E conomic Assessment
Environmental impact
Statement
NESHAPS for Radionuclides
Background Information
Document — Volume 3
Printed on Recycled Paper
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40 CFR Part 61
National Emission Standards
for Hazardous Air Pollutants
EPA 520/1-39-007
Economic Assessment
Environmental Impact Statement
for NESHAPS Radionuclides
VOLUME 3
BACKGROUND INFORMATION DOCUMENT
September 1989
U.S. Environmental Protection Agency
Office of R^di^tixon Proc[rdins
Washington, D.C. 20460
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Preface
The Environmental Protection Agency is promulgating National
Emission Standards for Hazardous Air Pollutants (NESHAPs) for
Radionuclides. An Environmental Impact Statement (EIS) has been
prepared in support of the rulemaking. The EIS consists of the
following three volumes;
VOLUME I - Risk Assessment Methodology
This document contains chapters on hazard
identification, movement of radionuclides through
environmental pathways, radiation dosimetry,
estimating the risk of health effects resulting from
expose to low levels of ionizing radiation, and a
summary of the uncertainties in calculations of dose
and risks.
VOLUME II - Risk Assessments
This document contains a chapter on each radionuclide
source category studied. The chapters include an
introduction, category description, process
description, control technology, health impact
assessment, supplemental control technology, and cost.
It has an appendix which contains the inputs to all
the computer runs used to generate the risk
assessment.
VOLUME III - Economic Assessment
This document has chapters on each radionuclide source
category studied. Each chapter includes an
introduction, industry profile, summary of emissions,
risk levels, the benefits and costs of emission
controls, and economic impact evaluations.
Copies of the EIS in whole or in part are available to all
interested persons? an announcement of the availability appears in
the Federal Register. For additional information, contact James
Hardin at (202) 475-9610 or write to:
Director, Criteria and Standards Division
Office of Radiation Programs (ANR-460)
Environmental Protection Agency
401 M Street, SW
Washington, DC 20460
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LIST OF PREPARERS
Various staff members from EPA's Office of Radiation Programs
contributed in the development and preparation of the EIS,
Terrence McLaughlin
James Hardin
Byron Bunger
Fran Cohen
Albert Colli
Larry Gray
W. Daniel Hendricks
Paul Magno
Christopher B. Nelson
Dr. Neal S. Nelson
Barry Parks
Dr. Jerome Pushkin
Jack L. Russell
Dr. James T. Walker
Larry Weinstock
Chief, Environmental
Standards Branch
Health Physicist
Economist
Attorney Advisor
Environmental
Scientist
Environmental
Scientist
Environmental
Scientist
Environmental
Scientist
Environmental
Scientist
Radiobiologist
Health Physicist
Chief Bioeffects
Analysis Branch
Engineer
Radiation
Biophysicist
Attorney Advisor
Project Officer
Author/Reviewer
Reviewer
Author/Reviewer
Author/Reviewer
Reviewer
Author/Reviewer
Author
Author
Reviewer
Author/Reviewer
Author/Reviewer
Author
Reviewer
An EPA contractor, S. Cohen and Associates, Inc., McLean, VA,
provided significant technical support in the preparation of the
EIS.
v
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INTRODUCTION
The purpose of this report is to analyze the economic factors affecting the regulation of radionuclides
in the twelve categories listed below. For each category, the industry was profiled and analyses
regarding the cost of applying the controls suggested in the Volume II of the Background Information
Document, the cost effectiveness of the controls, and their effect on production costs and on regional
and local economies were performed.
The categories considered were:
1. The Uranium Fuel Cycle Facilities
2. Underground Uranium Mines
3. Inactive Uranium Mill Tailings
4. Licensed Uranium Mill Tailings
5. High-Level Waste Disposal Facilities
6. Department of Energy Facilities
7. Department of Energy Radon Facilities
8. Elemental Phosphorus
9. Phosphogypsum Stacks
10. Coal Fired Boilers
11. Nuclear Regulatory Commission Licensed and non-DOE Federal Facilities
12. Surface Uranium Mines
The data regarding the control options was developed for Volume II and was incorporated into the
economic analysis. Other economic data was gathered from public available information.
vii
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TABLE OF CONTENTS
£&£§.
