinated manner, and the relationships between
these sectors could be determined. This would facilitate the development of a
unified, integrated, statewide energy policy and would serve as a sound basis
for future siting decisions. One fundamental implication of this option is the
underlying assumption that sufficient legal authority exists to provide for com-
pliance with these plans by the private sector. If this were not the case,
there would be no means by which to tie future siting decisions into such plans
and forecasts.- The lack of such adequate authority would limit the value of
independent plans and forecasts to merely identifying the differences between
the long range goals and objectives of the private and public sectors.

403

(3) Long Range Energy Plans and Forecasts Prepared by Private
Sector with State Designated Guidelines and Criteria
This option provides'for re
.gulatory oversight of private long range
plans and forecast preparation. Under this approach the state would stipulate
the conditions for plan and forecast preparation. This would involve promulga-
tion of rules.and regulations outlining procedural requirements, public parti-
cipation in the planning process, identification of planning and forecast method-
ologies employed, substantive content of informational requirements, the number
and types of alternatives that must be examined, and other factors. It is also

possible to include within these guidelines the criteria by which to,assess the
probable environmental impacts of the prospective sites outlined in the long
range plans and forecasts. Another approach would be to require the evaluation
of these sites in terms of some set of state designated site suitability cri-

teria.

Implications. This option implies legislated authority for'government
involvement in long range planning conducted by the private sector. It also
involves public disclosure of energy plans and forecasts. There are several
advantages associated with this particular approach. Opening the planning pro-
cess up to public scrutiny greatly increases the accountability of actions by
the private sector. Establishment of standards and criteria by which to pre-
pare such plans and forecasts provides a well defined and consistentbasis on
which the private sector can rely. This reduces confusion, improves the
efficiency of government, and limits unnecessary cost incurred by the private
sector. Administration of such a program could be achieved by a public utility
commission, a state energy office, the principal energy facility siting office,
the lead coastal-zone management agency, or some combination of these organiza-

tions.

b. Environmental Impact Assessment
An important concern in the siting of,energy facilities is the impact of
the facility on the surrounding environment. Options for delegating responsi-,
bility for impact assessment include:(1) require the applicant for a facility
site to provide a report on environmental impacts to the state; (2) assign the
responsibility to a state agency; or (3) require that the assessment be performed
by an independent consultant. The independent consultant may in turn be respon-

sible to either the applicant, a state agency, or perhaps, the local

404

government with jur isdiction over the proposed site (NY).
Implications. The credibility of impact assessments would probably
be enhanced if the responsibility were placed with a government agency. If the
actual study were performed by the state, it might be easier to achieve a uni-
form methodology for comparing sites. If the-assessment were performed by the
private sector,, assessment criteria could be established by the state.

c. Final Site Approval
Land use control (zoning) has largely been delegated by the states to
local units of government. Retaking of a segment of this power by a state
would involve major decisions. At the state level, final responsibility for
site approval may rest with a siting council (NY,,OH, MD) or with the Governor
(OR, WA) or with the legislature. Legislative approval may be reserved for
special cases such as nuclear power plants (VT). The status quo in many states
would keep zoning as the province of local units of government. However, com-
pliance with the Coastal Zone Management Act requires that the state exercise at
least a modicum of control over local zoning in the coastal zone.. The Act lists
two options short of direct state land use control: 1) state establishment of
criteria and standards for local implementation, or 2) state review of all
development plans, projects, and zoning regulations for consistency with the
state's coastal zone management program. The state may choose to extend control
in either case to the entire state. Note that this would effectively address
all projects and facilities; not just those related to energy-
Implications. Giving authority for site approval to local governments
does not provide for consideration of the regional or statewide interests in-
volved in large energy facilities. Distinguishing the control over coastal
zone 'siting from that which applies to the remainder of the state may hinder
the rational selection of a site from among coastal and inland alternatives. A.
state siting agency, with provisions for prior approval by.the coastal zone
management agency of proposed sites in the coastal zone (CA), would provide for
both consideration of state/regional interests and special attention to the

coastal zone.

d. Monitoring
All states are required by federal law to monitor the quality of air and
water resources within their jurisdiction. A state may choose to expand this

405

monitoring program to include a broader range of environmental factors affected
by energy facilities (MD). This would involve sampling of natural parameters
--@such as physical, chemical, and biological effects, and cultural parameters
such as changes in land use patterns and social and economic conditions associ-
ated with the construction, operation, and maintenance of a facility. Responsi-
bility for environmental monitoring could be: 1) delegated to local government,
2) assigned to a private consultant, 3)' assigned to the energy corporation, or
4) placed with the state environmental protection agency or department of

natural resources.

Implications. A-comprehensive program for monitoring the environmental
effects of energy facilities would provide valuableinsight into those aspects
of energy development that are typically of greatest concern. It may also indi-
cate substantive areas in which criteria and standards for energy facility sit-
ing and for protection of air or water quality in general appear to be either
overly stringent, reasonably sufficient, or inadequate.

e. Conservation

In recognition of the scarcity of energy resources on an economic or
geographic basis, or of the adverse.environmental impacts resulting from their
use, the state may choose to implement a program of energy.conservation. The
scope.of such a,program may range from a requirement that utilities (and others)
describe conservation efforts as part of their plans, to a state agency with
.responsibility for specifying building codes, appliance and automobile effi-
Piencies and other measures to reduce demand and thereby reduce the number of
energy facilities required.
.Implications. Energy facilities in general represent huge commitments
of resources, including land, and have significant adverse impacts on the
environment. If an aggressive state program for energy-conservation can'slow
the rate of growth in energy demand, the effect should be to slow the rate of
construction of energy facilities, and, thus, slow the rate at which siting
decisions must be made and reduce the number of sites occupied at any given time
in.the future; Conservation can provide the siting regulation process with
the option of not siting a proposed facility. For further details related to
this option, the reader should consult Chapter V, Regional Scenarios of Energy
Development. The discussion there concerns a range of electrical energy.growth.
The energy industry, as part of our economic system, is probably

406

dependent on growth'for its economic well-being. In the regulated utility
sector, a slower growth rate may require adjustments in the rate scheme, but
this could be handled by the traditional regulatory mechanism. In the private
sector, the gradual slowing of the rate of energy consumption could result in*
the shifting of economic resources away from energy production.

5. SITING PROCEDURES

The siting process may entail a variety of procedures, most of which are
independent of the responsible regulatory agency. However, the procedures
listed here generally assume a strong state role in the regulation of energy
facility siting. Several options and their implications are discussed for each
of four procedural categories: the application process, site selection, treat-
ment of generic issues, and funding.

a. Applicatio Process
The regulation of siting implies that the construction of facilities
will follow an application process to decide the merits of a site. The formal
application may be preceded by a notice of intent to file such an application.
Actions taken on the notice of intent would include a preliminary evaluation of
the site and notification of potentially interested parties. Public hearings

may be held on the notice of intent.
The application itself may describe the site and the facility to be con-
structed thereon. Public hearings would most likely be held at this stage with
time limit s specified for the completion of the site approval process. The
state may require that the application include not only a preferred site, but
one or more alternative sites as' well. Coastal states may specify that at least
one alternative be outside the coastal zone. A separate application process may

be established for sites in the coastal zone.

Implications. Requiring a notice of intent allows time for a prelimi-
nary site evaluation before an application fee may be required. Public hearings
at intervals throughout the site approval process,help assure that the results
are responsive to public needs and desires. The specification of time limits
for the process assures the applicant that there will be no delays while allow-
ing ample time for consideration of all aspects of the issue.
Where the constructor of An energy facility is free to select which sites
to propose, the requirement for proposing alternative sites allows comparisons

407

of the relative advantages of each site. This is especially important with re-
gard to coastal sites where both the magnitudes of the-advantages and disadvan-
tages may be greater than for an inland site. The requirement for prior approv-
al by a coastal zone management agency for sites in their jurisdiction insures
protection of the coastal zone but denies the opportunity to compare the rela-
tive merits of coastal and inland sites. With regard to comparison of coastal
and inland sites, the reader is directed to the case Study and discussion of
coastal dependence that appears in Chapter IV.A.6.

b. Site Selection

Several options exist for a state to assure selection of acceptable
sites for energy facilities., The normal situation would leave-the decision to
the constructor of the facility through the application process. Advance con-
sideration of siting problems by the state may lead to one of.the following:
establishment of criteria to be used by the.constructor in the selection of
sites (MN); designation of regions of the state that are suitable/unsuitable for
various types of energy facilities (OR); establishment of inventory of specific
sites (MN); or actual purchase of land by the state for eventual-lease or sale
as sites-(MD).
Implications. The-plan-disclose-defend paradigm of site selection is no
longer satisfactory when a state chooses to regulate the siting of facilities.
An applicant for site approval deserves to at least be aware of the criteria
that the state will use in evaluating the suitability of proposed sites. Estab-
lishment of such criteria facilitates generic treatment of siting cases (see
section c. below) and serves to reduce ambiguity-in the decision-making process.
The designation of suitable and unsuitable regions for various energy
facilities may be used in addition to siting criteria. Such designations
result from the application of certain criteria, most likely those related to
air and water quality, to all regions (such as airsheds and watersheds) of the
state, taking into account the expected environmental impacts of each type of
facility.. This would also serve to provide applicants with needed information
to reduce wasted efforts of studying and proposing unsuitable sites.
Carrying the process one step further, the state could establish an
inventory of suitable site s, taking over the site selection function altogether.
Potential applicants could work with the state in establishing the inventory
and in proposing sites to be included. This may require the prior establishment

408

of criteria to be used in the selection of sites and the whole process might be
relatively time-consuming and expensive, but once the. inventory is established,
siting would be a relatively simple process.
The purchase of potential sites by the statecan serve to assure that
suitable sites are available, even if proposed sites are rejected. A revolving
fund could be established to purchase an initial inventory of sites.

c. Treatment@of Generic Issues
In the siting of energy facilities thereare a number of issues that
recur in the siting process. Such issues include: "questions of proper demand
policies, allocation of research efforts, the amount of new capacity needed, and
proper safety, environmental and land use standards" [6131. Some aspects of
these generic issues may be decided upon separate from (and prior to) the site
approval process. Some.generic issues related to site selection are discussed
in the previous section b.
Implications. Treating common issues beforehand simplifies the siting
process by reducing the volume of material to be considered in individual cases.
It can also serve as a means for providing applicants with information that
enables them to forego making proposals that are unacceptable to the state.
Furthermore, separate treatment of generic issues serves to reduce ambiguity
in the site approval process.

d. Funding
As a function of state government, the regulation of siting may simply
be funded through the normal budgetary process. However, energy facilities
offer a great potential source of funds that may be applied either directly or
indirectly to the siting process. Assessments may be considered in two broad
categories: application fees and annual fees. The two are riot mutually exclu-

sive..
The application fe e is a one-time charge to be paid upon submission of
an application for sitelapproval. Theamount may be fixed or may be a variable
charge based,on the size of the facility, measured either in terms of its
estimated cost or its design capacity (megawatts, barrels per day,,etc.). The
fee may fund the general operations of the siting process or be earmarked for a
specific purpose, such as environmental impact assessment.
An annual fee may be assessed against all potential applicants for an

409

energy facility site, or at least against those with existing facilities. The
fee may again be a fixed fee, or a variable one based on the output of the
facility in the past year, measured either in terms of quantity of output or
dollar sales. The state may choose to determine an adequate sum for funding
the siting process and,associated functions and assess those regulated on a

proportional basis.
Implication@j. Making site regulation financially independent.relieve.s
the burden on the state's general budget and obviates argument.s against the
establishment of such a function on financial grounds. The resultant higher
energy.rates may slightly reduce demand.

6. SITING CRITERIA AND STANDARDS

a.. State Designation of Site-Suitability Criteria
The state may wish to develop a set of criteria.by which to evaluate
..various energy facility siting proposals. These criteria could be quite general
or they could,be specified in detail. General criteria usually involve.rather
broad statements that relate, to protection of the environment, provision of ade-
quate supplies of energy, protection of the general public health, safety, and
welfare, conformance with existing land use and/or energy plans, and,other
factors (NY,OH). Specific site suitability criteria involve a detailed analysis
of the physical capabilities of the resources affected, the specific resource
requirements of the types of facilities under consideration, and the probable
environmental impacts of those facilities. These criteria can be translated
into geographic areas within the state which represent varying degrees of
suitability for energy facilities. The state could thus maintain an inventory
of suitable sites by which to evaluate future siting proposals (MD, MN).
Implications. Site suitability criteria designated by the statewould

insure consideration of factors in the evaluation of alternative sites that

are of statewide concern. If the criteria were structured to incorporate
factors representing the broad spectrum of environmental protection and
natural resources management policies, the site review process could be stream-
lined and the relationship between these various policies and the resultant
trade-offs could be identified and evaluated. The success of this approach
depends largely on either a unified statewide land use policy, or an integrated,
comprehensive set of policies which together represent an overall statewide
policy.

410,

The use of general criteria provides for consideration of general
concerns about the environment, future energy-needs, and other factors. It
permits considerable flexibility,in the means by which the criteria are satis-
fied. However, past experience indicates that other state and federal laws
that have taken this approach have been subject to a wide variety of interpre-
tations in the early stages of applying such criteria, and a great deal of
uncertainty often exists as, to what is required to satisfy these general cri-

teria.

Through the application of specific site suitability criteria, it is
possible to incorporate specific elements of existing state land use and energy
development policy into the energy facility siting process. Such elements
include air and water quality standards, soil erosion and sedimentation con-
trol criteria, solid waste disposal standards, radiological standards, and other
factors. It is also possible to incorporate other state policies and program
elements such as areas determined to be of critical stae envi ronmental concern,
areas in.which economic development is encouraged, natural hazard areas, and so

forth.

Establishment of energy facility site suitability criteria would prob-
ably be achieved through promulgation of rules and regulations by the lead

state siting agency, such as a public utility commission, a department of
natural resources, a siting council, or some other agency.

b. Separate Site Suitability Criteria for Different Types of Energy
Facilties

Separate criteria could be developed for each type of energy facility,
such as petroleum refineries, nuclear power plants, coal power plants, etc. It
would also be possible to establish criteria for different size facilities.
Under. this approach, proposed energy facilities could be grouped in generic
categories and evaluated under separate site suitability criteria. Another
approach would be to conduct a statewide inventory of sites that would be suit-
able for these generically different types. Technical analyses would be con-
ducted for the various types of energy facilities of concern to the state and
specific resource requirements could be determined. The physical capabilities
of air, land, and water resources to support these generic types could also be
ascertained.

Implications. This option could streamline the energy facility siting

411

'proc ess considerably. Similar siting proposals could be evaluated more effi-
ciently, since past experience would identify those factors that are likely to
warrant special consideration and those that are routinely similar. In order to
implement this option a considerable amount of research and planning would be
required. This may involve extensive monitoring of existing energy facilities
(MD).

c. Detailed Siting Criteria for the Coastal Zone
This option would involve the application of detailed criteriato pro-
posed energy facility sitings in the coastal zone of a particular state. This
option presumes that the.state had not established siting criteria for non-
coastal areas. These criteria could be based on a detailed re6ource inventory
of the.state's coastal zone and could indicate suitability of various land and
water uses in the coastal zone through consideration of areas of particular con-
cern, permissible uses,- priority uses, etc. In addition, coastal zone siting
criteria could include factors such )as environmental opportunities or con-
straints determined by applicable air and water standards and other factors

related to physical capability.
Implications. This option could foster the achievement of policies for
energy facility siting in the coastal zone in states where regulation of energy

facilities is limited. Because the institutional framework for coastal zone

management has bee n developed to a higher degree than that for non-coastal areas
in several states, it may be easier to approach the,energy facility siting prob-
lein by working within the existing CZM planning framework. However, separate

and,distinct treatment of energy facility-siting in the coastal zone, as opposed
to a broader statewide approach, may result in a lack of balance regarding both
coastal and non-coastal needs and problems. This problem could be partially
eliminated if suitability criteria for energy facility siting in the coastal
zone were developed with full consideration of the remainder of state, regional,
.,and local policies, standards, and criteria relating to land use and energy
development. In order to implement this option, enforcement provisions1would
have to be established to insure adequate consideration of these coastal-
specific criteria in the siting process. This could be achieved by placing
authority within the lead CZM agency, by establishing a mandatory review and
comment process, or by formal or informal interagency agreements.

412

d. Point of Application of Suitability Criteria

(1) Application of Suitability Criteria to Long Range Plans and
Forecasts

This option involves the application of site suitability criteria to the
prospective energy facility sites identified in long range plans and forecasts.
Two states (MD, MN) have taken this approach in the regulation of electric gener-
ating plants. This option would involve evaluation of the land holdings of the
various'energy companies or of sites,under consideration for acquisition. It
would facilitate the development of an inventory of suitable sites within the
state. Determination that a site was unsuitable could serve as grounds.for

elimination of that site from further consideration.
Implications. The application of suitability criteria at the long range
planning stage would have many desirable implications.. For example, demonstra-
tion by the energy development companies that a proposed site is deemed accept-
able by a set of reasonable yet comprehensive suitability criteria would
increase the likelihood that the site would receive final approval. This
would greatly reduce the uncertainties associated with energy development, and
may well reduce the regulatory lag time that has plagued energy facility-siting
in the past. This would also permit adequate lead time for local and regional
interests to express their views and to adequately plan for the provision of
necessary public services and to manage the resultant environmental impacts.
This option implies some state involvement in development of long range
energy plans and forecasts. It also implies that the appropriate decision-
making body has authority to establish policies and procedures requiringicom-
pliance by the private sector. Presumably, satisfaction.of the suitability cri-
teria would constitute acceptance of a.proposed site, and failure to satisfy the
criteria would imply either outright rejection of the site or acceptance only
-upon satisfaction of certain site development conditions.

(2) Analysis of Site Suitability at Time of Application for
Approval
This option would provide for the evaluation of the suitability of a
specific site at the time of application for site approval. The private sector
would conduct its own preliminary assessment of alternative potential sites and
would choose a preferred alternative. In states where there is no principal
lead agency to administer the existing energy facility siting program,

413

the suitability analysis at the time of application could be handled by the
state coastal zone agency, by the state environmental review board, or by.the
rinciDal envir6nmental protection or natural resources mana
p gement agency. Ade-
quate consideration of regional and local problems and needs could be arrived at
through a variety of organizational structures, review procedures, public involve-
ment mechanisms, and other means.
Implications., Under this option, it would be the prerogative of the
private sector to conduct preliminary site suitability analysis according to its
own criteria. However, the state-designated site suitability criteria to be
applied at the time of application for approval would significantly influence
the preliminary site suitability criteria employed by the private sector, be-
cause pursuit of sites unlikely to satisfy the state-designated suitability cri-
teria may be a poor investment of time and money. If the state criteria were
sufficiently comprehensive and sufficiently flexibleto allow for Variable con-
ditions, these criteria could serve as an effective set of guidelines by which
state utilities and other energy companies could evaluate the suitability of
their prospective future sites., The application of these suitability criteria
implies some sort of state regulatory authority over energy facility site loca-
tions. Such authority would benecessary if this approach is to be effective.

e. Designatioq of Environmental Impact Assessment Criteria for Site
Evaluation

A state may wish to establish criteria for the assessment of the envi-
ronmental effects of siting proposals., Following the lead of the National En-
vironmental Policy Act of 1969 (NEPA), numerous states have taken the initiative
in this area and have developed their own statewide environmental impact review
processes (IN, MI, MN, NY, WI). Other states (NY, OH) have incorporated assess-

ment criteria in their power plant siting regulatory programs. Criteria can
either be very general or quite specific. General impact assessment criteria
are broad statements which permit a great deal of flexibility in their inter-
pretation. Specific criteria often take the form of various categories of in-
formation'required, and often list specific data that must be collected to
supply this information. These criteria can also include information that is
required under the various federal and state permit programs in effect in the,
state, such as those required.under the Clean Water Act (NPDES permit) and the
Clean Air Act (permits to construct and operate), and state programs for

414

soil erosion/sedimentation control, resource recovery, critical area or
resource protection, and other applicable programs. In addition,, assessment,.'
criteria could be developed to reflect -Factors of particular concern to the

coastal zone.

Implications. There are several advantages to stipulating environment-
al impact assessment criteria for proposed energy facilities. Carefully de-
signed criteria can include nearly all of the information and data require-
ments included in the various permit systems, and can thus serve as a mechanism
by which to streamline the approval process. Also, criteria that are clearly
stated and well understood can serve as a solid foundation for adequate con-
sideration of those areas of greatest concern in coastal and inland locations.
This would also reduce uncertainty in the private sector about the kinds of in-
formation that would ultimately be required in the siting process. Once a par-
ticular set of impact assessment criteria has been applied to various .proposed

site locations, a correlation would be established between various kinds of

energy facilities and the probable environmental impacts.

7. FINANCIAL MECHANISMS

It is generally agreed that financial problems are among the most severe
of problems currently facing energy development. These problems have arisen
from uncertainties about governmental policies and from difficulties in capital
formation)in the private sector. If implemented, many of the options outlined
above could streamline the regulatory process and thereby reduce uncertainties
and resultant financial risks. For a number of'reasons, the states may wish to
employ various financial mechanisms to facilitate the wise development of
energy. In addition to directly encouraging or discouraging the siting of new
facilities, financial techniques can be employed to promote energy conservation
and thereby reduce the need for new facilities, insure an adequate mix of fuels,
encourage the application of new technologies, and ameliorate the adverse ef-
fects of facility sitings. Options associated with these mechanisms canbe
categorized under three headings: 1) methods of generating financial resources,
2) direct public investment in energy development, and 3) incentives for energy

development by the private sector.

a. Methods of Generating Financial Resources
Several options are open with regard to obtaining revenues for the

415

administration of various aspects of energy facility programs. The following
list of such methods is presented to stimulate additional thinking in this
area and is not intended to be exhaustive.

(1) Appropriations from General State Revenues
(2) Issuance of Industrial Revenue Bonds
(3) Consumption Tax on Fuels and/or Energy Forms
(4) Tax on Goods that are Less Energy Efficient than other Goods
of the Same Type Due to Design or Construction
(5) Tax on Energy-intensive Goods
(6) Charges for Operating Source of Pollution
(7) Federal Assistance from a Potentially Wide Variety of Sources
(8) Fees for Site Applications and Long Range Plans and Forecasts.

Implications. Numerous scenarios can be developed which incorporate
one or more of these options with other institutional options outlined in this
report. The implications of employing one or more of these revenue sources will
depend on the details involved. No attempt will be made to elaborate on these
implications.

b. Direct Public Investment

(1) Direct Siting of Facilities and Production of Energy (Electric
Power) by the State
This option and its implications were discussed above under Section 2,
Siting Policy. In particular see Section 2.f., State Power Authority.

(2) Joint State Provate Sector Corporations
this option would entail the joint financial underwriting of new energy
facilities,by both the public and private sectors. This would probably be most
feasible for the electric and gas industries. Public and private sector siting
considerations and investment criteria would be combined to determine siting de-

cisions.
Imp.lications. Under this option, state government would be required to
work closely with one or more of the var ious sectors of the energy industry to
jointly finance new facility sitings. It is not inconceivable that such an
arrangement may require extensive negotiations involving two sectors of society
that are often-diametrically opposed. Details of other phases of the siting

416.

process, including long range planning, site selection, and site certification,
would have to be clearly defined so that a high degree of visibility could be
achieved in this potentially controversial arrangement.
This option has the potential for providing the best features of both
public and private sector involvement in energy facility siting. The state may
be more able to provide a stable source of financial resources for facility
development [4571. It can also provide adequate insurance, through the demo-
cratic process, that public financial resources willbe invested in projects
that reasonably satisfy objectives for economic development, equitable distri-
bution of resources, and environmental quality.

(3) State Financing of Energy Facility Development by the Private
Energy Corporations
This option would involve state'financial assistance to the energy cor-
porations. Options for raising the necessary capital were presented in the pre-
vious section. The probable means of financing would be state loans or loan

guarantees.
Implications. This option would require legislative authority to invest
public resources in quasi-public (electric and gas utilities) or private (fuel
production) energy companies. It is likely that the state would require that
certain conditions or criteria be met by the private sector, although these

would not be as extensive as those encountered with a more direct state involve-

ment.

C. Incentives for Energy Development by the Private Sector
Options under this heading imply a lower degree of economic risk in
ventures undertaken and probably.a slower market response to the stimuli.

(1) Positive Financial Incentives for Siting

(a) Tax incentives

Tax incentives can be used in a number of ways to encourage energy fa-
cility siting. Investment tax credits could be employed to stimulate the
development of associated facilities. Accelerated depreciation allowances
might also be used to achieve these ends.. In addition, deferred taxation may
be applied to minimize immediate siting costs. The state may also wish to pro-
vide credits against state income tax for local property taxes paid by energy

417

facilities.

Implications. Tax incentives must be justified as an appropriate solu-
tion to a well-defined problem (private market imperfections in the energy in--
dustry) They have been employed at the federal levels (oil depletion allow-
ance) and they tend to come under close public scrutiny. Tax incentives would
have to be designed to avoid undesirable redistributions.of income.
Tax incentives are related to the facility rather than to the site.
Since facility development, operation and maintenance costs are very large'com-
pared to site acquisition costs, incentives to limit the former may be quite
effective in stimulating new energy facilities.

(b) Financial incentives for site@location

This option builds on.the concept of the previous option. It may be
desirable to provide strong positive financial incentives to site energy facili-
ties at predetermined locations or at(sites that are.otherwise deemed suitable.
This could be achieved by providing the'tax incentives of th e previous option
for predetermined sites or for sites that meet state-designated suitability

criteria. Such incentives would not be available for other sites.
A variation on this option would entail state acquisition of suitable
sites with the sites subsequently being sold to energy corporations at either a
token price or at 'a somewhat reduced price., The previous option could then be
tied into the arrangement.
Implications. The legality of this option would have to be determined.
In order to be acceptable, the use of this option would probably have to be
based on well-defined long range plans for energy development and economic
growth. Steps would have to be taken to insure equitable distribution of the

related costs and benefits.

(2) Negative Financial Incentives for Siting
Options under this heading would be characterized by fees, penalties, or
other charges to discourage the siting of energy facilities in certain area .s or
to provide a source of revenue to ameliorate the adverse effects of'locating a
.site in those areas. This option could be used to discourage siting in coastal
areas that are deemed unsuitable for energy facilities. Negative financial in-
centives could be graduated to reflect the relative desirability of siting in

418

various coastal or inland areas.

Implications. The employment of negative financial incentives implies a
reactive approach to siting regulation. This option, along with other options
that provide financial incentives or disincentives, should be based on a ra-
tional plan for energy-development in the state. Since these options tend to
create-spillovers into other sectors of the local or regional economy, the
probable implications would have to be fully assessed.

8. INTERGOVERNMENTAL RELATIONS

a. S@ate-Federal Relations

The federal role in energy facility siting outlined in Section III.B.
indicates that there are several aspects of siting that involve federal agencies.
Section 307 of the Coastal Zone Management Act (CZMA) requires that federal
actions be consistent with"approved state CZM plans. The Act also requires that
states consider the national interest in the development of CZM plans and pro-
grams. Greater coordination between the states and the federal government in
energy policy and in the.siting of energy facilities will promote economically
efficient, publicly acceptable and environmentally sound energy development.
The options described below suggest alternative mechanisms by which the Great
Lakes states might interact with the federal government to achieve thes e objec-
tives and implement the portions of the Act requiring consistency.

(1) Coordination and Consolidation of Siting Procedures
A variety of options exist under this general heading. These options
are associated with the'phases of energy facility siting regulation that are
typically encountered in state siting programs. The approaches taken by a par-
ticular state would depend on the siting procedures currently employed or on
those that may be selected by the state from the institutional options outlined

above.

(a) Long range planning
To align the long range plans and forecasts for energy development of
the federal and state governments, the states may atte mpt to incorporate federal
agencies concerned with long range energy planning (e.g., ERDA., NRC, FEA, and
the FPC) into the long range planning process employed by the state. This

419

could be achieved by requesting extensive review and-comment by these agencies
on state plans, by requesting that these agencies attend public hearings and ad-
ministrative meetings held by' the ;tate on long range plans and forecasts, and
by seeking clarification of federal policy in various substantive areas address-
ed in the state energy planning process.
Implications. This option implies that the state.has some involvement
in long range energy planning. It may facilitate the identification of those
aspects of state and federal energy facility siting policy that are likely to
generate controversy and thus require special atte@tion. Resolution of these
issues early"in the process will streamline siting regulation by reducing
delays.

(b) Involve federal agencies in the state site certification
process
This option would provide for direct involvement of the appropriate fed-
eral agencies in the site review and evaluation process. Representatives of
these agencies would participate in the internal review process by acting as
resident liaisons between their respective agencies and the state siting bu-
reaucracy and CZM agency. For.example, representatives of the U.S. Environ-
mental Protection Agency could interpret applicable air and water quality'stan-
as they relate to the specific siting proposal under consideration in the
state application process. The FPC could evaluate the proposal (for an electric
generation facility) in terms of the degree to which it increases the'-reliabili-
ty of electricity production and meets well-defined energy demands. Other fed-
eral agencies could be incorporated in the process as warranted by the types of
energy facilities and locations involved.
At the same time, federal agencies could take this opportunity'to obtain
.state approval for federal actions affecting the coastal zone as required under
the consistency provisions of the CZMA. Permits issued by the Corps of Engi-
neers for structures in navigable waters or by the EPA for pollutant discharges
could bediscussed and a determination made with regard to joint state and fed-
.eral approval.
Implications. Increased participation of the federal. government in the
state energy facility site certification process would have to be handled very
carefully to avoid charges of federal encroachment in state siting-matters.' The
important point with regard to this option is that the states as well as the

420

federal government could benefit from increased communication and cooperation in
the certification of energy facility sites. This option would provide for enun-
ciation in, the siting decision process of the specific aspects of f ederal policy,
such as site evaluation or site suitability criteria, and air, land, and water
pollution control standards, which must be complied-with, or which reflect those
interests and concerns of society that are represented by the federal govern-
ment. Importantly, the Coastal Zone Management Act requires consideration of
,the national interest in the siting of facilities that are of greater than.local
significance. Also, by bringing the.fe deral agencies into the certification
process, and by encouraging p ublic participation, the states could facilitate
the resolution of policyconflicts with the federal government.

..(2) Consolidation of, State and-Federal,Environmental Impact Assess-
ment Processes

Federdl agency environmental assessments under NEPA, and state environ-
mental assessments required under a statewide program or under the state's
energy facility siting regulatory program would be consolidated under this
option. This could involve combined assessment criteria, uniform time limits,
coordinatedreview procedures, and jointpublic hearings..'This option could be
applied to environmental impact assessments of prospective sites outlined in.
long range plans or of sites for which application for final approval has been

made.

These combined assessments could be performed by the lead state siting
agency,.or. by a consultant, or the individiualagencies could contribute their
respectiv&,.inputs to be compiled, possibly by,the state.
Implications. This option would eliminate much of the duplicated effort
that currently Pxists in the regulation of energy facilities. A s ignificant
savings of public resources might result. This option.may also reduce the over-
all time required to evaluate proposed sites. Each interested party could.re-
view the resultant impact statement with its own particular interests in mind.
Impac-t assessment guidelines should be developed toinsure that all significant
impacts are addressed in the analysis..

b.. -02tions for Interstate Relations
Many of the problems and needs related to energy facility siting can be
handled either on an intrastate basis or through establishment of appropriate

421

state-federal relations. However, several siting issues will probably not be
adequat' ely addressed by these institutional mechanisms.@ It is with regard to
these issues that a sound case.for an interstate regional approach to siting
regulation can be made.

(1) Establishment of Multi-State Regional Siting Council
This option would entail the formation of an organization by two or more
states to deal with siting-related problems and needs that are not confined to
onestate. This organization could take a variety of forms. Membership would
depend on the functions and authority assigned.
Contiguous Great Lake states may wish to employ such an organization
comprised of CZM program administrators to coordinate energy facility siting in
the coastal zone. The influence of a regional CZM siting council would depend
not only on the authority of the council itself but on that of the CZM programs
within the respective states. Another approach to an interstate regional
siting-council would be to.include as members the heads of the lead state
energy facility siting regulation agencies. This would involve CZM considera-
tions as part of the broader set of statewidesiting considerations.
If the principal function of the regional siting council were to assess
the impacts of proposed sitings, the council might be structured to include
heads of natural resource departments and/or environmental protection agencies,
or representatives from state-level environmental review boards of citizen-
advisory committees.
It would also be possibl6to establish a skeletal framework for a re-
gional siting council and activate it on an ad hoc basis as the need arose.
Implications. There are several advantages associated with this option.
An interstate organization would provide a.mechanism for the resolution of
energy facility siting-related conflicts between states. It would also provide
a single forum for interacting with federal energy-related agencies, and would
strengthen the position of the states vis a' vis the federal government. With
regard to' electric power generation, the private sector, through federal en-
couragement, has already recognized the need for such cooperation by establish-
ing regional reliability councils to coordinate interstate electric power flows.
Implementation of this option would require some form of agreement be-
tween the states, such as parallel state legislation, memoranda of agreement or
other mechanisms to bring the states together.

422

(2) Establish an Interstate Regional Siting Approval Process
This option would entail joint approval of certain kinds of energy
facilities by the states involved. This process could be limited to those pro-
posed sitings that would.have-significant, direct impacts on the environments
of two or more states, or that will substantially alter the future availability
of energy in.two or more states. For example, the siting of, say, a large
nuclear or coal-fired electric generation plant in a state's coastal zone may
have significant direct impacts on coastal or other areas of one or more nearby
states, and it may materially influence future growth patterns in those.states

as well.

Implications. This option would necessitate a formal mechanism for
agreement between two or more states. This implies either approval by a formal
interstate siting council or the separate approval by the agency or agencies
that have, regulatory authority for siting in the states involved. In addition,
approval by the federal sector (depending on the location and type of facility)
would also be required, as would approval by other levels of organization within
a particular state.
The effectiveness of this option would be maximized if the individual
siting regulation programs of the states involved were well defined and well
coordinated with other environmental and land use policies and programs in those
states. Public acceptance of this option would be critical to its.success.
This option also implies that the states participating in regional site certifi-,
cation are capable of and willing to adopt specific policies regarding si.ting-
related issues to guide their actions in joint siting decisions. This option
may act as a catalyst in forcing the states to delineate thqse policies.

(3) Institute an Interstate Regional Process.for Predesignation of
Suitable Sites

This option is an extension of one described earlier. It would involve
the aggregation of sites deemed suitable by each state into an overall set of
suitable sites in the Great Lakes Basin or some sub-region thereof. It could
involve the entire area or only the coastal zone of each state.
Implications. Through this approach the states could strengthen their
bargaining positions with other levels of organization in the overall siting
process. Also, this option fosters an active rather than reactive approach to
siting regulation by identifying suitable sites, thereby indicating areas where

423

energy development could generally be favorably received. Identification and
predesignation of suitable energy Jacility sites implies the application of
some criteria by which to judge sitesuitability. The relationships between the
suitable sites of adjacent states would have to be determined to avoid conflicts
and to reasonably meet each statel.s goals and objectives for energy development,
economic growth, and environmental quality.
This option implies that the appropriate organizations and legal.author-
ities exist in'various states to pursue a multi-state regional approach to
energy facility siting. To be most effective, this approach requires active
state participation in the preparation of long range energy resource and facil-
ity plans and demand forecasts. An ongoing, multi-state, long range energy
planning process would increase the rationality of siting and would largely
determine the site suitability criteria and the priorities for siting new
facilities with a particular state. This option would be strengthened if the
states chose to acquire certain interests in sites and to encourage develop-
ment on those sites through a promotional campaign.

424

C. TECHNICAL OPTIONS

1. FRAMEWORK

The technical options related to energy facility siting and development
with regard to the coastal zone have been arranged to provide a full range of
policy choices consistent with the Coastal Zone Management Act of 1972. The
three major groups of options have been categorized as. they relate to jurisdic-
tional decisions. They are:
Exclusion of all new facility development from the coastal zone
management area, including access to coastal waters and related fuel transshipment.
9 Exclusion of all new facility development from the coastal zone manage-

ment area, but allowing coastal water access, related fuel transportation, and

product transmission through the coastal zone.
e Inclusion of new facility development in the coastal zone management
area, except in designated sensitive areas in which additional development would
be precluded.
The coastal zone management area is defined as that area the Great Lakes
states will designate as the coastal zone subject to their management program.
The definition of coastal zone used by Coastal Zone Management Act of 1972,
P.L. 92-583, is as follows:
Coastal -zone means thecoastal waters (including the1ands therein
and thereunder) and the adjacent shorelands (including the lands
therein and thereunder), strongly-influenced by each other and in
proximity to the shorelines of the several coastal states, and
includes transitional and intertidal areas, salt marshes, wetlands,
and beaches. The zone extends, in Great Lakes waters, to the inter-
national boundary,between the United States and Canada and, in other,
areas, seaward to the outer limits of the United States territorial
sea. The zone extends inland from the shorelines only to the extent
necessary to control shorelands, the uses of which have a direct and
significant impact on the coastal waters. Excluded from the coastal
zone are lands the use of which is by law subject solely to the
discretion of or which is held in trust by the Federal Government,
its officers or agents (Sec. 304(a)). [5821
"Coastal'waters" means (1) in the Great Lakes area, the waters
within the territorial jurisdiction of the United States consisting
of the Great Lakes, their connecting waters, harbors, roadsteads,
and estuary-type areas such as bays, shallows, and marshes; and
'(2) in other areas, those waters, adjacent to the shorelines, which
contain a measurable quantity or percentage of sea water,including
but not limited to sounds, bays, lagoons, bayous, ponds, and
estuaries (Sec. j04(b)) [582).

425

Assumptions included in this discussion of technical policy options are:
* All present and anticipated environmental quality standards and
controls will be aminimum requirement.
e Guidelines of the Coastal Zone Management Act as presently stated will
be followed in the development of the state CZM programs.
It is intended that the following policy options provide a wide range of
considerations but at the same time avoid any preference or bias toward either
the conservational or developmental viewpoint regarding the future of the coastal

zone.

2. DESCRIPTION OF OPTIONS

a. Exclusion of All New Facility Development from the Coastal Zone
Management Area Including Access to Coastal Waters and Related Fuel
Transshipment
New facility development in the coastal zone as well as all conveyance of
fuel or coastal waters.through the managementlarea are excluded by this option.
The aim of this option is to substantially reduce the impacts characteristic of
energy facilities located in the coastal zone. Exclusion of all new facility
development is visualized as aesthetically and environmentally beneficial. This
option presumes a conservative attitude towards the development of coastal

resources and considers energy facilities to be incompatible with conservation-
oriented planning objectives in the coastal zone.
In the discussion of this option, the implications developed will focus
on many of the technical, environmental, and economic impacts associated with a
policy of facility exclusions.
Although the policy of exclusion may be the least viable of the three
general options presented, this option is included to present a full range of
options for the siting of,energy facilities. Complete exclusion of new facility
d;velopment from the coastal zone may not.- in fact, serve the intent of the
Coastal Zone.Management Act to include the siting of facilities of national or
regional concern.
The Coastal Zone Management Act specifies that adequate consideration be
given to the siting of facilities that serve the requirements of the national
interest. Such characterization of energy facility siting may preclude an arbitrary
exclusion of development within or through the coastal management area. This
option is therefore presented to illustrate the range of coastal implications

426

associated with inland siting and is not designed to portray a prescriptive
policy concerning energy.
Implications. The primary intent of this option concerns the preservaI7
tion of the environmental, aesthetic, and recreational uniqueness of the coastal
resources of the Great Lakes. The exclusion of new facility development from
the coastal zone would permit sizable tracts of shoreline which would otherwise
be used for energy facilities to remain in existing uses or be used for purposes
of ostensibly less detrimental environmental impact. One would assume that a
reasonable adjunct to this stringent policy framework would be an exclusion of
simila r large scale facilities, e.g., steel plants, from the coastal zone.
Depending on the viewpoint, implementation of a policy excluding major industrial
uses from the management area would either greatly enhance the flexibility of
coastal.resource planning or impose rigid, restrictive, and inflexible management
of the area. Certainly, land no longer required for energy facilities or their
associated access rights-of-way for coastal waters or fuels would be available
for a wide range of uses. Public access to the coast could directly benefit,
increasing the recreational and aesthetic,value of the coastal zone. The natural

characteristics of shoreline and near-shore areas not heavily used for recreation
would be preserved by this option..
The development of smaller scale, less resource-intensive, commercial
activities might serve to offset the economic liabilities in the management area.
Small scale activities like light industry may benefit particularly in develop-
ment at sites once used for energy production. Land around decommissioned fossil-
fuel energy-facilities could be redeveloped for other purposes. However,
redevelopment of a portion of a retired nuclear facility directly adjacent to the
reactor vessel would be generally infeasible due to radioactive contamination of

the site.

Complete exclusion of new energy facility development in the management
area would reduce the continuation of such long-term environmental impacts in the
coastal zone. This option would also largely eliminate the milieu of short-term
and operating impacts associated with the development of additional energy

facilities in the coastal zone.

The movement of,fuels would depend heavily.on inland modes of transporta-
tion. The exclusion of access through the coastal zone fortransportation of
fuels would have a direct and significant economic impact on the future of

427

commercial lake navigation. The land and inland waterway transportation modes,

train, pipeline, truck or barge, would assume the balance of additional fuel
movement. The resulting reduction of cost-efficient Great Lakes vessel transpor-
tation and the increased use of inland modes would generally raise the delivered
price of fuels.

A technical spinoff of the decrease,in lake transportation of fuels could
be an increased utilization of coal scrubbers. The availabili ty of low sulfur
coal from the western states has been abetted by the low-cost transportation rates

via dry bulk vessel on the Great Lakes. The denial of future western coal trans-
shipment from lake vessel to new facilities would shift the movement of this coal
to other carriers. The resultant transportation costs may encourage utilities to
.revert to eastern and Appalachian sources and install sulfur scrubbing systems.
A-sulfur scrubbing system would then increase the acreage required for solid
waste disposal. It is estimated that the use of sulfur scrubbers necessitates
a 100 to 200 percent increase in land available for solid waste disposali The
expense of this additional land acquisition may be partially offset by the
generally lower costs and increased availability of larger tracts of land inland
than are commonly prevalent in the coastal zone. Moreover, the competition for
land use is regarded as less intense inland than on the coast.
The benefits in lower land acquisition costs are largely counterbalanced

with the economies of inland water utilization. The use of inland water resources
would in most cases require installation of complex cooling systems (mechanical
or natural.draft, spray ponds, canals, etc.). which in comparison to once-through
cooling demand a higher level of maintenance and operation investment. The
exclusion of access to coastal waters 'for cooling purposes would place enormous
-pressure on the inland water resources. It i s questionable whether these
resources could fully accommodate the increase in water demand. In,some*instances,
this would require use of currently expensive technologies (e.g., dry cooling
towers) and may result in installation of uneconomically sized units and/or the use
of other types of technology for generating electric power which may not presently
be fully developed.

The policy of facility and access exclusion might also, over time, shift
the existing pattern of power flow. The prevalent coastal power load might
gradually shift inland as facilities on the coast were decommissioned, although
some older urban sites would be redeveloped with energy facilities which might
even use clean fuels. Depending on site location this trend may involve extensive

428

construction of high voltage lines to transmit electricity back to the coastal
load centers. Overall, the implications would entail a general reorientation of
transmission systems.
Many of the technical drawbacks,that have surfaced within the facility
exclusion option would probably encourage research in and development of alterna-
tive energy sources less dependent on water. Closed-cycle cooling systems would
be an obvious component in inland siting. Perhaps other systems fueled by renew-
able sources (e.g., solar, wind) might evolve under the constraints of non-coastal
siting.
The attempt throughout development of.thi@s policy option has been to
stress the major implications that a program of energy facility and coastal access
exclusion would involve. The orientation of such an approach is the future
preservation of the unique resources of the coastal zone. While the approach in
totality may be extreme and possibly would not comply.with the provisions of the
Coastal Zone Management Act, certain aspects of this option may-be adapted within
the CZM programs. The presentation of this option of total exclusion represents
an effort to consider the full range of policy choices for the CZM programs.

b. Exclusion of All New Facility Development from the Coastal Zone
Management Area, but AllowinR Coastal Water Access, Related
Fuel Transportation, and Product Transmission through the Coastal
Zone

This general option excludes the major negative environmental impacts
associated with energy facilities-in the coastal zone, whileallowing access to
the most coastal-dependent features such as cooling water and fuel delivery, and
providing corridors for transmission of.products such as electricity and oil back

into the coastal zone.

In the following discussions of each option and, its implications,
references,will be made to various types of access corridors and rights-of-way.
These would include utility corridors and rights-of-way for transmission lines,
cooling waterpipelines, and for fuel.and product conveyance, including coal and
oil transport by pipeline, conveyor,.barge, or rail. It is assumed that any
necessary acquisition of corridors or rights-of-use would be accomplished through
a fee simple purchase or a granting of easement where feasible.
It is felt that the above general option is viable under the guidelines
of the Coastal Zone Management Act because the exclusion of facilities from the
coastal zone is neither complete nor arbitrary in view of the limited coastal

429

resources under consideration.: Furthermore, exclusion of these resources-from
facility development would allow flexibility of planning by state CZM programs
for potential uses of higher priority.

(1) Limit Expansion or Conveyance of Construction of'Coniveyance
Systems to Existing Corridors and-Rights-of-Way
ILn2lications. Where feasible, this option would.limit expansion of.
conveyance and development of conveyance systems to those corridors,presently
owned and developed for such uses, such as railroads, transmission lines, and
pipelines.

The primary intent and implication of this option would be to limit
further commitment of coastal land resourcesto development of new,access routes,
while at the same time concentrating those environmental impacts associated with
access routes (such as the above ground aesthe;tic intrusions and effects on.
adjacent property Values and uses) along presently developed corridors..,
Restriction of future development to existing corridors would have.an
effect on conveyance capacity as well. In those cases where present capacity-of
pipeline, rail, transmission line, or barge conveyance is not being fully .
utilized, expansion of conveyance could conceivably take place without.construc-
tion. In-those cases where existing conveyances-are at full capacity, it might
be possible to construct higher capacity systems on the same corridors. Finally,
in those areas where existing corridors could support no-further expansion, in
capacity, a necessary limitation on transportation and transmission capabilities
would result from this option.
If this option were implemented, it is possible that-inland siting of
energy facilities would be limited to those areas closest to@the existing-
conveyance corridors, depending, of course, on the relative transportation costs
outside the coastal zone. Concentrated conveyance use along existing corridors
could result in an overall decrease of operation and maintenance costs, especially
in cases where existing capacity can.be utilized without:new construction. In.the
case of below@ground transmission lines'and pipelines, concentration of such
facilities may involve strict control of above-ground land uses to provide for
adequate access and maintenance. This latter-possibility may involve fewer

aesthetic or economic effects.

430

(2) Avoid Areas.of Particular Concern in Determination of Access
Routes and Rights-of-Way
Implications. Areas of particular concern would include those areas
designated by the state CZM programs according to the guidelines of the CZM
regulations. Examples are areas of unique habitats, high natural productivity,
substantial recreational value, significant hazard, etc. The implication of such

an option would be to encourage preservation of and restrict use of such areas
by siting access routes and conveyance corridors elsewhere or in such a way as to
avoid them. In cases where the state would designate so many areas of particular
concern that access through the coastal zone would be difficult, a limitation on
conveyance ca pacity would result.

(3) Disperse New Access Routes and Corridors
Implications. A dispersal of access routes and conveyance corridors
wou Id presumably result in a corresponding dispersal of the environmental and
economic costs and benefits associated with the specific conveyance. For
instance, aesthetic impacts such as noise generated by rail traffic might be
ldssened due to dispersal of tracks. Likewise, economic benefits and costs
derived from construction and maintenance of dispersed conveyances would,be
spread out over a larger area.
Increases in land requirements due to dispersal within the coastal zone
would increase acquisition costs and at the same time remove land from other or

previous uses. Additionally, inland facility siting would tend to be dispersed,
corresponding to the water and fuel access dispersal.

(4) Concentrate Access Routes and Corridors

Implications. This option takes the opposite tack from the previous

option, but the implications fall into the same categories. *Also, this option
differs from option (1) by permitting new access and corridors in addition to
existing access and corridors. Concentration of access routes and corridors would
result in a corresponding concentration of environmental/economic impacts in
specified areas. This in turn would confine impacts to the specified areas,
while not further affecting other areas. In addition, economic benefits and costs

associated with construction of new access facilities would be concentrated. .
The less even distribution of new access facilities along the coastal zone would
permit the use of other lands for other existing or future uses. In conjunction

431

with this, concentration of access routes, a corresponding clustering of energy
facilities inland might possibly result.
Land requirements related tS this option would be greater than in the
case of restricting new development to existing corridors, but less than in the
previous option of dispersal. Costs of.land acquisition would also in crease.
Finally, it is possible that the implementation of this option would have the
overall effect of limiting transmission and transportation capabilities in the
event that cost feasibility could no longer be justified.

(5) Specify Development Areas
Implications. This option would allow the-state CZM programs or other
state agencies to designate those areas which could be develop@_-d for access routes
and conveyance corridors, thus facilitating long-range coastal zone planning.
This option would blend well with option (2-),,' which suggests determination of
-areas of particular concern, thus identifying those corridors which could be
developed for access or conveyance with least negative impact on the remaining
coastal zone. Additionally, the review and permitting process might be completed
more rapidly, as these specified.areas would be more acceptable to the.reviewing
agency, and therefore reduce in advance possible disagreement over the selected

site.

This option would shift the responsibility of corridor site selection
from the utilities to the planning agencies and potentially present problems.to
the utilities in terms of their long-range expansion plans. Given the go-ahead
to develop along specified.areas, the net result might be a concentration of
facilities and their associated impacts. This should be foreseen and planned for
in the initial specification of development areas.

6) Develop Buffer Control Areas
Buffer control areas here refer to zones bordering-either side of an
access route or conveyance corridor that would reduce or contain the Ivisual and/or
auditory impacts of facilities such as railroads, transmission lines, conveyor
.belts, or above-ground pipelines. This buffering effect might be accomplished
by raised, landscaped mounds or.simply by retention of a natural green belt
during development.
Implications. The reduction of visual and auditory impacts accomplished
by the buffer zones would be offset to a certain degree by the increased cos'ts

432

to the developer (utility or railroad) of additional land requirement and land-
scaping costs. This ratio of benefits and costs would be of a site-specific
nature. Such a buffer zone might have a positive effect on adjacent land values

and uses.

This option would effectively limit some uses of the land alongside the

corridor such as industrial development or perhaps agriculture, but at the same
time might provide increased public recreational areas where safety would allow.

(7) Develop Multiple-Use Corridors and Rights-cf-Way
In the development of new access routes or corridors, or in the expanded
use of existing ones, provisions for multiple uses of the land could be stressed
or required. This would be restricted to those uses that would benefit from
long continuous stretches of access such as would be expected along rail lines,
transmission corridors, or pipeline paths. Such uses might include recreation,
such as hiking, or bicycle routes, or multiple facility uses such as combining
transmission lines with pipeline paths or rail routes.
Implications. The intent and implication of such an-*option would be to
increase the number of uses in a previously single-use facility route or corridor.

This in turn would reduce demand on other coastal lands. Total land costs would

be reduced for multiple users of rights-of-way, though construction and main-
tenance costs might increase in the case of recreation development along rights-
of-way. In the case of multiple conveyance use of rights-of-way, a combination
of conveyances could possibly significantly increase the visual or noise impacts
to the point of offsetting those benefits gained from multiple use. Finally,
increased safety hazards resulting from increased public use of conveyance
corridors would require appropriate safeguards.

(8) Establish Limit on Resource Utilization
Within this report, figures have been developed for the various resource
requirements of different energy facility types. This option would specify the
amount of land or water that might be used by energy facilities and thus limit
the development or use of access routes or corridors through the coastal zone as
determined by utility/CZM joint planning. This would probably require some form
of legislation, regulations, or standards to facilitate implementation.
Implications. This option would encourage conservation of land resources
in the coastal zone and prqmote land use that will be of higher priority as future

433

demand increases. By limiting the amount of land available for development of
access routes and corridors, inland facility development would necessarily be
controlled by capacity limitations of access routes or might be displaced to

other coastal zone locations.

Limitations on water resource utilization would be intended to preserve
coastal water quality and quantity for future use and development, as well as for
futuredevelopment of the shoreline. A limit on water availability for cooling
and other uses would result in reducti on or.displacement of water consumption and
have impacts on water quality. It would likely encourage development of technolo-
gies which use less water or return higher quality water to the environment.
This, in turn, could increase the cost of using water.

(9) Provide Financial Assistance to Affected Areas for Impact
Assessment and Amelioration

(a) Impactassessment
'Implications. The intent of this option is to direct monies collected
from the utilities or facility owners, or provided by the state or federal govern-
ment, to the areas affected by proposed facilities for impact assessment. This
would ostensibly improve initial assessment andaid identification of potential
impacts early in the facilities planning stage by aiding local planning efforts.
Additionally, this option would increase public involvement in both the planning
and decision-making process.
In providing for local input to impact assessment, this might also result
in an overall increase in time taken to reach decisions. Also, regardless of who
provides the monies, planning costs will increase. Finally, the increase in
money for local planning efforts would provide for added employment in the impact
assessment field, e.g., consultants or planners.

(b) Impact amelioration
Implications. Provision of monies for amelioration of impacts associated
with energy facilities access routes would increase costs but also increase local
benefits as a result of potential upgrading of environment in the vicinity of the
facility in question. It would also obviate negative impacts,of access route
development.

434

(10) Use Technologies Requiring Least Land Area for Access Rights-
of-Way
Implications. It is intended that this.requirement would result in
preservation of coastal land for future higher priority use and development.
This option would encourage both the use of existing technologies and development
of new technologies that would require less land. Development costs might increase
but land costs would decrease. Examples of such technologies might be coal slurry
pipelines replacing short ha ul rail routes, or narrower or underground transmis-

sion line requirements.

c. Inclusion of New Facility Development in the Coastal Zone Management
Area, Except in Designated Sensitive Areas in Which Additional
Development Would be Precluded
This set of options is designed to address the present status of energy
facility siting, which places no geographical or locational restrictions on siting
in the coastal zone., except in designated sensitive areas. These options are
intended to maintain the present policy of siting in the coastal zone management
area but suggest possible limiting or restrictive policies which would enhance or
preserve coastal resources for future use and development.
All facilities previously described in this repo .rt are included for
consideration,', and the support materials regarding facility type descriptions and
associated impacts serve as the basis for the option selections. The implications
following each option are intended to look at the ramifications (intended or other-
wise) of an option if implemented. Furthermore, it should be realized that these
options are not presented for blanket approval and implementation. It is possible
that they may be implemented individually or in combinations where feasible. It
is equally possible that none of the options will be implemented as presented.
It is felt that this group of options represents a framework of potential
policies that could be most easily implemented by the state CZM programs, short
of doing nothing at all. Under the Coastal Zone Management Act and its amendments,
the state programs will have management responsibilities, for those lands and uses
of land having a direct and significant impact on coastal waters. The following
options suggest various forms of management of new energy facilities in the

coastal zone.

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(1) Limit Expansion or Reconstruction to Existing Industrial or
Utility Areas
'This option would prohibit Commitment of coastal lands.and other resources
to future energy facility development by restricting new development or capacity
expansions to those areas presently developed for such uses.
Implications. This option would require new electric generating units to
be built on sites which.have already been developed for electrical generation,
thus increasing productivity per unit of land without increasing land requirements.
Presently, large tracts of land are developed for generating facilities with only
a small percentage of this land being utilized for the generating plarit (see
facility descriptions on coal and nuclear facilities), allowing for potential

expansion.
Those environmental/economic costs and benefits associated with facility
development would be concentrated at existing sites as a result. However, many
of the negative environmental impacts associated with site preparation would be
avoided and associated costs would be less also. Some environmental impacts of
operation and maintenance woul .d be concentrated and thus furtherdegrade the
quality of the existing site. Economic benefits would be restricted to specific
areas of previous facility development.
In cases where existing energy facility sites could not technically
support further expansionj generating or refining capacity would be displaced to

other or non-coastal sites.

(2) Avoid Areas of Particular Concern, Including Sensitive Areas
Areas of particular. concern would include those areas designated by the
state CZM programs according to the guidelines of the CZM Regulations. Examples
are areas of substantial recreational-value, significant hazard, and great
sensitivity, such as areas of unique habitats and high natural productivity, as

well as others.

Implication@L. This option would preserve applicable coastal resources for
future development possibilities and provide for protected environmental preserves.
It would restrict facility siting in the coastal zone, intensify competition for
remaining coastal areas between energ y facilities and other uses, and could
ultimately promote inland siting in those cases where remaining coastal lands are
not sufficient or satisfactory for energy facility development.--

436

(3) Encourage Development of Dispersed Siting.
Implications; Dispersed siting of new energy facilities or a deliberate
spatial distribution of new developments would tend to disperse environmental
impacts and at the same time increase systems reliability.
This option also would have the effect of increasing construction and
fuel transport costs'as distance from load centers increased. To offset long
distance transportation costs it is entirely possible that an increase in

development of fuel transshipment facilities would result. Economic costs and
benefits associated with facility construction and operation would be more evenly
distributed but would increase or decrease depending on the site specifics.

(4) Encourage Multiple Unit/Single Site Development
This option would allow development of new areas of coastal land, but in
amanner,that would obtain the highest energy production per unit of land.
Implications. It is felt that implementation of this option would have
the effect of reducing land requirements, therefore preserving coastal lands for
future use. It would reduce de-Velopment costs per unitlof energy and would

reduce transport and transmission costs.
As with the first option in this section, this option would tend to
concentrate th-elenvironmental/economic costs and benefits in specific areas.

(5) Specify Development Areas
State CZM programs, in addition to designating areas of particular concern,
would specify those areas, including energy resource areas, remaining in the
coastal zone where facility development would be permitted.
Implications. Ideally, this would provide the coastal zone planning-
agency with some control of the degree of concentration of facilities and their
impacts. In addition, it would facilitate future coastal zone land use planning.
Adoption of this option would remove some control of,the site selection
process from the utilities and shift the burden of planning to the state CZM or
other planning agencies. Because of the intricate nature of suitable site
selection for such facilities as nuclear and coal.-fired power plants, an expansion
or addition of necessary expertise within these agencies would be required.'
Hence, there would be an employment benefit, but this would be offset by the
increase in costs.of this added responsibility.

437

(6) Specify Facility Type and Size in the Coastal Zone
Based on their associated impacts, only certain types of facilities
determined by the CZM agencies would be allowed to site in the coastal zone. An
example of this would be to allow the coastal siting of nuclear plants with
cooling towers rather than coal.-fired plants with once-through cooling. The
intent here would be to specify a facility which does not commit large areas of
land to coal and fly ash,storage and does not have significant entrainment/
impingement'impacts on the lakes. This is only an example and does not indicate
a preference.
Implications. This option-, if implemented, would provide for control of
the type and scale of,i'mpacts to be permitted in the coastal zone. Because of
the extensive planning required to determine what impacts will and will not be
acceptable', an increase in cost of planning programs is foreseen. Likewise,
development costs and associatedplanning problems wou ld increase for the facility

owners.

(7) No Restrictions on Facility Type and Size in the Coastal Zone
This option, whilelassuming-that present environmental standards will be
maintained, provides for no further siting restrictions or controls with regard
to the-coastal zone.
Implications. The intent of this option would be to promote the most
rapid and inexpensive development of energy facilities per unit of production and
capacity. This would allow the utilities to.more readily I'meet America's growing
energy needs.

(8) Give Coasta:l Development Priorities to Energy Facilities
This option would give,first priority.to energy facilities in the develop-
ment of coastal.lands. In other words, if a tract of land might be available for
an auto plant development or a refinery, under this option the refinery would be
given priority by the,state CZM program.
Implications. Implementation ofthis option would provide for lower
cost energy production by facilitating utility access to fuel and water resources.
This would also encourage lake transportation of fuels and promote expansion of
harbor and transshipment facilities...
In.addition, this option would reduce coastal land and other resources
which might be used for other development. Facility impacts on the coast would

438

increase, e.g., thermal loading from c6oling'water, aesthetic intrusions of
transmission lines, and increase in construction employment. This option would
.,increase coastal zone transmission capacity requirements. in areas devoid of
previous development.

(9) Site Close to Existing Transshipment Facilities
Implications. The intent of this option would be to decrease costs and
negative environmental impacts associated with the transportation of fuels within
the coastal-zone. Land committed to these conveyance systems would be reduced as
well. This option would limit sitingalternatives, depending on.the number or,
variety of transshipment facilities in existence. The merit of this option would
depend also on the relative location of the transshipment facility to major
transmission systems. In some cases, higher cost of transmission would offset
fuel transportation cost savings.
Expansion of existing transshipment facilities might necessarily,follow,
as generating plant fuel "demands increased in a concentrated area. This cluster-
ing of plants in the vicinity of transshipment facilities would concentrate those
economic benefits and environmental costs as well, resulting in either a financial
shot in the arm for the local community or an environmental eyesore, depending
on the quality of planning.

(10) 'Locate in Proximity to Existing Electric Power Grid
The elect-Oic power grid is the network of extra high voltage (ehv) trans-
mission lines used for regional distribution of electricity. The intent of this
option in contrast to the preceding one would be to site close to the transmission
system to reduce construction and maintenance costs of new tie-in lines.
Implications. This would reduce those environmental and economic impacts

associated with the construction and-maintenance of-new transmission lines

required to tie distant'generating facilities into the power grid system. This
would increase the cost of fuel transportation and water conveyance in those
.cases where the existing power grid was not near the coast. Siting alternatives
would necessarily be limited as a result of this option, and in some cases
capacity of existing systems might have to be increased to handle new generating

demands.,

439

(11) Assign Priorities for Facility Development to Those Facilities
Employing By-Product Utilization
By-product utilization includes use of waste heat from generating plants
for.industrial processes, mixture.oj@ fly ash with asphalt, utilization of thermal
discharges for mariculture, and others.
Implications. This would reduce the local negative environmental impacts
associated with fuel utilization, such as air pollution, waste storage, and,
cooling discharges, and at the same time promote efficient use of resources. By
prioritizing siting, an incentive for development of by-product utilization would
be established. Operating costs would be reduced overall because of more
efficient utilization of primary fuels.
Development costs would necessarily increase in order to make these.by-
product usages technically and economically feasible. Symbiotic siting of
generating facilities and industrial users of by-products would result in concen-
tration of enviro.nmental/economic impacts in specific-areas.

(l2) Develop Buffer Zones
As specified,in the second set of options, buffer zones are areas designed
to reduce or contain aesthetic intrusions.@associated with energy facilities.
Examples might be green belts surrounding refineries, preservation of natural
areas around power plants, or vegetated berms around coal storage areas.
Implications. Development of buffer zones would reduce visual, auditory
and other impa:cts on the human senses which may be undesirable. Green belts.have
been-shown to naturally filter out some types of air pollution. In some cases,
increased recreational use may accompany development of buffer zone areas.
However, usessuch as industrial development would be restricted. Costs of
developing these buffer zones would fall on the-owners of the energy facility
contained within and therefore raise the,cost of the facility overall.

(13) Maintain or Increase Public Access to the Shoreline in the
Event that a Facility's Property has Shoreline Frontage
Under this option the new facility owner would include plans for public

access,to shoreline areas if his property includes shoreline.
Implications. Ideally, this option would provide for increased public

access, to scarce shoreline areas for uses such as.recreation. This would in

effect shift some of the burden of public access acquisition and development from
state and local agencies to utilities and facility owners. Development costs

440

.would increase for the utilities, but these might bepassed along to the

consumers.

There might-possibly be restrictions to this option in the case where
safety regulations would not allow such activities (i.e., nuclear safety
exclusion zones).

(14) Establish Restrictions on Cooling Type

This option would provide stricter controls on those
environmental impacts associated with condenser cooling methods. The environ-
mental control and planning agencies, rather than the utilities, would select
'cooling systems and would decide which type would be most desirable in the
coastal zone. This might result in a deci sion to ban flow-through cooling
because of negative effects on aquatic life, or a ban on cooling ponds because
they require.lar ge amounts of 1and area. Finally, the costs to utilities to
implement these prescribed cooling types might be so restrictive as to encourage
inland sit ing.

..(15) Adopt Air and Water Quality Standards Compatible with Coastal
Siting
This option would allow the state CZM programs to suggest stricter
environmental standards for en ergy facility operation in the coastal zone.
Implications. The thrust of this option would be to improve air and
water quality, or at least prevent further degradation of coastal environments.
This option would increase costs of environmental controls, and in cases where
these costs would be prohibitive, discourage coastal siting. It is entirely
possible that adoption of stricter environmental standards for the coastal zone
would result in a favoring of those facility types.which most easily meet the
new standards-. However, as noted in Section III.B.l.d. of this report, the
states may not be able to.adopt stricter (or more lenient) environmental s tan-
dards"specified only for their coastal zones.

(16) -Provide Financial Assistance to Local Areas for Impact Assess-
ment and Amelioration

(a) Impact assessment
Implications. Similar to option (9)(a) in the second grouping, this would
provide monies to the area affected by a proposed facility to aid local planning
agencies in initial, identification of potential deleterious impacts. This would

441

increase public involvement in the planning process and decision making. This
might also increase the time required for decision making. Increased employment
in the planning and consulting field would result,from these monies, but these
planning costs would have to be met elsewhere.

.(b) Impact amelioration
Implications. Monies allocated for this:purpose would obviate negative
impacts of energy facilities@and may in the long run increase benefits''to.,a local
area due to overall increases in enVironmental,or economic quality.

(17) Permit Shoreline Site Location of Energy Facilities
This option would permit the location of power plants and refineries next
to or near the shoreline, as well as permit the use of.coastal resources. Unless
shorelines are presently zoned for other uses, this option is essentially the

status quo.
I lications. This option would result in shoreline use for energy
facilities, thereby precluding its use for other major development or conserva-
..tion purposes. However, with proper-planning, other uses could be accommodated
in some areas of the energy facility site. The development Of the land near
shorelines and its use for energy,fac.ilities might possibly induce local shore-
line damage. By competing.with other possible.uses of the shoreline, energy
facilities development of the shoreline might increase its value and local land
acquisition costs. The presence of an energy facility next to or near the shore-
line may also affect adjacent land'values and uses. By doing so, commercial-
industrial development of the shoreline,may be encouraged,.possibly discouraging
other uses of neighboring shorelines. Related to theseconsiderations are the
visual-aesthetic effects of large facilities on the shoreline.
An advantage of shoreline-or near shoreline location.is that docking
facilities might be developed.for water transportation of fuels.and other
materials, if water transportation is-less expensive. Shoreline.location would
also provide ready access to water for cooling or other plant processes.

(18) Sp ecify Shoreline Setback Distance for Energy Facilities
Under this option,a setback distance for energy facilities would be
required. The setback distance could vary depending on the location and local
conditions and characteristics.. The setback requirement could be established

442

by local ordinance or by legislative action. Such a requirement could affect
fuel storage areas for docking facilities, but not the docking facilities.them-
selves. This option would not be intended to affect access to coastal resources
for the facilities discussed in this report.
Implications. By specifying a setback distance for energy facilities,
the integrity and aesthetic qualities of the shoreline would be preserved. This
option might increase multiple use of shoreline property if public access were
permitted; i.e., the property could be used for access to coastal res ources and
for recreation. A required setback distance for energy facilities would increase
capital and operation costs for a pipeline and pumping station, particularly if
once-thr6ugh cooling is used and/or the increase in elevation is large between
the water-source level and the plant. Additionally, if fuel or products are
received by water transportation, transportation.costs of these materials would
be increased. For a discussion of these increased water provision and transpor-
tation costs, the reader is referred to Sections IV.A.5.b.(l).(a) and (b) of this
report. The use of a setback distance might also affect adjacent development
along the shoreline as well as development behind the setback distance. For
example, the setback line might preserve shoreline for natural or recreational
uses on the property affected as well as encouraging such uses on adjacent areas.
This situation may influence adjacent land values also. Behind the setback.line,
commercial-industrial as well as residentialdevelopment might cluster, depending
on provision of roads and utility services.
The use of a setback distance might also encourage companies and govern-
ments to purchase property for energy facilities that would not hav .e property
frontage on the shoreline, as long as resource access was available, such as
through the purchase of.an easement.
With respect to the distance considered for setback, a 1000-foot setback
for the plant and appurtenances might be similar to not having any setback require-
ment at all. This would be particularly true in the case of aesthetic and shore-
line,use effects. A setback distance approximately 1/2 to 1 mile might be more
beneficial from the aesthetic and shoreline use standpoints, but would involve
some incrementing water provision costs and possibly transportation costs.
However, as in the case of the Pleasant Prairie facility in Wisconsin, an inland
location may be advantageous to tying in to the existing transmission system.

443

(19) Permit Only Those Facilities Absolutely Requiring Shoreline
Location to be Located on or Near the Shoreline
This option would necessitaie some kind of legislative action at the
local or state.1level. It would be similar to zoning areas for particular uses;
in-this case, zoning certain shoreline,areas for particular energy facilities
which absolutely require a shoreline location. Under thisopt ion, energy facili-

ties would still have access to coastal resources.

Implications._ This study,has not identified any energy facilities,
except docking and transshipment facilities for water transportation,, which
absolutely require shoreline locations. This option would permit areas-along
the shoreline to remain in existing use or to be used for'..other.purposes;, rather
than be used for energy facilities. Considerations for shoreline location should
emphasize economic as well as environmental factors. Inland locations in some
areas may result in significantly greater economic costs which may not be
warranted, even when compared to the environmental effects. Thus, this approach
would have to be used on a case-by-case basis, and yet applied stringently enough
to have a recognizable effect on shoreline uses. This option might place
considerable emphasis on a state-required environmental.re'port on energy facill-
ties, an approach already adopted by some Great Lakes states. Other implications
such as effects on shoreline and inland development,@tie-in to the transmission
system,,, and water provision and transportation costs would be similar to technical
option (18) above.

D. SUMMARY

The institutional and technical policy op'tions provide a broad range of
directions that the states and their coastal zone management programs might take.
The options in the various categories serve to highlight the many possibilities
for: (1) developing new institutions to address the current and complex problems
related to energy facilities siting; (2) utilizing existing institutions with new
or expanded arrangements among them and, in some cases, additional responsibili-
ties; (3) developing financial approaches to assist the companies and governments
involved in energy facility siting; and (4) developing technical, environmental
and economic approaches to locating energy . facilities with respect to the coastal
zone management area and the shoreline. Particular emphasis was given to
.integratingthese options with state coastal zone management progr ams. Selection

444

of some options within certain categories ne cessarily precludes choosing other
options within or among the categories. For the most part though, the selection
of combinations of options in various categories is unrestricted. Individual or
collective decisions by the states and their CZM programs regarding well-defined
policies for review and examination of guidelines for energy facility siting may
assist the utility companies and other energy-related industries in theirshort
and long range planning for facilities.

445

Chapter VII

SUMMARY AND CONCLUSIONS

This study covers several broad subjects related to energy facility
siting in,a manner that should be useful to the Great Lakes coastal zone manage-
.ment programs. Some general conclusions from this study can be made in each of
the major areas of analysis.

A. INSTITUTIONAL CONSIDERATIONS

At present, four of theeight Great Lakes states (Minnesota, New York,
Ohio, and Wisconsin) have instituted concerted and fairly well defined site
selection processes for electric generating facilities. However, these states have
not addressed to a significant degree the selection of sites for other types of
energy facilities. The four remaining states have only limited involvement in the
regulation of sites for all energy facilities, and have concentrated primarily on
the certification of a proposed facility with respect to compliance with standards
for air, water and land resource protection. In all Great Lakes states, policies
to guide the siting of energy facilities in the coastal zone are in the early
stages of development.
The authorities of several federal agencies, notably the Nuclear Regula-
tory Commission and the Environmental Protection Agency, will have a significant
influence on energy facility siting. The policies, standards and guidelines of
the EPA for the protection of air And water resources define aframework within
which other agencies or interests of the public and private sector may operate.
The greatest federal impact on future selection of sites for energy facilities
will'probably be through the Coastal Zone Management Act of 1972 and its 1976
Amendments. Several.provisions of the Act deal with energy facility siting.

446

With respect to incorporating energy facility siting policies into a comprehen-
sive program for coastal zone management, numerous institutional options are.
available to the states.

The Coastal Zone Management Act allows the states considerable freedom in
the development of plans and in the establishment of programs for the management
of their coastal zones. The mere fact that such.plans and programs are being
developed, that they will be reviewed and approved at the state and federal level,
and that subsequent actions must be consistent with such plans, will introduce
a measure of comprehensiveness and coordination to energy facility siting as well
,as to the entire process of resource management for the coastal zone. The
requirement for a planning process for energy facilities in the Great Lakes states
coastal zone management programs provides.the foundation for energy facility.
siting programs that address and emphasize the problems and opportunities of energy
facility siting in the Great Lakes coastal zone.

B. TECHNICAL CONSIDERATIONS

1. FACILITIES SITING AND COASTAL DEPENDENCE

The major types of energy facilities included in this study--fossil-fuel
and nuclear power plants, coal and oil transshipment facilities, and refineries--
were described and their particular site and resource requirements discussed. In
addition, a discussion of their major environmental and economic impacts were
presented and a framework for analyzing these ','activity impacts" suggested.
Finally, an analysis of some of the major cost components was given. Based on
this material, a description of the coastal dependent, or nondependent, aspects
of facility siting was presented. The major conclusion drawn from this analysis
is that, like so many other siting factors, the degree of coastal dependence
exhibited by an energy facility is a function of the facility type, the geographic
area within which it is to be located, and the availability of alternative sites.
In addition, certain facility types--refineries, fuel transshipment facilities,
and coal conversion facilities--are not expected to have a major impact-in the
Great Lakes coastal zone during the period considered in the study.
It can generally be concluded that an electrical generating facility does
not require a location on or near the coast. However, certain aspects of the

facility, such as cooling system and water provision, mode of fuel supply, local
geological and topographical conditions, meteorology, location of the existing

447

transmission system, may make a coastal site more or less favorable than an
available inland location. An evaluation of this degree of coastal dependence
should be carried out for each proposed facility so that it can,be compared to
other, less displaceable, uses of the Great Lakes coastal zone.
The following general conclusions can be sited with respect to the
coastal dependence of power plants:
e Facilities using once-through cooling must be located on or near the
shoreline because of substantial inland transportation (pipeline) costs of water

provision.
e Facilities using closed-cycle cooling are less dependent on locations
on or near the shoreline than are facilities using once-through cooling, assuming
all other factors to be approximately equal. Site conditions will determine the
type of closed-cycle cooling system used. However,,the further inland a facility
is located, the greater are the construction (capital) costs for water provision
and blowdown pipelines.
0 For facilities using closed-cycle cooling, the cost of locating on
the shoreline versus the cost of locating inland are essentially trade-offs
between construction and operation costs for transmission lines, water supply and
cooling facilities, facilities for delivery and handling of fuels, and other
supplies, and disposal of waste material.
0 Nuclear facilities require very large and massive components, which in
most cases are delivered by water transportation. However, rail or road.corri-
dors of adequate width and load-carrying capacity can be utilized for delivery of
these components. If these rail or road cooridors are not available to potential
sites, the location of nuclear facilities may be more dependent on shoreline or
near shoreline locations. In any event, field assembly is becoming more.common,
thus possibly negating some of this shoreline dependence. Otherwise, nuclear
facility coastal dependence-considerations would be those in the previous

conclusion.

The coastal dependence of fuel transshipment and storage facilities and

refineries can be summarized as follows:
Fuel (coal and oil) transshipment and storage facilities receiving or
shipping their commodities by water must locate near the shoreline, although.
storage areas do not have to be located on the shoreline. Storage area location
is highly dependent on industrial needs, future transportation requirements, and

onsite and offsite use of stored fuel.

448

e Refineries are not coastal dependent, but do need water for processing
and cooling. Coastal dependence for-water supply and wastewater disposal consid"
erations is decreasing due to increased water recycling. Air cooling is also
decreasing refinery dependence on easy access to water. Refinery location
decisions are increasingly becoming market oriented, with decisions being made
on a national basis, due to,the existence of the national product distribution

pipeline.
The degree of coastal dependence exhibited by a proposed energy facility
of a type discussed in this report may vary from nonexistent or slight, to very
strong or complete, depending on a range of site and facility characteristics.
In light of the limited, and in some cases unique, coastal land available in
the Great Lakes Basin, an evaluation of the best use of the coastal land should
be included in a site selection or approval process. In this way, use of the

Great Lakes coastal zone can be reserved for those uses least suited to inland

locations., While this may include energy facilities in some cases, it will
ensure that a more comprehensive view of coastal development is taken.

2. ENERGY CONSUMPTION AND MOVEMENT

Intensive energy consumption in the Great Lakes Region is facilitated by
the availability of an abundant fuel-resource, proximity to major water resources,
and the unique transportation system afforded by the Great Lakes.
Extensive coal resources in the nearby.Appalachian and midwestern regions
supply the bulk of the fuel for generating electricity.in the Great Lakes states.
@Oil, a very versatile fuel, has less application historically for the generation
of base load power in the Great Lakes Basin. However, the-broad and diverse end-
use of oil make it crucial to the region's energy needs.
The waters of the lakes are also a source of hydroelectric power for the
region and a heat sink for the.nuclear and fossil fuel power plants that line the

coast.

Transportation of fuels to these plants is facilitated by low-cost water-
borne movement on the lakes. The patterns of fuel traffic through the region
arise from a complex relation among costs, reliability, and legal regulations.
The arrival of low sulfurwestern coal on the lakes has marked a change
in the prevalent upbound traffic pattern of this commodity., Long-term investments
in this movement assure continuation of,a new pattern. Complementing.and.competing
with lake movement of coal is the extended use of unit train coal transport.

449

Unit train movement typically runs directly from the mine to consumer. Litiga-
tion by the lake carriers is presently seeking for Great Lakes ports the lower
,unit train rates already available for other destinations.
Coal will continue to play a dominant role in the future fuel mix of the
region. The preeminence of this fuel will depend largely on resolving many of
the unanswered questions that presently plague the development of nuclear energy
facilities. The use of coal also depends on adjustments of air quality stand-
ards or improvements in combustion/air quality control technologi .es.
New generating capacity is not planned or scheduled to be in service by
1984 in the coastal counties of Illinois, Minnesota or Pennsylvania. The combined
planned and scheduled additional electrical energy generating capacity for the
entire Great Lakes states area through the mid-1980s is 74,067 MWe, with 19,433 MWe

to be located in the Great Lakes coastal counties. (A state-by-state analysis is
presented in Chapter VI, Technical Considerations--Energy Consumption and Move-
ment in the Great Lakes Region.) Of this.19,433 MWe of additional capacity by
1984, 28 percent will be coal-fired (Michigan, New York and Wisconsin), 12% will
be oil-fired (Michigan and New York), and 60% will be nuclear (Michigan, New York,
Ohio,'and Indiana)-.

3. REGIONAL SCENARIOS OF ENERGY, DEVELOPMENT

Regional scenarios of energy development (principally electrical energy
generation) were prepared to develop a perspective on potential resource impacts
of siting new energy facilities in the Great Lakes coastal zone. The scenarios
are based on different fuel mix.assumptions. The four scenarios with their

respective fuel mix assumptions are:
e Scenario I, Recent Trends--50% coal, 35% nuclear, 15% oil, gas and
hydroelectric
o Scenario II, High Coal--70% coal, 15% nuclear, 15% oil, gas, and hydro-

electric

9 Scenario.III, High Nuclear--45% coal, 45% nuclear, 10% oil, gas, and
hydroelectric
o New Technologies--40-50% coal, 20-35% nuclear, 15-20% new technologies
(solar, wind, fluidized bed, etc.)
In developing regional resource requirements for land, water, and fuel
(coal), these scenarios were applied to a range of electrical energy demand growth
projections (3%/year, 5.5%/year, and 8%/year), an assumed mix of generating

450

facilities (75% base load, 20% intermediate load, and 5% peak load),'and an
assumed capacity load factor (65%). The resource requirements of the generalized
@facilities (coal-fired and nu clear power plants) were then applied to these
assumptions to evolve the regional resource requirements of energy development.
For the purposes of this study, a three percent growth rate per year'in
electrical energy consumption was assumed to be a lower bound in projecting
future power plant development, given present uncertain circumstances. Actual
growth in the future may be considerably higher or somewhat lower. These situ-
ations are not disputed or argued. This 3% growth rate will then describe the
minimum amount of resources required to meet future electrical energy consumption,

as shown in Table 79.

TABLE 79

ADDITIONAL RESOURCE REQUIREMENTSOF THE GREAT LAKES STATES, 1975-1995
SCENARIOS AT 3%/YEAR GROWTH RATE IN
ELECTRICAL ENERGY CONSUMPTION

Additional Scenarios
Requirements
(1975-1995) 1 11 111

Nuclear (units) 70 24 104
land (acres) 46,725 16,020 69,420
water (gpd)
once-through 1,008 x 10 8 346 x 108 1,498 x 10 8
closed-cycle 1,512 x 10 6 518 x 106 2,246 x 10 6
Coal (units) 40 96 12
land (acres) 16,000 38,400 4,-.800
fuel (millions of tons per year) 80 192 24
water (gpd)
once-through 403 x 10 8 963 x 108 121 x 108
closed-cycle 576 x 10 6 1,382 x 106 173 x 106

Requirements,under Scenario IV, New Technologies, is assumed to be about 80%,of
those in Scenario I, Recent Trends, due to a postulated reduced dependence on
more conventional generation technologies.

451

Assuming an 8%/year growth rate, Scenario I, Recent-Trends, projects an
.":additional 238 nuclear units and 185 coal units neededi with land requirements
8
of 233,000 acres, water withdrawals"of 5,292 x 10 gpd for once-through cooling
6
or 7,805 x 10 gpd for closed-cycle cooling, and coal requirements of 370 million

tons per year.
Table 80 shows the general projected resource requirements (assuming a
50% coal/50% nuclear fuel mix for additional capacity between 1975 and 1995,
which is an approximate average.of the four scenarios) that were developed,for
the Great Lakes coastal countie's on the basis of an analysis of the scenarios
..and each state's energy development-

TABLE 80

ADDITIONAL RESOURCE REQUIREMENTS OF THE GREAT LAKES
COASTAL COUNTIES, 1975-1995,
ASSUMING A 37. GROWTH RATE IN ELECTRICAL ENERGY CONSUMPTION

Additional Requi ements
Generating Water Coal
Generating Capacity Land Withdrawals (gpm) (Millions of
State Units* (MWe) (Acres) 'Once- Closed Tons per year)
Through Cycle

Illinois --- --- --- ---

Indiana
Michigan 11 11,000 5,870 9.35xlO'6 137,500 11.0
6
Minnesota 1-2. 1-2,000 1-2,000 0.9-1.7XIO 12-25,000 2-4.0
New"York 7 7,000 3,740 5.95xlO 6 87,500 7.6
Ohio 4,000 2,135 3.4xlO 6 50,000 4.0

Pennsylvania --- --- --- ---
Wisconsin 8 8,000 4,'270 6.8xiO 6 100,000 8.0

Coal and mclear units, assuming a 50% coal/50%'nuclear mix, as noted above.
Does not include Bailly nuclear unit, Porter County, on site already containing
two coal-fired units.

452

if an 8% growth rate is assumed, the figures in the table above would
increase by factors ranging from 2.0 to 4.8, depending on the state. This
indicates that considerable pressure might be placed on'the coastal counties of
Great Lakes Basin for electricalenergy generation facilities.

OTHER CONSIDERATIONS

A host of other factors not addressed in.this report will affect energy
facility siting. Some of these factors involve economic and political circum-
stances. The economic development and stimulation provided by the siting of an
energy facility may be attractive to relatively less developed areas located near
load or market centers,- In many cases,.utilities and industries already have
purchased land in outlying areas. Such.development may.be more acceptable in
these localities, and indeed, campaigns for the facilities may be undertaken..
Thus, political factors.may influence the final location of these facilities.
.-Such political-economic factors are difficult to examine-in an objective analysis
of energy facility siting, and are beyond the scope of this study.
state energy policies relating to consumption, rates,.construction and
building r@equirements,,-and other factors will affect the.need for additional
facilities and the types, of fuels to be used. Public reaction to the location
of individual facilities..or types of facilities and energy use will have obvious
effects on where facilitieswill be.located as well as when they will be
constructed and placed into operation.
The absence of a federal energy policy is permitting public acceptance,
environmental and market factors, and state policies to influence energy use and
energy facilitysiting at the national level. The present national energy policy
is thereby made up of these subsets of policies which affect each other but are
developed separately. While these factors and subsets of energy policies must
,be incorporated into a federal policy because of their,importance, there is no
consistency or coherence among them. On one hand, this,absence of a federal
energy policy does not lock the country into.energy.developments that may not be
advantageous in thelong run.. On the other hand,.the lack of a federal policy
results in a piecemeal approach to energy development, inconsistency in dealing
with energy consumption and facility siting problems, and confusion for utility
and energy related companies as to future planning and investments.

453

C. POLICY OPTIONS

The institutional policy options described in Section VI.B. indicate
the range of options available to'the states under the Coastal Zone Management
Act, as well as other applicable federal and state legislation. An attempt was
made, within the constraints of reasonableness, to mike the list as thorough as
possible@ The options are structured to encourage the reader to develop new
options through permutations and combinations of those presented. Note that
while special attention is given to matters related to the coastal zone, the
options also address the broad issues of energy facility siting.on a statewide
basis. It is important@to relate CZM-specific policy options to the institutional
framework of,the.state as a whole, and to provide consideration of statewide
energy facility siting regulation where such programs do not exist.
The technical options were developed within the limits of present or
.probable technical feasibility to provide,as wide a range of choices as possible
for future energy facility siting in the Great Lakes coastal zone. The technical
options are not constrained by traditional and present institutional policies. This
permits consideration of innovative siting options. Given the conclusions of
the coastal dependence analysis, the state coastal zone management programs are
encouraged to give strong consideration to the siting of energy facilities
other than shoreline fuel transshipment facilities) inland from the shoreline,
but with access,to coastal resources. The technical options suggest how this
might be accomplished.

D. IMPLICATIONS FOR FURTHER RESEARCH

During the course of this project, several topics were encountered for
which there was a lack of available information or that were beyond this study.'s
scope. Time-constraints precluded any extensive investigation of these topics
by the study staff so they are offered here as suggestions for additional
research. All have a bearing on the siting of energy facilities in the coastal

zone.

1. -LAND.VALUES

Attempts to compare coastal and inland sites for energyfacilities were

454

impaired,by a lack of information. on relative land values. Not only is,there a
lack of data comparing actual land costs, but the intangible land values associ-
ated with.aesthetic,. recreational and psychological aspects of the coastline
also require additional investigation.

2. NUCLEAR FUEL CYCLE

Nuclear power plants require a variety of facilities for the enrichment
,of nuclear fuel and the processing and disposal of wastes.- While none of these
facilities are currently located in the coastal zone of the Great Lakes, some
are nearby and others are proposed. The scope,of the study did not permit
adequate consideration of the coastal,d.ependency of such facilities. The trans-
portation of radioactive materials on the Great Lakes also requires additional
@in.vestigation with regard to transshipment and storage facilities and the poten-
tial hazard to the-lakes from radioactivity.,

3. MULTIPLE-USE SITING

The use of land for one purpose may not preclude all other uses. The
intensity of.land use in some coastal areas suggests that it may be judicious
for states to investigate the possibilities for multiple uses of lands, such as
transportation corridors and the.shoreline, associated with energy facilities.

SYMBIOTIC SITING.

The-waste heat from a power.plant andthe heat from incinerating
municipal trash both offer opportunities for symbiotic siting. Waste heat may
be dissipated in a beneficial, industrial application, while trash may supple-
ment other fuels in the production of electricity or perhaps serve as the sole
fuel. Practical problems with implementation of such schemes require investi-
gation.

5. CONSERVATION

While research is underway into various methods of conserving electricity
and other forms of energy, the potential for the mitigation of adverse impacts
on the coastal zone could be investigated.

6. OTHER FACILITIES

Coastal zone management plans and programs will.deal with a wide variety

455

of facilities and land uses. The'coastal dependency of these other facilities
and uses could be investigated so *at a comparison could be made with the
results of this report and the relative requirements for coastal access.among

all land uses could be established.

7. SMALLER SCALE FACILITIES

Although electrical generating'facilities were covered in detail in
this report, a factor that may affect the construction of large generation facil-
ities is the development of combined cycle generation. Research is being
directed toward examining the use of combined' cycle generation for facilities (less
than 150 MWe) that would serve small communities or neighborhoods and large
individual industrial plants. Future pricing policies for electricity use and
for natural gas may encourage their application. The use of smaller scale fossil-
fuel powerplants '(other than combined cycle) should also be evaluated and
compared to poss ible.use of combined cycle plants. The significance of the
possible use of these facilities and their implications for future land, water,'
air, and fuel use should be examined.

8. DETAILED STATE POLICY ANALYSIS

A highly detailed analysis should be made of the policies, programs,
and legal authorities within each state that significantly influence energy.
facility siting in both coastal and inland areas. This greater level of detail
is a logical spinoff from this study and. is a.necessary prerequisite for each
state's'development of comprehensive institutional framework to implement energy-
facility siting policies and/or programs.

9. RELATIONSHIP BETWEEN STATE AND FEDERAL POLICIES

Further research into a number of substantive areas of energy.policy in
the Great Lakes Basin is needed. A detailed analysis should,be made of the
specific implications of the various aspects of federal energy facility siting
policy for each of the eight Great Lakes states.

10. STATE AND FEDERAL POLICIES

Policy research is necessary in state and federal policies affecting
energy use. Suggestions should be made for the establishment of coherent frame-
work within which the present energy use policies can be viewed and future

456

policies developed. Furthermorej the interaction among policy development,
technology, and resource requirements needs considerable attention.

At the state level, the.effect of electric and fuel rates on the need
for energy,facilities should be investigated. At the federal level, a comp
hensive fuels use-environmental policy would provide guidance,to.the energy
industry.

11. SHORELINE USE

A detailed study of shoreline land use should be undertaken on a state-
by-state as well as regional basis. Energy facilities.compete with other uses
of the shoreline. A better understanding of these uses and their relationship
and dependence on shoreline locations co ld greatly assist coastal zone manage-
ment planning.

12. ENVIRONMENTAL AND ECONOMIC EFFECTS

Load centers for electricity and facilities to provide this power are

clustered near the coastline of the Great Lakes.. The environmental and economic

effects of these facilities on the Great Lakes coastal zone in the context of

resource and impact management should be investigated.

13. LOCAL PLANNING AND DECISION MAKING

Planning and decisions made at the local (municipal, county, multi-coun-
ty) level can have a significant impact on the,availability and use of resources.
.Planning for energy facilities is a case in point. Further research.should be
directed-toward how local planning and decision-making affect resource manage-
ment and what are the types of policies, institutions, and processes involved in
this planning and@',decision-making.

14. THE-GREAT LAKES BASIN AS A FUTURE EXPORTER OF ELECTRICITY

The Great Lakes provide a water resource for cooling and process water
in the energy industry as well as for other industries. The potential exists
for this use of Great Lakes water to expand in the future. Energy facilities do

not need to locate on the shoreline to use this resource, but can be located
inland and still draw on it. If large energy facilities or clusters of facil-
it.ies localte in or near the coastal zone of the Great Lakes and export energy

from this area while utilizing its water resources, the social, economic,

457

political, and environmental implications of this circumstance should be examined

in detail.

15. INTERNATIONAL IMPLICATIONS

Great Lakes ports engage in international shipment of fuels for energy
production. In addition, electricity is transmitted back and forth (primarily
on a seasonal basis in the Great Lakes Region) across the international boundary.
Further study should be undertaken by the United States and Canada to determine
the implications of this for plant requirements and the associated resource
demands and impacts.

459

Appendix A

STANDING COMMITTEE ON GREAT LAKES COASTAL ZONE MANAG EME NT

MICHIGAN MINNESOTA

Mr. Merle Raber, Acting Chief Mr. Gene Hollenstein
Shorelands Management & Water Resources Chief Hydrologist
Planning Sec.,-Div. of Land Use Division of Water', Soils & Minerals
Michigan Dept. of Natural Resources Minnesotabept. of Natural Resources
Stevens T. Mason Building 345 Centennial Building
Lansing, Michigan 48926 St. Paul Minnesota 55155
ILILINOIS Mr. Roger Williams
Minnesota State,Planning Agency
Mr. Peter L. Wise (Committee Chairman) 100 Capitol Square Building
Coordinator-for Coastal Zone Management St. Paul, Minnesota 55101
Marina City Office Building M.r. Archie Chelseth
300 North State St., Room 1010 Assistant Commissioner
Chicago, Illinois 60610 Minnesota Dept. of Natural Resources
Mr. Chris A. Shafer 300 Centennial Office Building
Assistant Director for.CZM St. Paul, Minnesota 55155
Department of Transportation
Marina City Office Building NEW.YORK
300 North State St., Room 1010 Mr. Henry Williams
Chicago, IlIlinois 60610 Director of State Planning
INDIANA Department of State
162-Washington Avenue
Mr. William J. Andrews, Deputy Director Albany, New York 12231
for Water & Mineral Resources Mr. Frederick W. Howell
Indiana Dept. of Natural Resources New York State Department of
608 State Office Building Environmental Conservation
Indianapolis, Indiana 46204 50 Wolf Road
Mr. Theodore Pantazis Albany, New York '@12233
State Planning Services Agency
143 West Market Street OHIO
Harrison Building Mr. Bruce-E. McPherson
Indianapolis, Indiana 46204
Shoreland Management, Div. of Water
Ohio Dept. of Natural Resources
Building E., Fountain Square
Columbus, Ohio 43224

460

PENNSYLVANIA DEPT. OF INTERIOR
Mr. Georj@e E. Fogg, Coordinator Ms. Madonna F. McGrath,.Acting
9
Coastal Zone Management Program Special Assistant to the Secretary
Dept. of Environmental Resources North Central Region
Bureau of Resources Programming U.S. Dept. of Interior
Third & Reily Streets 230 S. Dearborn Street
Harrisburg, Pennsylvania 17120 Chicago, Illinois 60604

WISCONSIN DEPT. OF ARMY
Mr. Theodore F. Lauf Mr* Louis D'Alba
Coordinator-Special Projects Planning Branch
Office of Planning & Analysis North Central Division
Wisconsin Dept. of Natural Resources U.S. Army Corps of Engineers
Box 7921 536 South Clark Street
Madison, Wisconsin 53707 Chicago, Illinois 60605

Mr. Allen Miller
.Land Use Coordinator ENVIRONMENTAL PROTECTION -AGENCY
Dept. of Administration Mr. Ralph Nordstrom, CZM Coordinator
State Planning Office Planning Branch
1 West Wilson Street Airand 'Water Programs Division
Madison, Wisconsin 53702 Environmental Protection Agency
230 South Dearborn Street
DEPT. OF TRANSPORTATION Chicago, Illinois 60604
Mr. David C. Robb, Director
DEPT. OF HOUSING 6, U"AN DEVELOPMENT
Office of Comprehensive Planning
St. Lawrence Seaway Development Corp. Mr. Harry P. Blus
800 Independence Avenue, S.W. Environmental Standards Officer
Washington, D.C. 20591 Community Planning and Management
Cmdr. Charles R. Corbett U.S. Dept. of HUD
Chief of Environmental Affairs Region V
'Nin'th Coast uard District 300 South Wacker Drive
1240 East 9th Street Chicago, Illinois 60606
Cleveland, Ohio 44199 SECRETARIATS

DEPT. OF COMMERCE Mr. Leonard T. Crook
Dr. Arthur P. Pinsak Executive Director
Great Lakes Environmental Research Lab Great Lakes Basin Commission
Dept. of Commerce, NOAA 3475 Plymouth Road
2300 Washtenaw Avenue P. 0. Box 999
Ann Arbor, Michigan 48106
Ann Arbor, Michigan 48104
Mr. Gerald F. Kotas
Ms. Eileen Mulaney Water Resources Planner
Office of Coastal Zone Management Great Lakes Basin Commission
Dept. of Commerce, NOAA' 3475 Plymouth Road
3MO Whitehaven Street P. 0. Box 999
@Page Building No. 1 Ann Arbor, Michigan 48106
Washington, D.C. 20235

461

Appendix B

CZM ENERGY PROJECT STEERING COMMITTEE

Mr. John Armstrong Mr. David C. N. Robb, Director
State Planning Office Office of Comprehensive Planning
,l West Wilson Street St. Lawrence Seaway Corporation
Madison, Wisconsin 53702 800 Inddpendence Avenue, S.W.
Washington, D.C. 20591
Dr. William Mattox
Ohio Dept. of Natural Resources Mr. Warren Hofstra
.Building D, Fountain Square North Central-Region
Columbus, Ohio 43224 U.S. Dept. ofthe Interior
230 S. Dearborn Street, 32nd Floor.
Mr. Delbert Johnson Chicago, Illinois 60604
Water Resource Planner
Bureau of Water Management Mr. James H. Phillips
Michigan Dept. of Natural Resources EniE@rgy-Coordinator, Region.V
Stevens T. Mason Building U.S. Environmental Protection Agency
Lansing, Michigan 48926 230 South Dearborn Street

Mr, Thomas Fiddler Mr. John Paul Tolson
Ddpt.:of Environmental Resources Office of Coastal Zone Management
P. 0. Box 14.67 NOAA, Dept. of Commerce
Harrisburg, Pennsylvania 17120 3300 Whitehaven.Street
Page Building #1
Mr. Dmitri Aperjis Washington, D.C. 20235
Office of Coastal Zone Management
NOAA, Dept. of Commerce.
3300 Whitehaven Street,
Page Building #1
Washington, D.C. 20235

462

Appendix C

CZM ENERGY PROJECT TECHNICAL ADVISORS

Mr. Fred Abel Mr. Forrest G. Hiple
U.S. Energy Research Vice-President
and Development Administration Electric Operations & Construction
Fossil Energy Northern Ind. Public Service Company
20 Massachusetts Ave., N.W., 5265 Hohman Avenue
Washington, D.C. 20545 Hammond, Indiana 46320

Professor Richard Bishop Mr. John Hoover
Dept. of Agricultural Economics Argonne National Laboratory
340 Agricultural Hall 9700 S. Cass Avenue
1450 Linden Drive Argonne, Illinois 60439
Madison, Wisconsin 53706
Mr. Herb Jacobs
Mr. Karl Bremer Governor's Energy Council
Lake Studies PCB 905 Payne-Shoemak6r Building
Technical Support Branch -Harrisburg, Pennsylvania 17120
U.S. Environmental Protection Agency
230 S. Dearborn Mr. Owen A. Lentz, Exec. Manager
Chicago, Illinois 60604 East Central Area Reliability
Coordination Agreement
Mr. Walker Cisler P.O. Box 102
1071 Devonshire Canton, Ohio 44701
Grosse Point, Michigan 48236
Dr. James L. Liverman
Mr. Andrew (Pete) D'Zmura U.S. Energy Research and Development
19155 Roman Way Administration
Gaithersburg, Maryland 20760 Mail Station.E-201
Washington, D.C. 20545
Mr. Hugh Gardner
Federal Energy Administration Mr. Peter Meier
175 W. Jackson Associated University, Inc.
Chicago, Illinois 60604 Brookhaven National Laboratory
Upton, New York 11973
Mr. Tom Hemminger
Commonwealth Edison Mr. Walter J. Matthews
Div. of Environmental Affairs 555 Wayside Drive ,
Box 767 Indianapolis, Indiana 46260
Chicago, Illinois 60690

463

Mr. E.L..Michelson Mr. Richard Williamson
Administrative Manager, MAIN Systems Analysis
.1 N. 301 Swift Road U.S. Energy Research and
P.O. Box 278 Development Administration
Lombard, Illinois 60148 20 Mass Ave., N.W.
7th Floor, APAE
Mr. William McGorum, Acting Secretary Washington, D.C. 20545
Ohio Power Siting Commission
Seneca Tower Mr. Alec Wisch
E. Broad Street Governor's Energy Council
Columbus, Ohio 43215 905 Payne-Shoemaker Building
Harrisburg, Pennsylvania 17;20
Mr. Charles Hill
Federal Power Commission Mr. Howard Zar., Oceanography
Federal Building, Room 3130 Permits Branch
230 S. Dearborn Street U.S. Environmental Protection Agency
Chicago, Illinois 60604 230 S. Dearborn
Chicago, Illinois 60604
Mr. Robert S. Ryan, Director
Ohio Energy Research and Mr. Ellison Burton
Development-Agency U.S. Energy Research and
25th Floor, State Office Tower Development Administration
30 E. Broad Street, APAE - 7th Floor
Columbus, Ohio 43215 Washington, D.C. 20545

Mr. Al Grandys Mr. Robert H. Sims, Chairman
Division of Energy Mid-Atlantic Area Coordination Group
Illinois Dept. of Bus. co/GPU Service Corp.
and Economic Dev. 260 Cherry Hill Road
222 S. College Street Parsippany, New Jersey 07504
Springfield, Illinois 62706
Mr. Julius Bleiweis
Dr. Miller Spangler Executive Director
U.S. Nuclear Regulatory Comm. Northeast Power Coordinating Council
Washington, D.C. 20555 1250 Broadway
New York, New York 10001
Mr. Richard L. Wawrzyniak
Assistant Chief, Mr. Thomas Jackson
Division of*Water Michigan Energy Administration
Room 605, State Office Bldg. Dept. of Commerce.
Indianapolis, Indiana 46204 Law Building
Lansing, Michigan 48913
Mr. Robert F. Welford, Reg. Coordinator
U.S. Fish & Wildlife Service Mr. Jick Hyers
Federal Bldg., Ft. Snelling Office of Planning, Analysis, &
Twin Cities, Minnesota 55111 Evaluation
U.S. Energy Research and
Mr. Jerry.Williams, Engineer Development Administration
Environmental Impact Statement Washington, D.C. 20545
EIS Review Section
U.-S. Environmental Protection Agency
26th Floor, S&A Division
230 S. Dearborn
Chicago,-Illinois 60604

464

Professor John Steinhart Mr. John Foltz
Associate Director, Marine Studies Center Ashland Oil Co., Inc.
University of Wisconsin--Madison ATTN:. Communications Department
1225 West Dayton Street P.O. Box 391
Madison, Wisconsin 53715 Ashland, Kentucky 41101

Mr. Frank Davenport Dr. John Armstrong
U.S. Water Resources Council Coastal Zone Laboratory
Suite 800, Gelman Building University of Michigan
2120 "L" Street Ann Arbor, Michigan 48109
Washington, D.C. 20037,
Mr. Jim Beatty
Mr. Derek M. Foulds Sault St. Marie Power and Light
Director, Ontario Region Sault St. Marie, Michigan
Inland Waters Directorate
135 St.,Clair Ave., West Mr. Rob Callen, Director
2nd Floor Research Division
Toronto., Ontario M4V 1P5 Public Service Commission
7545 Mercantile Way
Mr. Richard C. Clancy Lansing, Michigan
Vice President
Ni'gara Mohawk Power Corporation
a Mr. Joseph Cook, Manager
300 Erie Boulevard West Port Development Section
Syracuse, New York 13202 Bureau of,Transportation & Planning
Michigan Dept. of State Highways &
Mr. George L. Houston Transportation
Assistant Vice President Highways Building
New York State Electric & Gas Lansing, Michigan
.Corporation
4500 Vestal Parkway East Dr. William Cooper
Binghamton, New York. 13902 Department of Zoology
Michigan State University
Mr. Gerald I. Stillman East Lansing, Michigan
Acting Prin'cipal Environmental Engineer
Power Authority of the State of New York Mr. John Duane, Staff Engineer
10 Columbus Circle Gas Energy Planning Dept.
New York, New York 10019 Consumers Power Company
212 W. Michigan Avenue
Mr. Roger W. Kober Jackson, Michigan 49201
Acting Assistant
Manager of Environmental Engineering Professor Marc Enns
Rochester Gas and Electric Corporation East Engineering Building
89 East Avenue University of Michigan
Rochester, New York 14649 Ann Arbor, Michigan 48109

Mr. Earl G. Ellerbrake Mr. Thomas Cotton
Office of Oil and Gas Office of Technology Assessment
Federal Energy Administration U.S. Congress
Room 3442, Federal Building Washington, D.C.
12th and Pennsylvania Ave., N.W.
Washington, D.C. 20461 Dr. Fred Jones
American Natural Gas Company
.1 Woodward Avenue
Detroit, Michigan

465

Dr. Elizabeth Peel
Social Impact Assessment
Oakridge National Laboratory
P.O. Box X
Oakridge, Tennessee 37830

Mr. Car 1 Rapport
Federal Energy Administration
Washington, D.C.

Mr. Burkhard H. Schneider
Detroit Edison Company
2000 Second Avenue
Detroit,.Michigan 48823

Mr. Richard T. Huber
Fish and Wildlife Service
U.S. Dept. of the Interior
Federal Building, Fort Snelling
Twin Cities, Minnesota 55111

While a broad group of technical advisors from both the public and
private sectors participated in the study by reviewing and commenting on
preliminary material and the draft report, this should not be taken as their
endorsement of this final report. They served only as advisors, reactors,
and providers of information.

466

Appendix D

CZM ENERGY PROJECT CITIZEN ADVISORS

Mr. David Comey
Executive Director
Citizens for a Better Environment
Suite 2610, 59 E. Van Buren
Chicago, Illinois 60605

Dr. John Neess
Department of Zoology
Birge Hall
University of Wisconsin
Madison, Wisconsin 53706

Mr. Myron Cherry
One IBM Plaza, Suite 4501
Chicago, Illinois 60611

Mrs. Betty MacDonald
Regional Resources Chairperson
League of Women Voters
1155 Edgewood Avenue
Madison, Wisconsin 53711

Dr. Paul Friesma
Public Lands Project
Northwestern University
Evanston, Illinois 63301

Ms. Louise Young
755 Sheridan
Winnetka, Illinois 60093

467

Appendix E

CZM ENERGY PROJECT STAFF

PROJECT MANAGEMENT

Leonard Crook, Executive Director--Supervisor
Charles Job--Project Manager
Gerald Kotas--Coastal Zone Management Coordinator

POLICY UNIT

Thomas Gross--Policy Analyst
'John Hall--Resources Planner and Policy Analyst

COASTAL DEPENDENCE UNIT

Robert Clemens--Geologist

John Johansen--Economist

William Skimin--Resources Planner and Policy Analyst

PROJECTIONS AND TRENDS UNIT

Reed Bohne--Resources Planner

David Staples--Resources Planner and Policy Analyst

SECRETARY AND OFFICE MANAGEMENT

Terri Ogle--Secretary and Office Manager
Marie Murrell--Typist

TECHNICAL ADVISORS

Jonathan Mayer--Transportation Research Analyst
Timothy Monteith--Civil Engineer

468

Appendix F

SUMMARY OF AIR QUALITY EFFECTS OF S023, PARTICULATES, AND N02

Effects of Sulfur Dioxide

1. Effects on Humans
3
0 1500 pg/m (0.52 ppm) of sulfur dioxide (24-hour average), and
suspended particulate matter measured as 'a soiling index of 6 cohs or
greater: increased mortality may occur (American data).
.3
0 715 pg/m (0.25 ppm) of sulfur dioxide and higher (24-hour mean),
accompanied by smoke at a concentration of 750 pg/m3: increased daily
death rate may occur (British data).
e 500 pg/m3_(O.lgl ppm) of sulfur dioxide (24-hour mean), with -low
particulate levels: increased mortality rates.may occur (Dutch data).
0 300 pg/m3 to 500 pg/m 3 (0.11 ppm to 0.19 ppm) of sulfur dioxide
(24-hour mean), with low particulate levels: increased hospital admis-
sions of older persons for respiratory diseas 'e may occur; absenteeism
from work, particularly with older persons, may also occur (Dutch
data).
0 (0.25 ppm) of sulfur dioxide (24-hour mean), accompanied by
particulate matter: a sharp rise in illness rates for patients over
age 54 with severe bronchitis may occur (American data).
0 (about 0.21 ppm) of sulfur dioxide (24-hour mean), with smoke
concentrations of about 300 pg/m3: patients with chronic lung disease
may experience accentuation of symptoms (British data).
0 105 Pg/m3 to 265 pg/m3 (0.037 ppm to 0.092 ppm) of sulfur dioxide 3:
(annual mean), accompanied by smoke concentrations of about 185 P-g/m
increased frequency of respiratory symptoms.and.lung disease may occur
(Italian data).
0 (0.046 ppm) of sulfur dioxide (annual mean), accompanied by
smoke concentrations of about 100 pg/m3: increased frequency and .
severity of respiratory diseases in school children may occur (British
data).

Material in this appendix is adapted from Environmental Protection Study,
prepared by ICF, Incorporated, for the Michigan Public Service Commission.
May, 1975.

469

0 115 Ug/m 3 (0.040 ppm) of sulfur dioxide (annual mean), accompanied
by smoke concentrations of about 160 pg/m3: increase in mortality from
bronchitis and from lung cancer may occur (British data).

2. Effects on Visibility
3
285 pg/m (0.10 ppm) of sulfur dioxide, with comparable concentration
of particulate matter and relative humidity of 50 percent: visibility
may be reduced to about five miles (American data).

3. Effects on Materials
0 345 pg/m 3 (0.12 ppm), accompanied by high particulate levels: the
corrosion rate for steel panels may be increased by 50 percent
(American data).

4. Effects on Vegetation
0 85 pg/m 3(0.03 ppm) of sulfur dioxide (annual mean): chronic plant
injury and excessive leaf drop may occur (Canadian data).
0 860 pg/m3 (0.3 ppm) of sulfur dioxide for 8 hours: some species of
trees and.,shrubs show injury (American data).
0 145 Ug/m3 to 715 pg/m3 (0.05 ppm to 0.25 ppm):- sulfur dioxide may
react synergistically with either ozone or nitrogen dioxide in short-
term exposures (e.g., 4 hours) to produce moderate to severe injury
to sensitive plants (American data).

Effects of Particulates

1. Effects on Humans
* 750 Mg/m3 and high er for particulates on a 24-hour averagp, accompanied
by sulfur dioxide concentrations of 715 pg/m3 and higher: excess
deaths and a considerable increase in illness may occur (British data).
e A decrease from 140 p /m3 to 60 yg/m3 (annual mean) in particulate
concentrations may be accompanied by a decrease in mean sputum volume
in industrial workers (British data).
3
9 If concentrations above 300--Pg/m for particulates persist on a 24-hour
average nd are accompanied by sulfur dioxide concentrations exceeding
630 pg/ml over the same average period, chronic.bronchitis patients
will likely suffer acute worsening of symptoms (British data).
3
0 Over 200 pg m for particulates on a 24-hour average, accompanied by
concentrations of sulfur dioxide exceeding 250 Pg/m3 over the same
average period: increased absence of industrial workers due to illness
may occur (British data).
0 100 Pg/m3 to 130 pg/m3 and above for particulates (annual mean) with
sulfur dioxide concentrations (annual mean) greater than 120 Pg/m3:
children residing in such areas are likely to experience increased
incidence of certain respiratory diseases.

470

3
* Above 100 Pg/m for p2rticulates (annual geometric mean) with sulfation.
levels above 30 mg/cm -Mo.: increased death rates for persons over 50
years of age are likely (American data).
* 80 pg/m3 to loopg/M 3 for particula5es (annual geometric mean) with
sulfation levels of about 30 mg/cm -mo.: increased death rates for
persons over 50 years of age may occur (American data).

2. Effects on Direct Sunlight
3 3
0 100 Pg/m. to 150 pg/m for particulates, where large smoke turbidity
factors persist: in middle and high latitudes direct sunlight is
reduced up to one-third in summer and two-thirds in winter (American
data).

3. Effects on Visibility
0 150 pg/m3 for particulates, where the predominant particle size ranges
from 0.2 to 1.0 and relative humidity is less than 70 percent:
visibility is reduced to as low -as 5 miles (American data).

4. Effects on Materials
0 60 pg/m 3 ( annual geometric mean), to 180 pg/m 3 for particulates
(annual geometric mean), in the presence of sulfur dioxide and moisture:
corrosion of steel and zinc panels occurs at an accelerated rate
(American data).

5. Effects on Public Concern
0 70 pg/m 3 for particulates (annual geometric mean), in the presence of
other pollutants: public awareness and/or concern for air pol lution
may become evident and increase proportionately up to and above con-
centrations of 200 pg/m3 for particulates (American data).

Effects of Nitrous Oxide

1. Effects on Humans
3
0 225 pg/m@ (0.12 ppm) for nitrogen dioxide: an odor becomes detectable.
* 9,400 pg/m3 ( 5 ppm) for nitrogen dioxide for 10 minutes: has produced
transient increase in-airway resistance.
9 162,200 Vg/M3 (90 ppm) for nitrogen dioxide-for 30 minutes: has pro-
duced pulmonary edema 18 hours later.
0 118 to 156 jig/m3 (0.063 to 0.083 ppm) for nitrogen dioxid S (24-hour
standard) with a mean suspended nitrate level of 2.6 Pg/m orgreater:
increased acute bronchitis among infants and school children.
a 117 to 205 pg/m3 (0.062 to 0.109 ppm) for nitrogen dioxide (24-hour
mean) with a mean suspended nitrate level of 3.8 pg/m3 or greater:
increased acute respiratory disease.in family group.

471

2. Effects on Materials
a .(0.25 ppm) for nitrogen dioxide for 8 months caused leaf
abscission and decreased yield among navel oranges.
0, 940 pg/m3 (0.5 ppm) for nitrogen dioxide for 35 days resulted in leaf
abscission and chlorosis on citrus fruit trees.
0 1,900 Pg/m3 (1 ppm) for nitrogen dioxide for one day can cause overt
leaf injury to sensitive plants.

472
Appendix G

ELECTRIC GENERATING FACILITIES

WATER AVG CPS PLANT OF
COUNTY LOCATION COMPANY PLANT WAKE MWe FUEL, SOURCE INTAKE HEAT RATE UNITS STATE

CLev. Elect. BTU/KWH
Ashtabula Ilium. Co. Ashtabula 640 coal/Oil Lake Erie 658 11,428 9 10hio
Clev. Elect.
Lorain 11.1um. Co Avon Lake 1,275 Coal/Oil Lake Erie 947 10,338 9 Ohio

Clev. Elect.
Lake Ilium. Co. East Lake 1,275 Coal/Oil Lake Erie 1,270 9,512 5 Ohio

Clev. Elect..
Cuyahoga Illum. Co. Lake Shore 514 Coal/Oil Lake Erie 4.56 11,552 5 Ohio

Commonwealth
Lake Edison Co. State Line 972 Coal/Gas Lake Michigan 1,259 10,573 4 Indiana

Commonwealth
Cook Edison Co. Fisk 547, Coal/Cas Chicago Canal 401 11,302 3 1111inois
Commonwealth
Cook Edison Co. Calumet 107 Gas Calumet River 67 13,224 1 Illinois

Conwionwealth
Cook K,116on Co. Crawford 702 Coal/Gas Chicago Canal 593 10,292 3 Illinois

Commonwealth
Cook Edison Co. Ridgeland 6901 oil/Gas Chicago Canal 742 11,177 4 Illinois

Commonwealth
Lake Edison Co. Waukegan 933 Coal/Oil Lake Michigan 962 10,195 7

Commonwealth
Lake Edison Co. Zion 1,098 Nuclear Lake Michigan 1,618 13,269 1 Illinois

Copsumers
Muskegon Power Co. Cobb 510 Coal/Oil Lake Muskegon 619 10,590 5 Michigan

COLIsumers Big Rock
Charlevoil Power Co. Point 75 Nuclear Lake Michigan 114 11,421 1 Michigan

Consumere
Bay Power Co. Karn 550 Coal/Oil Saginaw River 454 9,136 2 IMichigan
Cunsufflers
Ottawa Vuwer Co. Campbell 650 C*6al/Oil Pigeon Lake 504 9,097 2 Michigan

Coa8umers
Van Buren Power Co. Palisades 720 Nuclear Lake Michigan 900 10.981 1 Michigan
Detroit Pub. B711-J FKWI -I
Wayne Lightng.Comm Misteroky 174 Coal Detroit River 243 10,9 09 6 Michigan
Lk..Superior coal/
Ashland Dist.Pwr.Co. Bay Front 82 Oil/Gas Lake Superior 46 13,213 6 Wisconsin

Manitowoc
Manitowoc Public Util. Manitowoc 69 Coal Lake Michigan 51 14,999 5 Wisconsin
Marquette Brd.
Marquette of Lt & Powei Sheras 37 Coal/Gas Lake Superior 30 14,243 2 Michigan

Minn. Power
St. Louis & Light. Aurora 110 Coal/Oil Lake Colby 210 13,030 2 Minnesota
Minn. Power Coal/
St. Louis & Light. Hibbard 124 oil/Gas St.Louis River 364 14,576 4 Minnesota,
Niagara-Mo-
Oswego hawk Pwr.Co. Oswego 376 Oil Lake Ontario 500 11,51-5 4 New York

Niag.-Mohawk
Erie Power Co. Huntley 828 Coal Niagara River 1,160 10,380 6 New York

Niag.-Mohawk
Chautauqua Power Co. Dunkirk 628, Coal/Oil Lake Erie 890 109059 4 New York

Niag.-Hohawk 9 Mile
Oswego Power Co. Point Nuc 500 Nuclear Lake Ontario 518 10,7()9 1 New York

No.Ind.Publii
Porter Serv. Co. Bailly 615 Coal/Gas Lake Michigan 470 10,008 2 Indiana
Consumers Coal/Casl
Bay Power Co. Weadock 614 oil Saginaw River 545 10,61A 8 Michigan

Consumers
Monroe Power Co. Whiting 325 Coal/oil Lake Erie 362 9,913 3 Michigan
Coal/
Wayne Detroit Edis Conners Creei 510 Oil/Gas Detroit River 1 796 13,050 a Michigan

473

WATER AVG CFS PLANT OF
COUNTY LOCATION COMPANY PLANT NAME MWe FUEL SOURCE INTAKE HEAT RATE UNITS STATE

Wayne D.truit Edis Delray 375 Oil/Gas Detroit River 375- 14,440 6 Michigan

Monroe 0-.Lrolt Edis Fermi 1581 Oil _ Lake Erie 82 14,626 1 Michigan
- BTU/KWH
Huron Detroit Edisi Harbor beach 121 Coal/Oil Lake Huron 154 10,600 1 Michigan

St. Clair betroit Edis Marysville 200 Coal/Cas St.Clair River 461 12,300 7 Michigan

Wayne Detroit Edis Pennsalt 37 Coal/Oil Detroit River 18 54,657 7 Michigan
Coal/
Wayne Detroit Edis River Rouge 933 Oil/Gas Detroit River 1,041 9,450 3 [Michigan
Coal/
.St. Clair Detroit Edis St.. Clair 1,905 Oil/Gas St.Clair River 2,290 9,220 7 Michigan
Trenton Coal/
Wayne Detroit Edis Channel 876 Oil/Gas Detroit River 1,400 10,450 5 Michigan

Coal/ -
Wayne Detroit Edis Wyandotte 541 Oil/Gas Detroit River 152 11,800 8 Michigan

Monroe DeLruit Edis Monroe 2,462 Coal/Oil Raisin River. 1,796 9,600 3 Michigan
No.Indiana
Lake Public Serv. Mitchell 529' Coal/Gas Lake Michigan 690 10,124 4 Indiana

No. Indiana
Lap2jtei Public Serv. Michigan Cit3 215 Coal/Gas Lake Michigan 223 12,349 3 Indiana
p"r :

No Mich
C
C v
[email protected] Ll-*@c.C-.P'.In4. Advance. 37 Coal f Lake Charlevoix 856 12,636 3 Michigan
Ohio
Lorain Edison Co. Edgewater 193 Coal Lake Erie 181 11,747 3 Ohio
Pennsylvania
Erie Elec. Co. Front Street 119 Coal Lake Erie 220 14,295 5 Patin .

Rochester Ga! Coal/
Monroe & Etec. Corp Rochester #3 196 Oil/Gas Genessee River 147 18,849 1 9 New York
Rochester Ga!
Monroe & Elf-c.Corp. Rochester #7 253 Coal/Oil Lake Ontario 231 10,534 4 New York

Rochester Gat
Wayne & Elec.Corp. Rochester#13 490 Nuclear Lake Ontario 1 842 10,803 1 New York
Toledo Edisoi ICoal/ BTU/KWH i
Lucas Co. Acme 321 Oil/Gas Maumee River 309 12,994 1 5 Ohio

Toledo
Lucas Ecison Co. Bay Shore 638 Coal/Oil Maumee River 1,100 9,238 4 Ohio

Upper Penin. Presque
Marquette Gen. Go. - isle 175 Coal/Oil Lake Superior 1814 11,283 4 Michigan
Wisconsin
Milwaukee Elec.fi Pwr 0 Commerce 35 Oii/Gas Milwaukee River 72 16,021 1 lWisconsin
Wis. Elect.
Milwaukee & Power Co. Lakeside 310 Oil/Gas Lake Michigan 41 172159 8 Wisconsin

Wis * Elect. North
Milwaukee & Power Co. Oak Creek 500 Coal/Oil Lake Michigan 686 10,301 4 Wisconsin,
Wis. Elect. Port
Ozaukee & Power Co.- Washington 400 Coal Lake Michigan 623 11,585 5 Wisconsin

Wis. Elect. South
Milwaukee & Power Co. Oak Creek 1,192 Coal/Oil Lake Michigan 1,457 9,685 4 Wisconsin

Wis. Elect. N. Menominee
Milwaukee & Power Co. VAIley 272@ Coal/Gas Canal 182 14,145 2 Wisconsin

Wis. Elect.
Manitowoc & Power Co. Point Beach 1,047 Nuclear Lake Michigan 1,287 10,934 2 Wisconsin

Wis. Elect.
Sheboygan & Power Co. Edgewater 437 Coal/Oil Lake Michigan 295 10,085 4 Wisconsin
Wis. Elect. Coal/Oili
Brown & Power Co. Pulliam 393 Gas Fox River 500 11,351 8 Wisconsin

Ind. & Mich.
Berrien jElectric Co. Cook, D.C. 1,089 Nuclear Lake Michigan 1.537 10,771 1 Michigan

475

ACRONYMS

AQCR - air quality control region
ACRS - Advisory Committee on Reactor Safety
ASLB - Atomic Safety and Licensing Board
BWR - boiling water reactor
cfs - cubic feet per second

DER - Department of Environmental Resources

DES - Draft Environmental Statement

DNR - Department of Natural Resources
EHV - extra high voltage
EPA - Environmental Protection Agency
EQC - Environmental Quality Council
ESECA Energy Supply and Environmental Coordination Act
ERDA Energy Research and Development Administration
FEA - Federal Energy Administration

FES - final environmental statement

FPC - Federal Power Commission

gpd - gallons per day
gpm - gallons per minute
kWh - kilowatt (1,000 watts) hour

LMFBR liquid metal fast breeder reactor
LNG - liquefied natural gas
MW = megawatt (1,000,000 watts)

NO - nitrous oxides

NPDES - National Pollutant Discharge Elimination System
NRC - Nuclear Regulatory Commission
PCRV - prestressed concrete reactor vessel

PSC - Public Service Commission or Power Siting Commission
PUC - Public Utility Commission
SIP - state implementation plan
SNG - synthetic natural gas
SO x- sulphur oxides

477

GLOSSARY

Base load unit an electric generating facility which is normally operated to
carry base load and which, consequently, operates essentially at a constant
load.

Base loading the operation of a unit at or near its rated output to supply the
base load of a system.

Benthic organisms - organisms attached, resting, or living on or in the bottom
sediments.

Blowdown - release or cleaning out.of water with high solids content, the
solids having accumulated each time water evaporates.

BWR boiling water reactor - a nuclear reactor in which water, used as both
coolant and moderator, is allowed to boil in the core.

Btu (British thermal unit) - the amunt of energy necessary to raise the
temperature of one pound of water by one degree Farenheit, from 39.2 to 40.2
degrees.

Capacity - maximum rating of a generating unit most often in Kw or Mw..

Capacity factor - the ration of the average load on a machine, or equipment, for
the period of time considered, to the capacity rating of the maching or
equipment.

Cooling Systems

Once through systems where cooling water is taken from'a suitable source,
passed through the condenser, and returned to the source body of water.
Same as direct cooling.

Closed cycle systems - (evaporative cooling) where cooling water is contained
in a closed system and its heat dissipated to the air through heat
exchangers. Includes dry and wet cooling towers, spray ponds, canals,
mechanical draft, etc.

Core meltdown - failure in control mechanism or cooling system of nuclear reactor
which results in nuclear pile going super-critical with meltdown and
rupture of the reactor vessel potentially occurring.

Efficiency - (heat rate) - measure of how effectively a tlermal'ge'nerating station
is operating, generally expressed in Btu per net kilowatt hour. It is
computed by dividing the total Btu content of1fuel burned for electric
generation by the resulting net kilowatt hour generation.

478

Energy - the-capac,ity for doing work, often measured in kilowatt hours.

Energy facility broad term which includes development, production, conversion,
storage, processing, transfer or transportation of any energy resource.
These would include refineries, fuel transshipment and storage facilities
and electric generating units.

EHV lines - transmission lines which have a rated capacity above and including
236 kilovolts.

Generating facility " broad term encompassing all types of electric generating
facilities.

Interm6diate load plant - a generating unit that is normally operated to provide
power for loads between base load and peak load levels.

kW MW - GW.- (kilowatt, megawatt, gigawatt) instantaneous measure of electric
power equal to 1,000 watts, I million,watts, and 1 billion watts, respectively.

kWh Kilowatt hour - the basic unit of electric energy equal to one kilowatt
of power supplied to or taken from an electric current steadily for one hour.

Load center - a point at which the load of a'given area is assumed to be concen-
trated.

Load factor - the ratio of the average load in kilowatts, supplied during a
designated period, to the peak or maximum load in kilowatts occurring in
that period.

LWR - light water reactor - a nuclear.reactor which uses water (H20) to transfer
heat from the fissioning of uranium to a steam turbine.

Load schedule - same as load curve - a curve of demand versus time of occurrence
in chronological sequence the magnitude of the load for each unit of time
of the period covered.

Makeup water - that quantity of water added to a closed cycle.cooling system
needed to replace water lost through evaporation or blowdown.

Nektonic - swimming organisms able to navigate at will.

Particulates microscopic pieces of solids which emanate from a range of
sources and are the most widespread of all substances usually considered
air pollutants.

Peak demand - same as peak load - the maximum load in a stated period of time.

Peaking faci 'lity - same as peaking generation - same as peaking unit - a unit
which is normally operated only to provide power during high demand periods.

Plant factor same as capacity factor.

-479

Planktonic floating organisms whose movements are more or less dependent on
currents.

Power - the time rate at which work is done or energy emitted or transferred,
measured instantaneously in kilowatts.

Power plant same as generating facility

Power pool regional grouping,of utilities to promote reliability, production
and transmission of electricity.

PWR Pressurized'water reactor - a nuclear reactor in which heat is transferred
from the core to a heat exchanger by water kept under high pressure to
achieve high temperature without boiling in the primary system. Steam is
generated in the secondary system.

Reliability councils - coordinate in varying degrees the planning, construction,
and operation of transmission and generating facilities of groups of
utilities. They effect an adequate supply of low-cost power.

Reserve margin - same as reserve capability-the difference between net system
capability and system maximum load requirements.

Slurry pipeline - mixture of coal and water transported in pipelines.

Unit-train a train dedicated to transporting one commodity fr om source to
user.

481

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66. Federal Energy Administration; National Energy Information Center.
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67. Federal Energy Administration; National Energy Information Center.
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75.. The University of Michigan, Institute of Science and Technology.
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87. Department of Natural Resources, Geological Survey Mineral Economics
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88. Frund, Eugene. Natural Gas - Pennsylvania. July 11, 1975.

89. Department of Natural Resources. Steam Electric Power.Generating. July,
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90. Bishop, Richard C. and Daniel L. Vogel. Power Plant Siting on Wisconsin's
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91. Public Service Commission of Wisconsin. Findings of Fact, Certificate
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92. Minnkota Messenger. Some Serious Talk on the Energy Situation. January
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93. U.S. Energy Research and Development Administration. Geothermal Energy.

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100. U.S. Department of Commerce. Commerce America. April 26, 1976., "U.S.
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101. 94th Congress, 2d Session.. Synthetic Fuel Commercial DemonstrationFund
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102. U.S. Energy Research and Development Administration. Creating Energy
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103. Resources-for the Future, Inc. Towards a Responsible Energy Policy. 1975.

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105. American Enterprise Institute. The Future of the Electric Utilit .ies.
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106. Department of the Interior, U.S. Fish and Wildlife Service. National
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107. White, David C. Ener y Consumption and Electric Supply Influence 1972.
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108. Power Plants in the Great Lakes Basin.

109. Energy Research and Development Administration. Nuclear Energy, Questions
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110. U.S. Energy Research and Development Administration. Fusion. 1975.

111. Public Service Electric and Gas Company. Nuclear Energy, Questions and
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112. Federal Energy Administration., Energy Reporter. Special Nuclear Issue,
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113. Atomic Industrial Forum, Inc. National Environmental Studies Project.
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114. 93D Congress, 2d Session. Energy Supply Act of 1974. Senate Report No.
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115. 94th Congress, lst Session. Energy Independence Authority Act of 1975.
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116. Science. -Transportation Energy Conservation Policies. Vol. 192, No.
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117. Inman, Donald L. Preliminary Assessment of Potential Great Lakes Offshore
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118. Union Carbide Corporation. Synthetic Natural Gas(SNG). December, 1975.

119. Union Carbide Corporation. The U.S. Electric Power Supply. "A Vital
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120. Union Carbide Corporation. The Crisis in Natural Gas. December, 1975.

121. 92nd Congress, S. 3507. Public Law 92-583. Marine Resources and Engineering
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122. 94th Congress, S. 622. Public Law 94-163. Energy Policy and Conservation
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489

123. 94th Congress, lst Session. Conference Report Energy Policy and
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124. 94th Congress, 2d Session. R.R. 13451. A Bill to improve the Nation's
energy resources, by establishing a national power grid system, for the
purpose of assuring an adequate and reliable low-cost electric power
supply consistent with the enhancement of environmental values. April
29, 1976.

125.. 94th Congress, 2d Session. H.R. 13350. A Bill to authorize appropria_@
tions to the Energy Research and Development Administration in accord-
ance with section 261 of the Atomic Energy Act of 1954, as amended,
section 305 of the Energy Reorganization Act of 1974, and section 16 of
the Federal Nonnuclear Energy Research and Development Act of 1974, and
for other purposes. April 27, 1976.

94th Congress, 2d Session. H.R. 13172. An Act making supplemental
appropriations for the fiscal year and 'ing June 30, 1976,and the period
ending September 30, 1976, and for other purposes. April 26, 1976.

127. 94th Congress, 2d Session. H.R. 13350. A Bill to authorize appropria-
tions to the Energy Research and Development Administration in accordance
with section 261 of the Atomic Energy Act of 1954, as amended, section
305.of the Energy Reorganization Act of 1974, and section 16 of the
Federal Nonnuclear Energy-Research and Development Act of 1974, and for
other purposes. April 27, 1976.

128. 94th Congress, 2d Session. H.R. 13449. A Bill to amend the Federal
Energy Administration Act of 1974 to provide for authorizations of
appropriations to the Federal Energy Administration, to extend the
duration of authorities under suchAct, and for other purposes. April
29, 1976.

129. 94th Congress, 2d Session. S. 3339. A Bill to promote more effective
management of certain,related functions in@a new Department of Energy
and Natural Resources. April 28, 1976.

130. 94th Congress, 2d Session. H.R. 12207. An Act to amend the Rural
Electrification Act of 1936, as amended, to correct unintended inequities
in the interest rate criteria for borrowers from the Rural Electrification
Administration, and to make other technical amendments. May 4, 1976.

131. 94th Congress, 2d Session. S. 3105. A Bill to authorize appropriations
to the Energy Research and Development Administration in accordance with
section 261 of the Atomic Energy Act of 1954, as amended, section 305,of
the Energy Reorganization Act of 1974, and section 16 of the Federal
Nonnuclear Energy Research and Development Act of 1974, and for other
purposes. March 9, 1976,

132. 94th Congress, 2d Session. H.R. 13410. A Bill to create within'the
Energy Research and Development Administration the position of Assistant
Administrator for Solar and Geothermal Energy and Conservation, and for
other purposes. April 28, 1976.

490

133. 94th Congress, 2d Session. S. 3107. A Bill to authorize appropriation -s
to the Nuclear Regulatory Commission in accordance with section 261 of
the Atomic Energy Act of 1954, as amended, and section 305 of the Energy
Reorganization Act of 1974, as amended, and for other purposes. March 9,
1976.

134. 94th Congress, 2d Session. H.R. 12387. A Bill to authorize appropria-
tions to the Nuclear Regulatory Commission in accordance with section
261 of the Atomic Energy Act of 1954, as amended, and section 305 of the
Energy Reorganization Act of 1974, as amended, and for other purposes.
March 9, 1976.

135. 94th Congress, 2d Session. S.J.RES. 126. Joint Resolution consenting
to an extension and renewal of the interstate compact to conserve oil
and gas. May 4, 1976.

136. 94th Congress, 2d Session. S. 3362. A Billto provide authorization for
a United States contribution to the International Atomic Energy Agency
in support of its safeguards activities and for other purposes. May 3,
1976.

137. '94th Congress,,2d Session. H.R. 12168. A Bill to amend the National
.Gas Pipeline Safety Act of 1968 to authorize appropriations for fiscal
year 1977. February 26, 1976.

138. 94th Congress, 2d Session. H.R. 13220. A Bill to amend the Natural
Gas Act to authorize a natural gas pipeline from the North Slope of
Alaska through Canada to the contiguous forty-eight States. April 13,
1976.

139. 94th Congress, 2d Session. S. 3310. A Bill to conserve electric energy,
to reform electric utility rate regulation, to strengthen State electric
utility regulatory agencies, and for other purposes. April 13, 1976.

140. 94th Congress, 2d Session. S. 3341. A Bill to abolish the Federal
Energy Administration. April 29, 1976.

141. 94th Congress, 2d Session. S. 2872. Amendment intended to be proposed
by Mr. Pell to S. 2872, a bill to amend the Federal Energy Administratiofi
Act of 1974 to extend the expiration date of such law until September
30, 1979, and for other purposes. April 29, 1976.

142. 94th Congress, 2d Session. S. 3311. A Bill to amend the Federal Power,
Act, to provide coordinated longrange planning and facility siting in
the electric utility industry, and for other purposes. April 13, 1 1976.

143. 94th Congress, 2d Session. H.R. 13350. A Bill to authorize appropria-
tions to the Energy Research and Development Administration in accord-
ance with section 261 of the Atomic Energy Act of 1954, as amended,
section 305 of the Energy Reorganization Act of 1974, and section 16 of
the Feder&l Nonnuclear Energy Research and Development Act of 1974, and
for other purposes. April 27, 1976.

491

144. U.S. 94th Congiess,-ls t Session, Senate. Energy Facility Siting,in
Costal Areas. (Committee Print for Senat ommittee on Commerce).
U.S.G.P.O. , 1975.

145. Shafer, Chris A. Power Plant-Siting Issues_and Policies for the Great
Lakes Costal Zone. Prepared for the Great Lakes Basin Commission
Standing Committee on Costal Zone Management. February 3, 1975.-
146. U.S. Geological@Survey. Resource and Land Investigations (RALI) Pro-
gram: Methodologies for Environmental Analysis. Vol. III: "Power
Plant Siting." 1 19.2: R13.

147. Wisconsin University Sea Grant Program. The Great Lakes Transportation
Syste . Technical Report 9230. January, 1976.

148. U.S. National Science Foundation. Assessment of Energy Parks vs Dispersed
Electric Power Generating Facilities, Final Report. Vol. II. May 30,
1975. Report Prepared for the Office of the Science Adviser Energy R&D
Policy Office Under Nat .ional Science Foundation Grant OEP74-22625 A01.

149. U.S. National Science Foundation. Assessment of Energy Parks vs Dispersed
Electric Power Generating Facilities,-Final,',Report. Vol. I. May 30,
1975. Report Prepared fore the Office of Ithe'Science Adviser Energy
R&D Policy Office Under National Science Foundation Grant OEP74-22625 A01.

150. New York, Cornell University Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental Quality.
"Recent State Initiatives on Power Plant Siting: A Report and Comment."
February, 1972. Paper No. 72-3.

151. New York, Cornell University Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental Quality.
"New Institutional Arrangements to Resolve Power Plant Siting Conflicts:
A Polical-Analysis." February, 1972. Paper No. 72-4.

152. New York, Cornell University Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental Quality.
"Public Utility Investment and Regulatory Practices." January, 1974.
Paper No. 14-1.

153. New York, Cornell Unive .rsity Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and,Environmental Quality
"NEPA: Some Legal Constraints as SetForth by the Court in,Calvert Cliffs."
October, 1971. Paper.No. 71-12.

154. New York, Cornell University Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental quality.
"Coal Gasification: A Review. November, 1971. Paper No. 71-15.

155. New York, Cornell Univeristy Center for Environmental Quality Management.
bir
Cornell Energy Project: National Energy Needs-and Env` onmental Quality.
"Nuclear Insurance:, An Estimate of the Cost.of the Nuclear Hazard."
October, 1971. 'Paper No. 71-13.

492

156. New York, Cornell University Center for, Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental Quality,
"Federal Funding for Research and Development of Fossil Versus Nuclear
Fuels Used for Civilian Energy Production." October, 1971. Paper NO.
71-14.

157. New York, Cornell University Center for Environmental Quality Management.
Cornell Energy Project: National Energy Needs and Environmental Quality.
"Radioactive Waste Management at Nuclear Fuel Reprocessing Plants."
February, 1972. Paper No. 72-2.

158. U.S. Army Corps of Engineers. St. Paul District. Draft Environmental
Impact Statement. "Refined Products Terminal Lakehead Pipe Line Company,
Inc. Duluth - Superior Harbor." May, 1975.

159. Empire State Electric Energy Research Corporation. 1975 Report of Member
Electric Corporations of the New York Power Pool and the Empire State
Electric Energy Research Corporation Pursuant to Article VIII, Section
149-b of the Public Service Law. Vol. 1. April 1, 1975.

160. Empire State Electric Energy Research Corporation. 1975_Report of member
Electric Corporations of the New York Power Pool and-the Empire State'
Electric Energy Research Corporation Pursuant to Article VIII, Section
149-b of the Public Service Law. Vol. 2. April 1, 1975.

161. U.S. 94th Congress, lst Session, Senate. Energy Facility Siting in Costal
Areas. (Committee Print For The Use of the Committee on Commerce and
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Policy). December, 1975.

162. State of Florida, Department of Environmental Regulation. Materials
Outlining-Florida's Power Plant Siting Program. As pf July, 1976.

163. Michigan Congress. House Bill No. 5271. A Bill to regulate the loca-
tion of power facilities within this state; to create the state power
facility siting council and to prescribe its powerq. 'and duties; to re-
quire utilities to prepare certain plans; and to prescribe penalties.
May 20, 1975.

164. Michigan Congress. House Bill No. 4478. A Bill to provide for review
by the Michigan public service commission of plans, forecasts, and
planned expansion of electric and gas utilities; to provide for the re-
gulation by the commission of the location, construction, and operation
of certain electric generating plants, certain electric transmission
lines, and gas processing plants including holding joint hearings and
issuing joint orders with other states or the the United States; to
provide for certificates of public convience and necessity and environ-
mental compatIbility; to provide for control of costs and operating
efficiency of certain electric generating plants and gas processing
plants; to premit the commission to enter into interstate compacts; and
to prescribe penalties. March 4, 1975.

493

165. Michigan Congress. House Bill NO. 4846. A Bill to regulate the con-
struction and use of oil and gas pipeline facilities; to authorize the
public service commission toestablish and enforce safety-standards
concerning,oil and gas pipelines, gas processing plants, and gas stor-
aIge facilities; to provide for rates and tariffs; to-provide for con-
demnations; to provide penalties; and to reveal certain acts and parts
of acts. April 8, 1975.

166. Great Lakes Basin Commission Staff and Great Lakes National Assessment
Work Group. State-Regional Future Great Lakes Region: 1975 National
Water Assessment (Draft). March, 1976.

167. Cornell University,-C.enter for Environmental Quality Management.
Cornell Energy Project, National Energy Needs and Environmental Quality.
Technology Assessment with Special Reference to Energy, Paper No. 70-1.
Written by C.L. Comar, Principal Investigator. October, 1970.

168. Cornell University, Center for Environmental Quality Management.
Cornell Energy Project, National Energy Needs and Environmental Quality.
National Energy Needs and Environmental Quality, Paper No. 71-6.
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169. Resources for,the Future, Inc. Economics of Thermal Pollution Control.
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170. Massachusetts Institute of Ted hnology. Power, Pollution and Public Policy.
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171. U.S. Environmental Protection.Agency. Study of an Integrated Power,
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172. Atom Industrial Forum, Inc. Nuclear Environmental Information--Resources
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173. Atomic Industrial Forum, Inc. General Environmental'Guidelines for
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174. Atomic Industrial Forum, Inc. Nuclear Power Plant Siting--A Generalized
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175. Atomic Industrial Forum, Inc. Environmental Impact Monitoring of Nuclear
Power Plants: Source Book of Monitoring Methods, Volume 1. Prepared
by Battelle/Pacific Northwest Laboratories/Columbus Laboratories.
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176. Atomic Industrial Forum, Inc. Environmental Impact Monitoring f Nuclear
Power Plants: Source Book of Monitoring Methods, Volume 2. Prepared by
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1975.

494

177. MAthetmatica. "U.S. Energy Policy Evaluation: Some Analytical
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176. Argonne National''Laboratory. Forecasting the Local Economic Impacts
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for the U.S. Energy.Research and Development Administration under
Contract W-31-109-Eng-38. December, 1975.

179i American Nuclear Society. Nuclear Power and the Environment: Questions
and Answers. October, 1973.

180. California University, School of Engineering and Applied Science.
Public Health Risks of Thermal Power Plants. Prepared for the Resources
Agency of California'. May, 1972.

181. Rand Corporation. 'California's Electricity Quandary: 11-Planning for
Power Siting. Prepared for the California State Assembly No. R-1115-RF/CSA.
September, 1972.

182. U.S. 94 th Congress, lst Session, Senate. Public Works for Water And
Power Development and EnergX Research Appropriations. Senate Hearings
Beforethe Committee on Appropriations. H.R. 8122. Fiscal Year 1976.
Part 3. 1975.

183. U.S. Council on Environmental Quality. Report on 1975 Public Hearings.
"Environmental Effects and Energy Conservation Aspects of the Nonnuclear
Energy Research, Development, and Demonstration Programs." January, 1976.

184. U.S. Federal Power Commission. The 1970 National Power Survey. Part I
of IV. December, 1971.

185. U.S. Federal Power Commission. The 1970 National Power Survey. Part II
of IV. 1971.

186. U.S. Federal Power Commission. The 1970,National Power Survey. Part III
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187. U.S. Federal Power Commission. The 1970 National Power Survey. Part IV
of IV. 1972.

188. U.S. Federal Power Commission. Federal Power Act. April 1, 1975.

189. U.S. Federal Power Commission. Annual Report 1974. 1974.

190. U.S. Federal Power Commission. Steam-Electric Plant Construction Cost
and Annual Production Expenses, Twenty-S4xth Annual Supplement-- 1973.
1975.

191. U.S. Energy Research and Development Administration. Recommended Synthetic
Fuels Commercialization Program. Interagency Task Force on Synthetic
Fuels Commercialization, Fact Book. November, 1975.

495

192. U.S. Federal Power Commission. Steam-Electric Plant Air and Water Quality
Control Data, For the Year Ended December 31, 1973 Based on FPC Form No.67,
"Summary Report." January, 1976.

193. U.S. Energy Research and Development Administration. Final Environmental
Statement - Liquid Metil Fast Breeder Reactor Program. "Summary and
Supplemental Material." Vol. 1 of 3. December, 1975.

194. U.S. Energy Research and Development Administration. Final Environmental
Statement - Liquid Metal Fast Breeder Reactor Program.' "Comment Letters
and ERDA Responses." Vol. 2 of 3. December, 1975.

195. U.S. Energy Research and Development Administration. 'Final Environmental
Statement - Liquid Metal Fast Breeder Reactor Program. "Comment Letters
and ERDA Responses." Vol. 3 of 3. December,, 1975.

196. Illinois Coastal Zone Management Program. The Illinois Coastal Zone
Management Program: First Year Work Product; Volume I, Legal Analysis.
By: Taussig, Wexler, and Shaw, Ltd. Submitted to: The Illinois Coastal
Zone Management Program. June, 1975.
197. State and Regional Commission. Energy Volume IV: Electrical Energy and
Power Plants. Preliminary Draft. July, 1974.

198. Mid-America Interpool Network. Electric Power Reliability. Date Unknown.

199. Mid-America Interpool Network. MAIN's.1976 Reply to Appendix A-1 of
Order No. 383-3. April 1, 1976.

200. Flint, Harold J., Division of Geological Survey. Electric Power Trans,-
mission System in Ohio: 1974. 1975. In cooperation with Power Siting
Commission.
201. Ohio Department of Natural Resources. Oil,and Gas Fields of Ohio (Incl!@@
Underground Storage Areas). 1974. In cooperation with Division of Oil
and Gas.

202. Ohio Department of Natural Resources. Oil and Gas Pipe Lines in Ohio.
1973. Compiled by Harold J. Flint.

203. Environmental Technology Assessment, State of Illinois. Power Facility
Siting in the State of Illinois. Part II--Environmental Impacts of Large
Energy Conversion Facilities.

U.S. Army Corps of Engineers, North Atlantic Division. Northeastern
United States Water Supply Study: Preliminary Study of Long-Range Water
Supply Problems of Selected Urban Metropolitan Areas. Volume I--Main
Report. Prepared by Anderson-Nichols and Company, Inc. Contract No.
DACW 52-71-C-0001. November, 1971.
205. 94th CongressP lst Session. H.R. 2650. A Bill to increase domestic energy
sup-plies and availability; to restrain energy demand; and to prepare for
energy emergenciesq and for other purposes. February 4, 1975.

496

206. Federal Energy Administration. Annual State Energy Consumption for FEA
'Region V States.' Submitted by Hugh Gardner. May 15, 1976.

207. U.S. Atomic Energy Commission. General Environmental Siting Guides for
Nuclear Power Plants, Topics and Bases. December 1973.

208. U.S. Atomic Energy Commission. Land Use and Nuclear Power Plants, Case
Studies of Siting Problems.

209. Southern,Insterstate Nuclear Board. Power Plant Siting in the United,States.
June, 1976.

210. East Central Area Reliability Coordination Agreement. Volume V: Conceptual
Planning Projections. A Report by ECAR Bulk Power Members to the Federal
Power Commission Pursuant to Docket R-362, Order 383-3. April, 1976.

211, Illinois (State) Institute for Environmental Quality. Power Facility Siting
in the State of Illinois. Part 1: Siting Regulation Alternatives. 1974.

212.. East Central Area Reliability Coordination Agreement. ECAR Summary Report
.of Permit and Contact Requirements of ECAR Members. 72-EAP-48. 1972

213. Illinois (State) Institute for Environmental Quality. Potential Sites for
Coal Conversion Facilities in Illinois. October 21, 1974.

214. East Central Area Reliability Coordination Agreement. Volume V: Load
Projections and Resource Planning. 'A Report by ECAR Bulk Power Members
to the Federal Power Commission Pursuant to Docket R-362, Order 383-3.
April 1976.

215. East Central Area Reliability Coordination Agreement. Volume II: System
Performance and Transmission Planning. A Report by ECAR Bulk Power Members
to the Federal Power Commission,Pursuant to Docket R-362, Order 383-3.
.April 1976.

216. East Central Area Reliability Coordination Agreem ent. Volume III: Area
.Controls, Communication, and Emergency Preparedness. A Report by ECAR
Bulk Power Members to the Federal Power Commission Pursuant to Docket R-362,
Order 383-3. April 1976.

217. East Central Area Reliability Coordination Agreement. Volume IV: Liaison
.Systems' Data. A Report by the ECAR Liaison,Committee to the Federal
Power Commission Pursuant to Docket R-362, Order 383-3. April 1976.

218. U.S. 94th Congress. lst Session. Senate. Greater,Coal Utilization.
Joint Hearings before the Committees on Interior and Insular Affairs and
Public Works. S. 1777. Part 1. June 10 and 11, 1975.

219. U.S. 94th Congress. lst Session. Senate. Greater Coal Utilization.
Joint Hearings before the Committees on Interior and Insular Affairs and
Public Works., S. 1777. Part 3 - Appendix.

220. U.S. 94th Congress. lst Session. Senate. Greater Coal Utilization.
Joint Hearings before the Committees on Interior and Insular Affairs and
Public Works. S. 1777. Part 2. June 12, 16 and 23, 1975.

497

221. U.S. Office of Science and Technology. Considerations Affecting Steam
Power Plant Site Selection.

222. The Science and Public Policy Program, University of Oklahoma. Energy
Alternatives: A Comparative Analysis. May 1975.-

223. Office of Coal Research, U.S. Department of the Interior. Water Require-
ments for a Synthetic Fuels Industry Based on Coal'. Presented at the
Workshop-on "Research Needs.Related to Water for Energy" University of
Illinois on October 20, 1974. Prepared by Edward Schmetz, Harold Podall, and
G. Alex Mills. (from Chris Shafer's files)

224. Coal Conversion: Processes, Resource Requirements, and Environmental
Impact. (from Chris Shafer's files).

225. Johnson, Sue, and Alan Randall. Research Needs on Social, Political and
Institutional Aspects of Coal Utilization. (from Chris Shafer's file)

226. Carroll, Sidney L. Research Needs on Economic and Resource Management
Aspects for Coal Gasification/Liquefaction. Workshop on Research Needs
Related to Water for Energy. October 20-22, 1974. (from Chris Shafer's
files)

Hollenstein, Gene H. Research Needs Related to Hydrologic Aspects
of Water for Energy from Large Energy Complexes. Prepared for the OWRT
Workshop on "Research Needs Related to Water for Energy," Indianapolis,
Indiana, October 20-22, 1974. (from Chris Shafer's files)

228. Great Lakes Basin Commission. The Coastal Zone and Power in the Great
Lakes Basin. August 1, .1974. Prepared by: Chris A. Shafer. (from
Chris Shafer's files)'

229. U.S. Bureau of Mines. Effluent Treatment and its Cost for the Synthane
Coal-to-S.N.G. Process. Prepared by,Joseph P. Starkey, Jr., Albert J.
Forney, William P. Haynes and Kenneth D. Plants. (from Chris Shafer's file)

230. Water For Energy Self-Sufficiency. August 1974. Prepared by the United
States Water Resources Council. (from Chris Shafer.'s files)

231. U.S. Water Resources Council. Water for Energy.Self-Sufficiency Report
(from Chris Shafer's files)

232. New York. Chapter I: Rules of Procedure, Subchapter-. E. Certificates of
Environmental Compatibility and Public Need for Steam Electric Generating.
,Facilities.

233. New York. Chapter 1: Rules of Procedure, Subchapter E-1. Long-Range
Electric System Planning.

234. Council of State Governments. States' Role in Radioactive Material
Management.. A workshop held D er 9-11, 1974, in Las Vegas, Nevada.

235. Pennsylvania State University. Center for the Study of Environmental Policy.
Energy Parks and the Commonwealth of Pennsylvania - Issues and Recommendations.
Volume 2: Appendices. July 1975.

498

236. Pennsylvania Carnegie-Mellon University, School of Urban & Public Affairs.
'Power Plant Siting Policy Alternatives for Pennsylvania. May 4, 1976.
237. Council of State Governments. State Responses to-the Energy Crisis.
March 1974.

238. Council of State Governments. State Energy Management: The California
Eneray Resources Conservation and Development Commission. May 1976.

239. Boeing Commercial Airplane Company. Intercity Passenger Transportation
.Data: Service and Economic Comparisons@ Volume I. May, 1975.

240. Boeing Commercial Airplane Company. Intercity Passenger Transportation
Data': Energy Comparisons, Volume 2. May, 1975.

241. New York Dept. of Transportation. Introductory Materials to the
Comprehensive Upstate New York Ports Study. April 8, 1975.

242.. New York Dept. of Transportation. Preliminary Progress Report: New York
State Dept. of Transportation Upstate Public'Ports Study. Phase I Report.
July, 1975.

243. U.S. Army Corps of Engineers, North Central Division. Great Lakes/St.
Lawrence Seaway Traffic Forecast Study. Summary Report. February, 1976.

244. Massachusetts, Berkshire County Regional Planning Commission. Evaluation
of Power Facilities: A Reviewer's Handbook. April, 1974.

245. Texas (University of), Petroleum Extension Service. Introduction to the
Oil Pipeline Industry. May, 1966.

246. Texas (University of), Petroleum Extension Service. Oil Pipeline Construc-
tion and.Maintenance, Volume II. April, 1973.,

247. Oak Ridge National Laboratory. Ecology and Resource Economics: An
Integration and Application of Theory to Environmental Dilemmas.
April, 1971.

248. Federal Power Commission. Hydroelectric Power Resources of the United
States--Developed and Undeveloped. January 1, 1972.

249. Department of Transportation. Energy Primer: Selected Transportation
Topics. 1975.

250. Michigan University, Dept. of Naval Architecture and Marine Engineering.
Optimum Capacity of Ships and Port Terminals. December, 1973..

251. Wisconsin University, Center for Great Lakes Studies. Wisconsin's Great
Lakes Ports: Background and Future Alternatives. July, 1975.

252. Michigan Geological Survey. Michigan's Oil and Gas Fields, 1974. 1975.

499

253. New York Power Authority. Greene County Nuclear Power Plant Environmental
Report, Construction Permit Stage, Vol. 1. 1975.

254. New York Power Authority. Revision No. 1, Green e County Nuclear Power
Plant Environmental Report, Construction Permit Stage, Vol. 1. 1975.

.255. New York Power Authority. Revision No. 2, Greene County Nuclear Power
Plant Environmental Report, Construction Permit Stage, Vol. 1. 1975.

256. Department of the Interior. Alaskan Natural Gas Transportation Systems:
Economic and Risk Analysis, Conclusions and Results. June, 1975.

257. Federal Power Commission. Alaska Natural Gas Transportation Systems
Draft Environmental Impact Statement, Vol. I. November, 1975.

258. Federal Power Commission. Alaska Natural Gas Transportation Systems:
Draft Environmental Impact Statement, Vol. II. November, 1975.

259. Federal Power Commission. Alaska Natural Gas Transportation Systems:
Draft Environmental laact Statement, Vol. III. -November, 1975.

260. Department of the Interior. Alaska Natural Gas Transportation System,
Final Environmental Impact Statement: Overview. March, 1976.

261. Department of the Interior. Alaska Natural Gas Transportation System,
Final Environmental impact Statement: North Border. March, 1976.

262. Department of the Interior. Alaska Natural Gas Transportation System,@
Final Environmental IMact Statement: Alternatives. March,.1976.

Department of the Interior. Alaska Natural Ga s Transportation System,
Draft Environmental Impact Statement: Part I, Vol. 1, Overview.
June, 1975.

264. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement. Part III, Vol. 1. Canada.
June, 1975.

Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement: Part III, Vol. 2, Canada.
June, 1975.

266. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement. Part III, Vol. 3, Canada.
June, 1975.

267. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement: Part V*, Vol. 1, North Border.
June, 1975.

268. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement. Part V, Vol. 2, North@Border.
June, 1975.

500

269. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement. Part V, Vol. 3. June, 1975.

270. Department of the Interior. Alaska.Natural Gas transportation System,
Draft Environmental Impact Statement. Part VI, Vol. 1,.Alternatives.
June, 1975.

271. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement. Part VI, Vol.. 2, Alternatives.
June, 1975.

272. Department of the Interior. Alaska Natural Gas Transportation System,
Draft Environmental Impact Statement, Part VII, Vol. 1, Consultation
and Coordination. June, 1975..

273. Rand Corporation. Electricity Generating Cost Model for Comparison of
California Power Plant Siting Alternatives. Prepared for the California
State Assembly-with Support From the Rockefeller Foundation. January,
1973.

274. U.S. Energy Research and Development Administration. ERDA Energy Research
Abstracts. Vol. 1, No. 6. June, 1976.

California (State) Coastal Zone Conservation Commission. Energy. Adopted
January 21, 1975.

*276. California (State) Coastal Zone Conservation Commission. Energy: An
Overview and the Potential for Conservation, Volume I. Preliminary Draft.
Compiled by State and Regional Commission Staff. July, 1974.

*277. Ca lifornia (State) Coastal Zone Conservation Commission. Energy: Petroleum
and Natural Gas: Demand and Supply, Volume II. Preliminary Draft.
Compiled by State and Regional Commission Staff. August, 1974.

*278. California (State) Coastal Zone Conservation Commission. Energy: Alterna-
tive Energy Sources, Volume III., Preliminary Draft. Compiled by State
and Regional Commission Staff.

*279. California (State) Coastal Zone Conservation Commission. Energy: Elec-
trical Energy and Power Plants. Preliminary Draft. Compiled by State
and Regional Commission Staff. July, 1974.

*280. California (State) Coastal Zone Conservation Commission. Energy: Petroleum
Development, Volume V. Preliminary Draft. Compiled by State and Regional
Commission Staff. July, 1974.

281. Wisconsin University. Center for Great Lakes Studies. Center for Great
Lakes Studies, Special Report No. 23: Analysis of International Great
Lakes Shipping and Hinterland. April, 1975.'

282. U.S. Army Corps of Engineers. "Origin-Destination Study of Bulk Commodity
Movement, Upper Great Lakes Region",*Chapter III--Minerals Industry. By
Paul H. Mutschler and Donald Klyce, Eastern Field Operation Center,
Pittsburgh, Pennsylvania. 1972.

283. Water Resources Commission, "Michigan Energy Facilities,Related Laws,
Policies, and Regulations.
Draft Report not adopted by California (State) Coastal Zone Conservation Commission.

501

284. U.S. Council on Environmental Quality. OCS Oil and Gas--An Environmental
Assessment. A Report to the President by the Council on Environmental
Quality. Volume 2. April, 1974.

285. U.S. Council on Environmental Quali ,ty. @OCS Oil and Gas--An Environmental
Assessment.' A Report to the President by the Council on Environmental
Quality. Volume 4. April, 1974.

286. Environmental Protection Agency. Federal Register. "Steam Electric
Power Generating Point Source Category", Volume 39, Number 196.
October 8, 1974.

287. Environmental Protection Agency. Development Document for Best Technology,
Available for the Location, Design,, Construction and Capacity of Cooling
Water Intake Structures for Minimizing Adverse Environmental Impact.
April, 1976.

Federal Power Commission. Statistics of Publicly Owned Electric Utilities
in the'United States. 1974.

289. Federal Power Commission. Steam-.Electric Plant Air and Water Quality
Control Data: Summary Report. For the Year Ended December 31, 1973.
Based on FPC Form No. 67. January, 1976.

290. Lake Carriers. Association. Annual Report: Lake Carriers' Association.
1975.
291. Bureau of Mines. Fuel and Energy bata: United States by States and
Region, 1972. Bureau of Mines Information Circular, 1974.

292. California (State) Coastal Zone Conservation Commission. Energy, Tanker
Terminals, Refineries, Ing Facilities, Volume VI. Preliminary Draft.
Compiled by State and Regional Commission Staff. July, 1974. Draft
Report not adopted by California (State) Coastal,Zone Conservation
Commission.

293. Morris, Greg. Department of Natural Resources. "Use of Energy Systems
Concepts in Evaluating Resource,Management Alternatives inPuerto Rico".
Presented at the Joint National Meeting of the Operations Research Society
of America, and the Institute of,Management Sciences. October 16-18,
1974, San Juan, Puerto Rico.,

U.S. Geological Survey. Resource and Land Investigations (RALI).Program
Methodologies for Environmental Analysis. Volume III: Power Plant Siting.
(Microfish)

295. U.S. 94th Congress, 2d Session. H.S. 14236. An Act Making appropriations
for public works for water andpower development and energy research,
including the Corps of Engineers... June 16, 1976.

502

296. U.S. 94th Congress, 2d Session. H.R. 14236 (With Amendments). An Act
Making appropriations for public,works for water and power,development and
energy research, including the Corps of Engineers ... July 17, 1976.

297. U.S. 94th Congress, 2d Session.. H.R. 14394. A Bill to extend the Federal
Energy Administration Act of 1974 until September 30, 1976. June 16, 1976.

298. U.S. 94tfi Congress, 2d Se ssion. H.R. 14377. A Bill to establish within
the Energy Research and Development Administration a.program of Federal
grants to assist States in carrying out solar energy community utility
programs. June 15, 1976.

299. U.S. Army Corps of Engineers, St. Paul District. Ship Unloading Facility
Lake.Superior and Ishpeming Railroad Co.*,Final Environmental Impact
Statement. Presque Isle Harbor, Marquette, Michigan. October, 1974.

300. U.S. Atomic Energy Commission. Comparative Risk-Cost-Benefit Study of
Alternative Sources of Electrical Energy. Appendix A: -Energy Expenditures
Ass'ociated with Electric.Power Production by Nuclear and Fossil Fueled
Power Plants. December, 1974.

301. Federal Power Commission. The CRO 1974 Generating Unit/Capacity Data
Consisting of a PSA Generating Unit.Summary Section, A PSA Generating
Unit Detail Section'and an FPC map of the Commission Power Supply Areas.

302. Federal Power Commission. The CRO Summary Tabulation by PSA, of 1974
Annual Electric Requirements.

303. Federal Power Commission. The CRO tabulation of "Scheduled or Planned.
Changes in Installed Generating Capacity" dated January 1, 1976.

.304. Federal Power Commission. The NYRO tabulation of "Summary of Scheduled
or Proposed Addition in Capacity" dated January 1, 1976.

305. Wisconsin University. Center for Urban Transportation Studies. Studies
in Urban Transportation: An Inventory of Organizational Responsibilities
for Ports on the Great Lakes. September, 1974.

306. Mid-Continent Area Power Pool. Western Coal Utilization in.the,Mid-
Continent Area Power Pool: A Preliminary Assessment Performed for the.
Mid-Continent Area Power Pool. Prepared by Bechtel Corporation. May,
1975.

307. Upper Midwest.douncil. Northern Great Plains Coal: Conflicts and Options
in Decision Making. April, 1976.

308. Atomic Energy Commission, Washington. WASH 1345 UNCLAS, "Power Plant Capital
Costs; Current Trends and Sensitivity to Economic Parameters'% October,
.1974. USAtC Oakridge National Laboratories.

503

309. Sward, John D. Unitrain Operating Methods and Costs. Presented at the
University of Michigan, Department of Naval Architecture and Marine
Engineering, Ann Arbor, Michigan. October 25, 1972.

310. Glover, T.O.,.Hinkle, M.E., and Riley, H.L. Unit Train Transportation of
Coal: Technology and Description of Nine Representative Operations.
Information Circular 8444. 1970.

311. Petruschell,' R.L. and Salter, R.G. Electricity Generating Cost Model
for Comparison of California Power Plant Siting Alternatives. Prepared
for the California State Assembly,with Support from the Rockefeller
Foundation. January, 1973.

312. Anderson, Kent P. and DeHaven, James C. The Long-Run Marginal Costs of
Energy. Prepared under grants from the National Science Foundation.
February, 1975.-

313. Atomic Energy Commission and Resources Agency of the State of California..
California Power Plant Siting Study: Executive Summary Volume I.
May, 1973.

314. Atomic Energy Commission and Resources Agency of the State of California.
California Power Plant Siting Study. Volume II. May, 1973.

315. Atomic Energy Conmissionand Resources Agency of the State of California.
California Power Plant Siting Study: Appendixes. Volume III. May, 1973.

316. Gordon, Richard L. U.S. Coal and the Electric Power Industry * Published
for Resources for the Future, Inc. By the Johns Hopkins University Press.
1975.

317. U.S. Department of theInterior, Bureau of Mines. 1972 Minerals Yearbook.
Volume 11. 1974.

318. U.S. Department of the Interior, Bureau of Mines. Bitumenous Coal and
Lignite Distribution, Calendar Year 1975. Prepared in Division of Fossil Fuels.
April 12, 1976.

319. U.S. Department.of the Interior, Bureau of Mines. Crude Petrol eum, Petroleum
Products and Natural Gas'Liquids, December 1975. Prepared in Division of
Fossil Fuels. April,21, 1976.

320. U.S. Department of the Interior, Bureau of Mines. The Mineral Industry of
Indiana in 1975. Prepared by the'State Liaison Program Office. December 31,
1975.

321. Indiana Department of Natural Resources. Oil Development and Production in
Indiana During 1974. Geological Survey.Mineral Economics Series 2. 1975.

322. Job, Charles A. 'Energy Production, Generation, and Transportation in the
Great lakes Region, with Emphasis on Electrical Energy, Generation in the
Coastal Zone. Background Paper, Draft. May 10, 1976.

504

323. American Petroleum Institute Annual Statistical Review. Petroleum Industry
Statistics. 1965-1974.- Washington, D.C. May 1975-

324. The Office of the Ten Year Forecast, Ohio Power Siting Commission.
Review of 1975 Forecast Rej_)brts. -January, 1976.

325 Federal Energy Administration. FEA Region V Report --- Scheduled Electric
Generating Capacity Additions-Steam 1976-1985-

326. U.S. Department of the Interior, Bureau of Mines. Crude Petroleum,
Petroleum-Products, and Natural Gas Liquids. 1974. (final summary).
Prepared by the Division of Fuels Data. April 1, 1976.

327. U.S. Department of the Interior, Bureau of Mines. Mineral Industry
Surveys. Coal-Bitumenous and Lignite in 1974. Prepared in Division of
Fossil Fuels. January 27, 1976.

328. Northeast Utilities. What are the 1981-1984 base-load alternativesope
to the Northeast Utilities system?

329. U. S. Department of the Interior, Bureau of.Mines. Long-Distance Coal
Transport: Unit Trains or Slurry Pipelines. 1975.

330. U.S. Department of the Interior, Bureau of Mines. Basic Estimated
Capital Investment and Operating Costs for Underground Bituminous Coal Mines.
1975.

U.S. Department of the Interior, Bureau of Mines Railroad Volume Freight
Rates Evolution and Analysis. By Thomas C. Campbell and Sidney Katell.
April 1976.

332. Campbell, Thomas C., Professor of Economics and Research Associate,
Regional Research Institute, West Virginia University. The Coal Slurry
.Pipeline: Its Contribution in Meeting the Nation's Energy Requirements.
Presented at the Missouri Valley Economic Association Conference, Tulsa,
Oklahoma, February 26-28, 1976.

333. Regional Research Institute, West Virginia University. Transporting
Western Coal: Unit Train or Slurry Pipeline. By Thomas C. Campbell
Reprint Series X, No. 4 from "The Logistics and Transportation Review,
Vol. 11, No. 2 (Summer 1975)

334. Regional Research Institute, West Virginia University. Status of Slurry
Pipeline Transportation of Bituminous Coal. by Thomas C.-Campbell. -
Presented at the Intersociety Conference on Transportation, Atlanta, Ga.
July 14-18, 1975.

335. U.S. Environmental Protection Agency. Symposium Proceedings: Environmental
Aspects of Fuel Conversion Technology, II. (December 1975, HOllywood, Fla.)
June 1976.

505

336. U.S. Environmental Protection Agency. Proceedings: Symposium on Flue
-Gas Desulfurization, New Orleans, March 1976. Vol. II. May 1976.

337. U.S. Environmental Protection Agency. Proc eedings@: Symposium on Flue
Gas Desulfurization, New Orelans, March 1976, Vol. I. May 1976.

338. Tetra Tech, Inc. 1976 Energy Fact Book.

339. Cargo, David N. and Bob F. Mallory. Man and his Geologic Environment. 1974.

340. Mitre Corporation. Quantitative Environmental Comparison of Coal and
Nuclear Generation Workshop Summary. Sponsored by Office of Energy
R&D Policy National Science Foundation. September, 1975.

341. Mitre Corporation. Electric Utility Financial Problems and Potential
Solutions. February7, 1-976.

342. Mitre Corporation. Proceedings of Legal and Institutional Problems of
Electrical Facility Siting Workshop. June, 1975.

343. Mitre Corporation. Legal and Institutional Problems of Electrical
Facility Siting. May, 1975.,

344. Mitre Corporation. Proceedings of Workshop on Increasing Efficiency and-
Effectiveness in Ele@c_trical Power Generation. February, 1976.

345. National Science Foundation, Office of the Science Advisor. Minutes and
Summary of the First Meeting,,of the Advisory Committee on Energy Facility
Siting: Volume I., November 20, 1974.

346. National Science Foundation, Office of the Science Advisor. Proceedings
of the First Meeting of the Advisory Committee on Energy Facility Siting:
Volume II. November 20, 1974.

347. National Science Foundation, Office of Energy R&D Policy. An Agenda for
Research and Development on Energy Systems: Volume I, Summary and
Recommendations. February, 1974.

348. National Science Foundation, Office of Energy R&D Policy. Proceedings of
Meeting of Advisory Committee on Energy Facility Sit ing Held on October 24,
1975. February, 1976.

349. Michigan (State of), Governor's Advisory Commission on Electric Power
Alternatives. 'I. Preliminary Report for Public Discussion, Facts and
Recommendations. April, 1976.

350. Pennsylvania State University. Economic Analysis of Coal Supply: An
Assessment of Existing Studies Research Project 335, Key Phase Report.
Prepared for Electric Power Research Institute. May, 1975.

506

351. Hoffman-Muntner Corporation. Engineering/Economic Analyses of Coal
Preparation with S02 Cleanup Processes for Keeping Higher Sulfur Coals
in the Energy Market. Prepared for United States Bureau of Mines.
Appendix B: Distribution of N. Appalachian and Midwest Region Coals to
Utilities During 1974. June,_1976.

352. Stiles, C.A.; Carlson, E.S.; and Peterson, T.C. Mining Congress Journal,
"Rail Versus Truck Haulage at Erie Mining Co.". May, 1972.

353. Burton, Alan K., Bechtel Corp. Society of Mining Engineering. "Capital-
and Operating Parameters for Off-Highway Trucks". Part 5 of a five-part
series. January, 1976.

354. Northeast Power Coordinating Council. Northeast Power Coordinating
Council.

355. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Transcript of First Public
Hearing. Denver, Colorado. August 6-9, 1974.

356. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administ@ation Project Independence Blueprint Final Task Force Report,
Water Requirements, Availabilities, Constraints, and Recommended Federal
Actions. November, 1974.

357. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint'Final Task Force Report,
Water Requirements, Availabilities, Constraints, and Recommended Federal
Actions. November, 1974.

358. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report,
Synthetic Fuels from Coal. November, 1974.

359. U.S. Federal Energy Administration. Pro ect Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report,
Nuclear Energy. November, 1974.

360. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report--
Finance, Financing Project Independence, Financing Requirements of the
Energy Industries, and Capital Needs and Policy Choices in the Energy
Industries. November, 1974.

361. U.S. Federal Energy Administration. Pro ect Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report,
Facilities. November, 1974.

362. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report,
Energy Conservation in the Manufacturing Sector 1954-1990-.. Volume 3..
November, 1974.,

363. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Final Task Force Report,
Coal. November, 1974.

507

364. U.S Federal Energy Administration. Project Independence: Federal Energy
Administration, Project Independence Report., November, 1974.

365. U.S. Federal Energy Administration. Project Independence: Federal Energy
Administration Project Independence Blueprint Transcript of Second Public
Hearing, New York, New York, August 19-22, 1974.

366. U.S. Federal Energy Administration ' Project Independence: Federal Energy
Administration, A Summary. November, 1974.

367. U.S. Federal Energy Administration. Energy Independence Act of 1975 and
Related Tax Proposals, Draft Environmental Impact Statement. March, 1975.

368. U.S. Federal Energy Administration. The Data Base: The Potential for
Energy Conservation in Nine Selected Industries. Volume 2, Petroleum
Refining, First Edition. September, 1974.

369. U.S. Federal Energy Administration. The Analysis of the Economic Environ-
ment for the Report to Congress'on Petrochemicals.

370. Radian Corporation., Final Report: A Program to Investigate Various
Factors in Refinery Siting. Submitted to Council on Environmental Quality
and Environmental Protection Agency. Prepared by Radian Staff. Radian
Contract #100-0.29. February 15, 1974.

371. State of Maine, Department of Environment Protection. Alteration of
Coastal Wetlands. Maine Revised Statutes Annotated, Title 38, Chapter 3.
October, 1975.,

372. State of Maine., Department of Environmental Protection. Protection and
Improvement of Air. Maine Revised Statutes Annotated,Title 38, Chapter
4. October, 1975.

373. State of Maine, Department of Environmental Protection. Oil Discharge
Prevention and Pollution Control. Maine Revised Statutes Annotated,
Title 38, Chapter 3. October, 1975.

374. State of Maine, Department of Environmental Protection. Protection and
Improvement of Waters. Maine Revised Statutes Annotated, Title 38,
Chapter 3. October, 1975.

375. Anual Area Power Coordinating Group. Davis-Besse Nuclear Power Station
Units, No. 2 and 3: Environmental Report, Volume 3.

376. State of-Maine., Department of Environmental Protection. Site Location
of Development. Maine Revised Statutes Annotated, Title 38, Chapter 3.
October, 1975.

377. State of Maine, Department of Environmental Protection. Classification
of Surface Waters. Maine Revised Statutes Annotated, Title 38, Chapter 3.
October, 1975.

378. U.S. Atomic Energy Commission. Greenwood Energy Center,, Units 2 & 3:
Applicant's Environmental Report Construction Permit Stage, Volume 2.
1974.

508

379. U.S. Atomic Energy Commission. Greenwood Energy Center, Units 2 & 3:
Applicant's Environmental Report Construction Permit Stage, Volume 3.
1974.

380. Clark, John and Brownell, Willard. Electric'-P owe.r Plants in the Coastal
Zone:- E.n.vironmental Issues. American Littoral Society Special Publication
No. 7. October, 1973.

381. Pennsylvania. Drexel University. Environmental Planning Seminar,
December 9-13, 1974. Presentation by Peter M. Stern.

382. Bureau of National Affairs, Inc. Enei gy Users Report. 1976.

383. U.S. Environmental Protection Agency. Implementation Plan Review for
Michigan as Required by the Energy Supply and Environmental Coordination
Act. February, 1975.

384. U.S. Environmental Protection Agency. Implementation Plan Review for
Illinois as Required by the Energy Supply and Environmental Coordination
Act. February, 1975.

385. U.S. Environmental Protection Agency. Implementation Plan Review for
Wisconsin as Required by the Energy Supply and Environmental Coordination
Act. March, 1975.

386. U.S. Environmental Protection Agency. Implementation Plan Review for.
Minnesota as Required-by the En ergy Supply and Environmental Coordination
Act. March, 1975.

387. U.S. Environmental Protection Agency. Implementation Plan Review for
Indiana as Required by the Energy Supply and Environmental Coordination
Act. December, 1974.

388. U.S. Environmental Protection Agency. Implementation Plan Review'for
Ohio as Required by the Energy Supply and Environmental Coordination
Act. December, 1974.

389. Argonne National Laboratory, Energy and Environmental Systems Division.
Air Quality Policy Analysis of Electric Utilities: A Regional Persp .ective.
By: R. Bright, K. Croke, J. Hoover, K. Hub, D. Schregardus, and P. Walker.

390. Argonne National Laboratory. Energy and Environmental Systems Division.

391. Weston Environmental Consultants-Designers. Coal Transshipment Facility,
Superior, Wisconsin: Environmental Impact Report. Prepared for ORTRAN,
Inc. July, 1974.

392. Weston Environmental Consultantg-Designers., Coal Transshipment Facility,
Superior, Wisconsin: Appendices. Prepared for ORTRAN,,Inc. July, 1974.

393. Michigan (State) Public Service@Commisslon. Environmental Protection,
Study. Prepared for the Michigan Public Service Commission. May, 1975.

509

394. Michigan (State) Public Service Commission. Michigan Public Service
Commission: Evaluation of the Consumers Power and Detroit Edison
1974 Load Growth Forecasts. February, 1975.

395. Michigan (State) Public Service Commission. Michigan Public Service
Commission: Economic Analysis of Reductions in Power Plant Construc-
tion in Michigan. October, 1974.

396. Michigan (State) Public Service Commission. Summary Report on
Proceedings:' Hearings on Electric Energy Availability and System
Reliability. September 4-5-6, 1974.

39.7. Illinois University. Energy Resources . Center. Nuclear Power in Illinois:
Proceedings of the Third Annual Illinois Energy Conference. September 11-12,
1975.

398. Illinois University. Energy Resources Center. Energy'Conservation Policy
Options for Illinois: Proceedings of the Second Annual Illinois Energy
Conference. June 24-25,1 1974.

399. U.S. National Science Foundation. Some Considerations in the Use of
Cooling Water for Inland Power Plant Sites in California. (microfish)

400. U.S. Council on Environmental Quality. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use. Volume II. (Microfish)

401. U.S. Council on Environmental Quality. Environmental Impacts, Efficiency,
and Cost of Energy Supply and End Use. Volume I. (Microfish).

402. U.S. Environmental Protection Agency. By. Charles L. Jedlicka. Nomographs
for Thermal Pollution Control Systems. Prepared for: Office of Research
and Development. U.S. Environmental Protection Agency. September 1973.

403. Department of Natural Rd.Gources. Oil Development and Production in
Indiana During 1975. Geological S urvey Mineral Economics Series 22. 1976.

404. State of Michigan. Governor's Advisory Commission on Electric Power
Alternatives. Preliminary Report I. April 1976.

405. Michigan State University Dept. of Resource Development. Michigan G!:eat
Lakes Shoreland Zone Boundary Definition. June 1975.

406. American Association for the Advancement of Science. Energy: Use
Conservation and Supply. 1974,

40.7. Federal Energy Administration. National Energy.Information Center.
Monthly Energy Review. June 1976.

408. Maryland Department of Natural Resources. By Frederick W. Jones. Record
of,the Maryland Power Plant Siting Act. "Forecasting theDemahd for
Electricity. July, 1976.

510

409. Federal Energy Administration. Energy Research and Development
Adminstration. Energy Abstracts for Policy Analysis. Vol. 2., No. 7.
Abstracts 1062-1271. July 1976.

410. 94th Congress, 2nd Session. House of Representatives * Report together
with Additional Views (Including cost estimate of the Congressional
Budget Office) To accompany H.R. 13676. Report No. 94-1348. National
Energy Extension Service Act of 1976. July 19, 1976.

411. 94th Congress 2nd Session. House of Representatives. Report together
with Additional and Dissenting Views. Loan Guarantees for Demonstration
of New Energy Technologies. To accompany H.R. 12112. Report No. 94-1170,
Part 2. June 18, 1976.

412. Information from Ontario Hydra. Energy-Saving Program Cuts Consumption
by 15%. August 19, 1976.

.413. U.S. Geological Survey. (1) Industrial Fuel Conference October 8-9, 1975.
Purdue.University. (2) Update on Fuel Reserves and Resources - 1974-1975.

U.S. Geological Survey., (1) Industrial Fuel Conference - October 2-3,
1974, Purdue University. (2) Overview of Energy Resources in the Midwest.

415. National Electric Reliability Council. 6th Annual Review of Overall Reliabilit
and Adequacy of tl@e N. American Bulk Power Systems. July, 1976.

416. U.S. Federal Energy Administration. National Energy Information Center.
Quarterly Report: Fourth Quarter 1975. Energy Information Report to
Congress..

417. Channing L. Bete Co., Inc. What Everyone Should Know About Coal
Gasification. 1974.

418. U.S. Energy Research and Development Administration. Nuclear Science
Abstracts. Volume 33, No. 9. Abstracts 19643-22696. May 15, 1976.

419., U.S. Energy Research and Development Administration. Nuclear Science
Abstracts. Volume 33, No. 8, Abstracts 16483-19642. April 30, 1976.

420. U..S. Environmental Protection Agency. Program Overviews. "Environmental
Control Technology Health and Environmental Effects." December 1975.
421. National Electric Reliability Council. Fossil and Nuclear Fuel for
Electric Utility Generation: Requirements and Constraints, 1976-1985.
June, 1976.

422. U.S. Environmental Protection Agency. The Bioenvironmental Impact of a
Coal-Fired Power Plant: First interim Report, Colstrip, Montana-
December, 1974. Ecological Research Series. January, 1976.

423. U.S. Environmental Protection Agency. The Bioenvironmental Impact of a
Coal-Fired Power Plant: Second Interim Report, Colstrip, Montana-
June, 1975. Ecological Research Series. February, 1976.

511

424. U.S. Environmental Protection Agency. The Bioenvironmental Impact of
Air Pollution From Fossil-Fuel Power Plants. Ecological Research Series.
August, 1974.

425.-Michigan University. Power Systems Laboratory. A Social Systems
Engineering Approach to Electric Power System Planning. By Arthur S.
Bechhoefer, Kan Chen, Mark K. Enns. Winter, 1975.

426. Geological Survey. Circular 645. A Procedure for Evaluating Environmental
Impact. By Luna B. Leopold, Frank E. Clarke, Bruce B. Hanshaw, and James R.
Balsley. Washington, 1971.

427. American Nuclear Society. Transactions-Conference on Nuclear Power
Plant Siting, August 25-28, 1974. Sponsored by the American Nuclear
Society's Power Division and the Oregon Local Section. 1974.

428. U.S. Federal Energy Administration. Trends in Refinery.Capaci@ty and
Utilization. June, 1976.

429. The Southern Interstate Nuclear Board. The Objectives and Institutional
Mechanisms of a Regional Approach to Nuclear Power Plant Siting. Final,
Report. December 15, 1975.

430. Argonne National Lab)oratory. SITE: A Methodology for Assessment of Energy
Facility Siting.PatterTfs. August, 1975.

431. The University of Michigan, Department of Naval Architecture and Marine
Engineering. Great Lakes Transport of Western Coal: Technical and
Economic Analysis. Report to Department of Commerce Maritime Administration.
By Volker H. Elste and Robert M. Scher. June, 1976.

432. Argonne National Laboratory. Air Quality Policy Analysis of Electric
Utilities: A Regional Perspective. March, 1975.

433. Argonne National Laboratory. Flue Gas Desulfurization and Its'Alternatives:
The State of the Art. By Arthur P. Hurter, Jr. November, 1974.

434. Isard, Walter. Location and Space-Economy: A General Theory Relating to
Industrial Location, Market Areas, Land Use,_Trade, and Urban Structure.

435. Wisconsin University, Center for Urban Transportation Studies. Studies
in Urban Transportation: An Examination of the Effects of Changes in Rail
Transport Technology Upon Great Lakes Bulk Shipping Activity.

436. U.S. Army.Corps of Engineers. Office of the Chief.@ National Shoreline
Study. Volume V. June 29, 1973.

437. U.S. Dept. of Transportation. Energy Statistics: A Supplement to the
Summary of National Transportation Statistics. Final Report. August, 1974.

438. The Mitre Corporation. Energy Self-Sufficiency: How Much and How Soon?
March, 1975.

512

439. Orba CorporAtion., Bulk Handling System Simulation A Window on Reality.
February 26, 1974.

440.:.Galatin, M.,.Economies of Scale and Technological Change in Thermal Power
Generation.

441. Environmental.Protection Agency. Reviewing Environmental Impa ct Statements
Power Plant Cooling Systems, Engineering Aspects. October, 1973.

442. U.S. Office of Science and Technology. Considerations Affecting Ste m
Power Plant'Site Selection.

443. U.S. Army Corps of Engineers, St. Paul District. Draft Environmental
Impact Statement: Power Plant Discharge Structure,'Delta Stabilization
Dike, and On-Land Taconite Tailings Disposal. March, 1976.

444. Coordinating Committee for North Central Power Study. North Central
Power Study. Report of Phase I, Volume 1. October,, 1971.

445. Ohio- Energy Emergency Commission. Final Repo-rt to the General Assembly.
October 28, 1975.'

446. Argonne National Laboratory. Methodological Aspects of Forecasting
Electricity.Demand. By J.D. Cavallo, G.C. Krohm and W.T. Pelletier.
May 27, 1976.

447. Argonne National Laboratory. Candidate Scenarios for the National Coal
Assessment. September 1, 1976.
448.' New York Power Pool. Nuc"lear Electric Power for th6'Empire State.
June, 1976.

449. New York Power Pool. Report of Member Electric Systems of the New York
Power-Pool. Volume 1. 1976.

.450.'New.York Power Pool. "Report of Member,Electric Systems of-the New York
Power Pool. Volume 2. 1976.

451. Berkshire County Regional Planning Commission. Evaluation of Power
Facilities: A Reviewer.'s Handbook. April, 1974.

@452. Gilmore, John S. Science, Vol. 1919 "Boom Towns May Hinder Energy Resource
Development". Pages 535-540. February, 1976.

453. Schuster, Ray..-"PMC Digs, in.to'Build the Breeder", Power.Engineeririg,
Pages 59-64. April., 1974.

454. Sider, Don. "The Big Boondoggle at Lordstown", Fortune Magazine.
Pages 106-109; 195-196. September, 1969.

455. U.S. Federal Power Commission. Federal Power Commission. Annual
Report, 1975.

456. Baram, Michael S. Environmental Law and the Siting of Facilities:
Issues in Land Use and Coastal Zone Management. 1976.

457. Governorls Advisory Commission on Electric Power Alternatives. Final
Report: Facts and Recommendations. August, 1976.

458. U.S. Department of the Interior. Mining and Minerals Policy. Annual
Report of the Secretary of the Interior. 1976.

459. U.S. Department of the Interior. Laws and Regulations Affecting Coal.

460. Illinois (State) Geological Survey. Direc tory of Illinois Mineral
Producers, 1974. July, 19.76.

461. U.S. Energy Research & Development Administration. Energy Trails: A
Guidebook Describing Energy Sites, Power Plants, Science Museums, and
Other Interesting Places.' Volume 1. 1976.

462. The Marshall-Wythe School of Law' College of William and Mary in
Virginia. William and Mary Law @eview, Volume 16, Number 4. Summer,
1975.

463. Power Planning Committee, Pacific Northwest River Basins Commission.
Reivew of Power Planning in the Pacific Northwest. 1975.

464. U.S. Environmental Protection Agency. Who's Who in the Interagency
Energy/Environment R&D Program. June, 1976.

465. Pennsylvania.:.Electric 'Company. Pennsylvania Electric Company Presentation
to Girard Township Supervisors. February 10, 1976.

466. ECAR Environmental Advisory Panel. ECAR Summary Report of Permit and
Contact Requirements of ECAR Members. November 15, 1972.

467. Lentz, Owen A., Executive Manager, ECAR. Presentation before the
Pennsylvania Public Utility'Commission in re Further Hearings on
Investigation Docket No. 138 "Investigation Upon the Commission's Own
Motion to Determine the Need for Additional Electric Generating Transmission
Facilities During the Next Decade". March 10, 1976.
468.,Oak Ridge National Laboratory. Energy Division, Annual Progress Report--
Period Ending December 31, 1974.

469. Oak Ridge National Laboratory. Energy Division, Annual Progress Report--
Period Ending December 31, 1975.

470. Oak Ridge National Laboratory. Toward a Regional Power Plant Siting
Method: AEC-Maryland Regional Siting Factors Study. FY 1974 Progress.
Report.

471. U.S. Environmental Protection Agency. Implementation Plan Review for
New York as Required by the Energy Supply and Environmental Coordination
Act. April, 1975.

514

472. U.S. Environmental Protection Agency. Implementation Plan Review for
Pennsylvania as Required by the.Energy Supply and Environmental Coordination
Act. 'February, 1975.
473.,'U.S. Environmental Protection Agency. National Summary of State Implemen-
tation Plan Reviews (Section 4 ESECA), Volume 1--Synopsis. July, 1975.

474. U.S. Environmental Protection Agency. National Summary of Statte
Implementation Plan Reviews (Section 4 ESECA), Volume II--Technical
Support Document. July; 1975.

475. U.S. Office of Coastal Zone Management. Living Coastal Resources.
476. U.S. Environmental Protection Agency. Federal Interagency Energy/
Environment Research and Development Program--Status Report II. June,
1976.

477. Tennessee Valley Authority, Office of Power. Comparison of Coal-Fired
and Nuclear Power Plants for the TVA System. June, 1966.

478. Spangler,@Miller B. U.S. Atomic Energy Commission. The Basis for
Standards in Cost-Benefit Analysis in Nuclear Power Plant Licensing
Actions. November 29, 1973.

479. Spangler, Miller B. Division of Nuclear Reactor Regulation, U.S.
Nuclear Regulatory Commission. Probabilistic Methods of AssessinA
Risk in Cost-Benefit Analysis,of Nuclear Power Plants and Alternative
Energy Sources. June 26, 1975.

480. Spangler, Miller B. Cost-Benefit Analysis Branch, U.S. Nuclear
Regulatory Commission. An Appraisal of Future Energy.Developments
Affecting the National and Regional Economic Outlook for Nuclear-
Generated Electricity During the Next Forty Years. March 1, 1976.

481. Abel, Fred H. Balancing Environmental Quality, Energy Use and Growth:
Difficult Decisions. 1975.

482. Abel, Fred H.9, Tihansky,-Dennis P.; Walsh, Richard G. National Benefits
of Water Pollution Control. 1975.

483. Abel, Fred H. Determining Acceptable Levels of Health and Environmental
Damages. 1975.

484. D.P. Cleary, S.N. Salomon, L.A. Pollnow, and M.B. Spangler. A Preliminary
Matrix Model for Quantifying and Balancing the Socio- -Economic Impact of
Alternative Cooling System Technologies for Nuclear Power Plants. 1975.

485. Department of Housing and Urban Development. Rapid Growth from Energy
Projects: Ideas for State and Local Action. A Program Guide.

486. State of California. 'Onshore Impact of offshore Southern California OCS
Sale No. 35. Executive Summary.
487. Resources and Land Investigations (RALI) Program. Directory to U. IS.
Geological Survey Program Activities in Coastal Areas 1974-76. Geological
Survey Bulletin 1428.

515

488. Madison Gas & Electric Company, Wisconsin Electric Power Company System,
Wisconsin Power & Light Company, and Wisconsin Public Service Corporation.
1976 Advance Plan.

489. Argonne National Laboratory, Energy and Environmental Systems Division.
A Preliminary Program Plan for Community Systems: 'Factors Influencing
the Acceptance of New Energy-Efficient Community Design Concepts and
Energy Supply Systems. January*, 1976.

490. Federal Energy Administration,, Office of Oil and Gas. Crude Oil Supply
Alternatives for the Norther n Tier States. August, 1976.

491. U.S. Energy Research and Development Administration. A Preliminary Program
Plan for Community Systems: Advanced Technology Mix Energy Systems (ATMES).
January, 1976.

492. Dr. Paul W. McCracken, William G. Rosenberg, and Dr. Gerald L. Decker.
Energy Industrial Center Study. Executive Committee Summary Report and
Policy Proposals. Prepared for the Office of Energy R&D Policy, National
Science Foundation. June, 1975.

493. Bonner & Moore Associates, Inc. Petroleum Supply Alternatives for the
Northern'Tier States Through 1977, Volume III, Short-Term Report.
August-4,, 1976.

494. Stanford Research Institute. Meeting Wisconsin's Energy Requirements---
1975 to 2000. Volume 1, Summary and Conclusions. April, 1975.

495. Scott, David L. Pollution in the Electric Power Industry: Its Control
.and Costs.

496. Brookhaven National Laboratory. A Perspective on the Energy Future
.of the Northeast: Health and Environmental Impacts of Alternative
Energy Futures for the Northeast. March 16-17, 1976.

497. Organization for Economic Co-operation and Development. Environmental
Damage Costs. Record of a Seminar held at the OECD in August 1972.

498. Brookhaven National Laboratory, Departments of-Applied Science and.-
Medicine. The Health and Environmental Effects of Electricity Generation.
A Preliminary Report by the Biomedical and Environmental Assessment Group.
July 30, 1974.

499. Meier, Peter M., and Palmedo, Philip F. A Preliminary Assessment of a
Hypothetical Nuclear Energy Center in New Jersey. Draft. October, 1975.

500. Morgan, M. Granger. Brookhaven National Laboratory. Some Methodological
Issues in Estimating the Social Costs of the Energy System. A Preliminary
Report. June, 1975.

501. Brookhaven National Laboratory. ERDA/National Laboratories Workshop on
Environmental Effects of Energy hold at Rockefeller University, New York,
New York. September 4-5, 1975.

502. New England Regional Commission. Gas Industry Development in_New England:
Analysis of Alternatives. Part IV,, Decision Guidelines and Development
Alternatives. November, 1975.

516

503. New England Regional Commission. Gas Industry Developm. ent in New England:
Analysis of Alternatives. Parts I, II,JII. November, 1975.

504..New England Regional Commission. Petroleum Development in New England:
Economic and Environmental Considerations. Volume One of Four Volumes:
Executive Summary. November, 1975.

505. New England Regional Commission. Petroleum Development in New England:
Economic and Environmental Considerations. Volume Two of Four Volumes:
Modular Results. November, 1975.

506. New England Regional Commission. Petroleum Development in New-England:
Economic and@Environmental Considerations. Volume Three of FourVolumes:
Regional Factors. November, 1975.

507. New England Regional Commission. Petroleum Development in New England:,
Economic and Environmental Considerations. Volume Four of Four Volumes:
.Appendices. November, 1975.

508. New England Regional Commission. Decision Mik ing.for Energy Facilities
in New England: Institutional and Legal Process. December, 1975.

509. Ohio Power Siting Commission. The Mead Corporation Chillicothe, Ohio
Facility Ten Year Electric Demand Forecasts. 1976.

510. Ohio Power Siting Commission. Duquesne Light Company, 1976. Ten Year
Forecast Report Submitted to tb Ohio Power Sit Iing 'Commission.

511. Ohio Power Siting Commission. The Cincinnati Gas and Electric Company.
Ten Year Forecast Report to the Ohio Power Siting Commission. 1976.

512. Ohio Power Siting Commission. Ohio Valley Electric Corporation: Ten
Year Forecast Report to the Oldo Power Siting Commission. 1976.

513. Ohio Power Siting Commission. Columbus and Southern Ohio Electric
Company: Ten Year Forecast Report to the Ohio Power Siting Commission.
76.

514. Ohio Power Siting Commission. 1975 Key Ohio Electric Utility Statistics.

515. Ohio Power Siting Commission. The Cleveland Electric Illuminating Co.
Ten Year Forecast Report to the Ohio Power Siting Commission. 1976.

516. Ohio Power Siting Commission. Monongahela Power Company Ten-Year Forecast
Report to the Ohio Power Sitlaa Commission. April 15, 1976.

517. Ohio Power Siting Commission. The Goodyear Tire and Rubber Company,
Akron Facility: Ten Year Electric Demand Forecasts. 1976.

518. Ohio Power Siting Commission. PPG Industries: Ten Year Forecast
Repott to the Ohio Power Siting Commission.

519. Ohio Power Siting Commission. Union Carbide Corporation Power Station:
Ten Year Forecast Report to the Ohio Power Siting Commission.
April 15, 1976.

517

520. Institute for Contemporary Studies. No Time to Confuse. A Critique of
the Final Report of the Energy Policy Project of the Ford Foundation:
A,Time to Choose America's Energy Future. .1975.

521. U.S. 94th Congress. Ist Session. S enate. Air Quality and Stationary
Source Emission Control. A Report by the Commission on Natural Resources
National Academy of Sciences, National Academy of,Engineering, National
Research Council. March, 1975.

522. Chess er, Al H. Economic Advantages of Transporting Coal by Rail vs.
Coal Slurry Pipeline. June, 1976.-

523. Environmental Protection Agency. Air Quality Implementation Plans:
Prevention of Significant Air Quality Deterioration. Federal Register
Volume 39, Number 235, Part III. December 5, 1974.

524. Environmental Protection Agency. Environmental News. November 27, 1974.

525. U.S. 91st Congress, H.R. 17255.' The Clean Air Act Amendments of 1970.
December 31, 1970.

526. Commonwealth Associates, Inc., Landplan Systems Division. Environmental
Report on the Belle River Power Generating Facilities, St. Clair County,
Michigan. Prepared forlthe Detroit Edison Company. April 8, 1974.

527. Zeni, L.E. Electrical World, "Maryland Pioneers with State Siting Program",
April 1, 19 Volume 185, Number 7, p. 30-33.

528. Central Electricity Generating Board. Modern Power Station Practice.
Second Revised and Enlarged Edition. Volume 1.

529. Decker, Gerald L. The Dow Chemical Company. Power Plant Design Considera-
tions for Energy Conservation. 1975.

530. Wisconsin University, Institute for Environmental Studies. 1975 Survey
of Energy Use in Wisconsin, May, 1976.

531. U.S. Federal'Power Commission. Alaska Natural Gas Transportation Systems:
Final Environmental Impact Statement. September, 1976.

532. Burlington Northern, Inc. Statement of Louis W. Menk, Chairman and
Chief Executive Officer, Burlington Northern Inc., Before the House
Committee on Interior.and Insular Affairs. H.R. 1863, 2220, 2553, and
2896.

533. Ohio Power Siting Commission'. Ten Year Forecast of Electric Generation
and Transmission Facilities,- 1976-1986. Submitted by Buckeye Power,
Inc. April 15, 1976.

534. U.S. Federal Power Commission. The Adequacy of Future Electric Power
Supply: Problems and Policies. Technical Advisory Committee on the
Impact of Inadequate Electric Power Supply. March, 1976.

518

Greenwood, John 0. Gree nwo-od's Guide to Great Lakes Shipping. April,
1975.

536. U.S. Army Corps of Engineers. Waterborne Commerce of the United States.
Calendar Year 1974.

537. New York Coastal Zone Management Program. Land and Water Uses. July,
1976.

538. U.S. 94th Congress, lst Session, Senate. Air Quality and Stationary
-Source Emission Control.. March, 1975.

539. U.S. Army Corps of Engineers, St. Paul District. 'Draft Environmental
Impact Statement. Units 7, 8,& 9, Presque Isle Generating Station
Upper Peninsula Generating Co. March, 1976.

540. U.S. Dept. of the Interior. Feasibility of Alternative Means.of
Cooling for Thermal Power Plants Near Lake Michigan. September, 1970.

541. Bechtel Corporation. Manpower, Materials, and Capital Costs 'for Energy-
Related Facilities. Research Sponsored by Brookhaven National Laboratory
Associated Universities, Inc. April, 1976.,

542. Dukert, Joseph M. Nuclear Power and the Environment. 1976.

543. Committee for Economic Development. Nuclear Energy and National,Security.
A Statement by the Research and Policy Committee of the Committee for
Economic Development. September, 1976.

544. National Academy of Engineering. Engineering for Resolution of the Energy-
Environment Dilemma. 1972.

545. Battelle Columbus Lakes, Ohio. Environmental Considerations in Future
Energy. April, 1971.

546. Argonne National Laboratory. Proceedings of the Second Federal Conference
on the Great Lakes. March.25-27, 1975.

547. Federal Power Commission. Annual Summary of Cost and Quality of Steam-
Electric Plant Fuels 1975. May, 1976.

548. National Academy of Sciences. Port Development in the United States.
Washington, D.C. 1976.

549. Coastal Zone Laboratory. Appendix-A: Eng-in.eering-Economic Analysis of
Shore Protection Systems: A Benefit/Cost Model.

550. U.S. Bureau of Mines. Long-Distance Coal Transport: Unit Trains or
Slurry Pipelines. 1975.

551. Detroit Edison. Enrico Fermi Atomic Power Plant, Unit 2. Applicant's
Environmental Report Operating License Stage, Volume 2.

.519

552. Wisconsin Electric Power Company. Environmental Report: Pleasant Prairie
Power Plant, Units 1 and 2,'Volume 1. February, 1975.

553. Wisconsin Electric Power Company. Environmental Report:. Pleasant Prairie
Power Plant, Units 1 and 2, Volume 2. February, 1975.

554. Wisconsin University. Institute for Environmental Studies. Energy Systems
Forecasting, Planning and Pricing. Proceedings of a French-American
Conference University of Wisconsin-Madison, 23 September - 3 October, 1974.

555. U.S. Energy Research & Development Administration. A National Plan for Energy
Research, Development & Demonstration: Creating Energy Choices for the
Future. Volume 1: The Plan.

556. New York. Cornell University. Center for Environmental Quality Mgmt.
Cornell Energy_Project. Summary of Present Status of High Voltage D.-C.
Transmission,. By Simpson Linke. December,- 1974.

557. New York. Cornell University. Center for Environmental Quality Mgmt.
Cornell Energy Project. On the Minimum Size of Natural-Draft Dry Cooling
Towers for Large Power Plants. By Franklin K. Moore. August, 1972.

558. New York. Cornell,.University. Center for Environmental Quality Mgmt.
Cornell Energy Project. A Pricing System for Pollution Control. By
J.E. Hass. March, 1972.

559. New York. Cornell University. Center for for Environmental Quality M gmt.
Cornell Energy Project. A Critique of the New EPA Emission Standards for
New Stationary Sources. By C.R. Aleta. October, 1971.

560. New York. Cornell University. Center for Environmental Quality Mgmt.
Cornell Energy Project. Cost Comparison Between Natural Gasand Electricity.
By Rob Hogue. June, 1971.

561. New York. Cornell University. Center for Environmental Quality Mgmt I
Cornell Energy Project. Electric Utility Optimum Mix Model. By K.B. Cady
and J. Hass. January, 1971.'

562. U.S. Nuclear Regulatory Commission. Final Environmental Statement Related
to Manufacture of Floating Nuclear Power Plants by Offshore Power Systems.
Volume 1. September 1976.

563. U.S. Nuclear Regulatory Commission. Final Environmental Statement Related
to Manufacture of Floating Nuclear Power Plants'by Offshore Power Systems,
Volume 2. September 1976.

564. U.S. Bureau of Reclamation. Construc'tion Cost Trends. January 1976.-

565, New York Dept. of Transportation. Upstate Public Ports Study, Volume I,
Market Potential: Phase I. September 1976.

566. New York Dept. of Transportation. Upstate Public Ports Study, Volume II,
Market Potential: Phase II. September 1976.

567. New York Dept. of Transportation. Upstate Public Ports Study, Volume III,
Port Development Plans and,Policies. September 1976.

520

568. Illinois Coastal Zone Management Program. Energy.
569. Argonne National Laborator y. Air Quality Policy Analysis of Electric
Utilities: A Regional Perspective. March, 197.5.

570. U.S. Nuclear Regulatory Commission. -Regulatory Guide 4.7: General Site
Suitability Criteria for Nuclear Power Stations. November 1975.

571. Argonne National Laboratory. A Study of Social Costs for Alternative Means
of Electrical Power Generation for 1980 and 1990. Prepared for Atomic
Energy Commission. February 1973.

572. Comar, C.L. and Sagan, L.A. Health Aspects of Energy Production and
Conversion.

573. Wisconsin Electric Power Company. Environmental Report: Pleasant
Prairie Power Plant, Units 1 and 2, Volume 1. February 1975.

574. Wisconsin Electric Power Company. Environmental Report: Pleasant
Prairie Power Plant, Units 1 and 2, Volume 2. February 1975.

575. Energy Research & Development Administration. Annual Report for 1975:
Laramie Energy Research Center. January, 1976.

576. Department of the Interior. Energy Perspectives 2. June 1076.

577. Environmental Protection Agency. Fuel and Energy Production by Bioconver-
sion of Waste Materials. State-Of-The-Art. August 1976.

578. U.S. 94th Congress, 2nd Session. Senate. ERDA Energy Conservation Programs.
March 5, 1976.

579. U.S. 94th Congress, 2nd Session. Senate. Federal Energy Reorganization:
Issues and Options. Report to the Committee on Government Operations.
September, 1976.

580. Department of the Interior. Leasing and Management of Energy Resources
on the Outer Continental Shelf.

581. U.S. 94th Congress, 2d Session. Coastal Zone Management Act Amendments of
1976. Report of the Committee of Conference on S. 586. June 24, 1976.

582. U.S. 92nd Congress, S. 3507. Public Law 92-583: Coastal Zone Management
'Act of 1972. October 27, 1972.

583.. U.S. Army Corps of Engineers. The Port of Chicago, Illinois. Port
Series No. 46. Revised 1975.. Washington, D.C.

584. U.S. Army Corps of Engineers. The Port. of Detroit and Ports on-the.
Saginaw River Michigan-. Port Series No. 45, Revised 1972. Washington,
D.C.

585. Department of Transportation. Energy Statistics: A Supplement to the
Summary of National Transportation Statistics. August, 1974.

521

U.S. Bureau of Mines. Minerals Yearbook 1973.. Volume II, Area Reports:
Domestic. Washington, D.C. 1976.

587 National Aeronautics and Space Administration. ECAS--Westinghouse Phase I
Final Report. Volume I-Introduction and Summary-and General Assumptions.

588. National Aeronautics and Space Administration. ECAS--Westinghouse-Phase-I
Final Report. Volume II-Materials Considerations..

589. National Aeronautics and Space Administration. ECAS--Westinghouse'Phase I
Final Report. Volume III--Combustors,-Furnaces and Low BTU Gasifiers.

590. National Aeronautics and Space Administration. ECAS--Westinghouse Phase I
Final Report. Volume IV--Open Recuperated and Bottomed Gas Turbine Cycles.

591. National Aeronautics and Space Administration. ECAS--Westinghou-se Phase I
Final Report. Volume V--Combined Gas-Steam Turbine Cycles.

592. National Aeronautics and Space Administration. ECAS--Westingho use Phase I
Final Report. Volume VI".-Closed-Cycle Gas Turbine Systems..

.593. National Aeronautics and.Space Administration. ECAS--Westinghou�e Phase I
Final Report. Volume VII--Metal Vapor Rankine Topping-Steam And Bottoming
Cycles.

.594.. National Aeronautics and Space Administration... ECAS--Westinghouse Phase I
Final Report. Volume.VIII---@Open-Cycle MHD.

595. National Aeronautics and Space Administrationi ECAS-Westinghouse Phase I
Final Report. Volume IX--Closed-Cycle MHD.

596. National Aeronautics and Space Administration. ECAS--Westinghouse Phase-I
Final.Report. Volume X--Liquid-Metal,MHD-Systems.

597. National Aeronautics and Space Administration. ECAS--Westinghouse Phase I
Final Report. Volume XI--Advanced Steam Systems.

598. National Aeronautics and'Space-Administration. ECAS--Westi ngh6use Phase I
Final Report. Volume XII--Fuel Cells.

599. U.S. DPA. Methods for Identifying and Evaluating the Nature and Extent of
Nonpoint.,Sources of Pollutants. 1973.

600. Peelle, Elizabeth. Socioeconomic Effects of Operating Reactors on Two Host
Communities: A Case Study of Pilgrim and Millstone.. Presented at
Conference on Land Use and Nuclear Facility Sit,.ing: Current Issues.
Sponsored by Atomic Industrial Forum, Denver, Colorado. July 18-21, 1976.

601. Peelle, Elizabeth. Social Effects of Nuclear Power Plants. 1974.

602. Young' Loise B-. Power Over People. 1973.

522

603. Department of the Interior. Water Quality Critera. Report of National
Technical Advisory Committee.

604. Department of the Interior. Bituminous Coal and Lignite Distribution
Calendar Year 1975. April 12, 1976.

605. World Ports/American Seaport. "Superior's Mammoth Coal Terminal.
September, 1975.

606. U.S. Army Corps of Engineers. Ports on Lake Michigani Part 2. 1974.

607. Great Lakes Basin Commission. Appendix 12: Shore Use and Erosion

608. Consumers Power Company. Environmental Report, Volume 3: Quanicassee
Plant, Units 1 & 2. February,.1974.

609. Eichholz, Geoffrey. Environmental Aspects of Nuclear Power.

610. New York State University. Sea Grant Project. Visual Quality and the
.Coastal Zone: Conference Proceedings.

611. U.S. Department of the Interior. The Need for a National System of
Transportation and Utility Corridors. July 1,,1975.
612.. U.S. Department of the Interior. Environmental Criter Iia for Electric
Transmission Systems. 1970.

613. Special Committee on Electric Power and the Environment. Electricity and
.the Environment: The Reform of Legal Institutions. A Report of the
Association of the Bar of the City of New York.

614. U.S. Atomic Energy Commission. Final Environmental Statement. Related to
Operation of Davis-Besse Nuclear Power Station, Unit 1. Proposed by
Toledo Edison Company. October 1975.

615. Armstrong,.John R. and Bensky, Lawrence. Energy: The Institutional
Question. February, 1975.

616. U.S. 94th Congress. 2nd Session. Senate. Land Use and Energy: A Study
of Interrelationships. January,1976.

617. Edsall, T.A. "Electric Power Generation and Its Influence on Great Lakes
Fish". By Argonne National Laboratory: Proceedings of the Second Federal
Conference on the Great Lakes.

618. Asbury, J.G. "Future Fossil Energy Requirements in the Great Lakes Basin
State." Argonne National Laboratory: Proceedings of the Second Federal
Conference on the Great Lakes.

523

619. Wisconsin Planning Office. Energy: The Institutional Question.
Prepared by Lawrence Bensky and John R. Armstrong. February 1975.

@620. Federal Power Commission. The Thermal Component of Atlantic Coast
Estuarine Environments. 1974.

621. Federal Power Commission. Energy Technology III: Regional Energy
Systems-Planning. 1976.
622. A Statement of Concerns and Suggested Ecological Research, Report
No. 1 of the Lake Michigan Cooling Water Studies Panel. Panel supported
by the United States Environmental Protection Agency, Region V, and the
Pollution Control Agencies.of Illinois, Indiana, Michigan, and Wisconsin.
1975.

623. U.S. Department of Commerce. "Energy Impact Complicates Coastal Manage-
ment Problem", Commerce America, pp. 4-6. October 11, 1976.

624. Environmental Protection Agency. "Steam Electric Power Generating Point
Source Category- Effluent Guidelines and Standards". Federal Register.
Title 40, Chapter 1, Subchapter N, Part 423. Volume 39, No. 196, Part III..
Tuesday, October 8, 1974.
625. Energ' Research and Development Administration. Role of Transportation
y
in the Nuclear Fuel Cycle, report to the Michigan Environmental Review
Board at its July, 1976, meeting, Lansing, Michigan.

626. Environmental Protection Agency. 'Federal Register., Vol. 41, No. 81,
"Effluent Guidelines", Title 40, Chapter 1, Part 401/402. Monday,
April 26, 1976.

627. Environmental Protection Agency. "Thermal Discharges", Title 40,
Chapter 1, Part 122. Federal Register, Voluem 39, No. 196, Part II.
Tuesday, October 8, 1974.

628. U.S. Environmental Protection Agency. Development Document for Best
Technology Available for the Location, Design, Constructiong and
Cap city of Cooling Water Intake Structures for Minimizing Adverse
Environmental Impact. April, 1976.

629. Federal Register. "208 Planning Rules. Appendix C, 40 CFR Part 130
and 131: Policies and Procedures for Continuing Planning Process,
Preparation of Water Quality Management Plans.", Vol. 40, No 230.
Friday, November 28, 1975-@

630. Environmental Protection Agency. Coordination of Coastal Zone Management
Plans and.Air Quality,Implementation Plans. August, 1976.

631. U.S. 94th Congress. 2nd Session. Senate. Legislative History of the
Coastal Zone Management Act of 1972, as Amended in 1974 and 1976 with
a Section-by-Section Index. December 1976.

524

632. U.S. Department of Commerce, National Oceanic and Atmospheric Administration,
,"Notice of Final Rulemaki,ng, Coastal Zone Management Program Development
Grants": Federal Register, Vol. 38, No. 229, November 29, 1973.

633. U.S. Department of Commerce, National Oceanic and Atmospheric Administration,
"Notice of Final Rulemaking, Coastal Zone Management Program Administrative
Grants":.Federal Register, Vol. 40, No. 6, January 9, 1975.

634. U.S. Department of Commerce, National Oceanic and Atmospheric Administration,
"Proposed Regulations, Federal Consistency with Approved Coastal Zone
Management Programs": Federal Register, September 28, 1976.

635. U.S. Department of Commerce, National Oceanic and Atmospheric Administration,
"'Proposed Regulations for Financial Assistance to Coastal States, Coastal
Energy Impact Program": Federal Register, October 22, 1976.

636. U.S. Department of Commerce, National Oceanic and Atmospheric Administration,
"Program Development Grants, Coastal Zone Management": Federal Register,
December 6. 1976.

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