PREFACE iii
LIST OF PREPARERS v
INTRODUCTION vii
TABLE OF CONTENTS . . ix
LIST OF TABLES xviii
LIST OF FIGURES xxix
1. URANIUM FUEL CYCLE FACILITIES 1-1
1.1 Introduction and Summary 1-1
1.2 Industry Profile 1-2
1.2.1 Introduction 1-2
1.2.2 Uranium Mills 1-2
1.2.3 Uranium Conversion Facilities 1-2
1.2.4 Fuel Fabrication Facilities 1-5
1.2.5 Light Water Power Reactors 1-5
1.3 Current Emissions, Risk Levels, and Feasible Controls Methods 1-5
1.3.1 Introduction 1-5
1.3.2 Current Emissions and Estimated Risk Levels 1-7
1.3.2.1 Uranium Mills . 1-7
1.3.2.2 Uranium Fuei Conversion Facilities 1-9
1.3.2.3 Uranium Fuel Fabrication Facilities 1-9
1.3.2.4 Nuclear Power Reactors 1-13
1.3.3 Control Technologies 1-13
1.3.3.1 Uranium Mills . 1-13
1.3.3.2 Uranium Conversion Facilities 1-15
1.3.3.3 Uranium Fuel Fabrication Facilities 1-15
1.3.3.4 Nuclear Power Reactors 1-15
1.4 Industry Cost and Economic Impact Analysis 1-16
REFERENCES 1-17
2. UNDERGROUND URANIUM MINES 2-1
2,1 Introduction 2-1
ix
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TABLE OF CONTENTS
Ess®
2.2 Industry Profile 2-1
2.2.1 Demand 2-1
2.2.2 Sources of Supply , . 2-2
2.2.2.1 Domestic Production 2-2
2.2.2.2 Imports 2-3
2.2.2.3 Inventories 2-3
2.2.2.4 Secondary Market Transactions 2-3
2.2.3 Financial Analysis 2-4
2.2.3.1 Homestake Mining Company 2-4
2.2.3.2 Rio Algoni 2-5
2.2.3.3 Plateau Resources Limited 2-5
2.2.3.4 Western Nuclear 2-5
2.2.4 Industry Forecast and Outlook 2-6
2.2.4.1 Projections of Domestic Production 2-6
2.2.4.2 Near-Term Projections 2-7
2.3 Current Emissions, Risk Levels, and Feasible Control Methods 2-8
2.3.1 Introduction 2-8
2.3.2 Current Emissions and Estimated Risk Levels 2-8
2.3.3 Control Technologies . 2-8
2.3.3.1 Introduction 2-8
2.3.3.2 Alternative One 2-11
2.3.3.3 Alternative Two 2-13
2.4 Analysis of Benefits and Costs 2-13
2.4.1 Introduction 2-13
2.4.2 Least-Cost Control Technologies . 2-13
2.4.3 Benefits of Control Alternatives 2-21
2.4.4 Costs of Control Alternatives 2-21
2.4.5 Sensitivity Analysis 2-21
2.5 Industry Cost and Economic Impact Analysis 2-28
2.5.1 Introduction 2-28
2.5.2 Production Cost Impacts 2-28
2.5.3 Economic Impact Analysis 2-28
2.5.4 Regulatory Flexibility Analysis 2-30
REFERENCES 2-31
3. INACTIVE MILL TAILINGS 3-1
3.1 Introduction and Summary . 3-1
/ 3.1.1 Rulemaking History and Current Regulations . 3-1
3.2 Inactive Industry Profile 3-3
3.2.1 Current Status of Inactive Mills 3-3
3.2.2 Use of Inactive Mill Sites 3-3
3.3 Current Emissions, Risks, and Control Methods 3-5
x
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TABLE OF CONTENTS
Ism
3.3.1 Current Emissions and Estimated Risk Levels 3-6
3.3.1.1 Development of the Radon Source Terms 3-6
3.3.1.2 Demographic and Meteorological Data 3-6
3.3.1.3 Exposures and Risks to Nearby Individuals 3-8
3.3.1.4 Exposures and Risks to the Regional Population 3-8
3.3.1.5 Exposures and Risks under Alternative Standards 3-8
3.3.1.6 Distribution of Fatal Cancer risk 3-12
3.3.2 Control Technologies . . 3-12
3.4 Analysis of Benefits and Costs 3-15
3.4.1 Benefits 3-16
3.4.2 Costs 3-16
3.5 Economic Impact Analysis 3-25
REFERENCES ..... 3-28
LICENSED MILL TAILINGS 4-1
4.1 Introduction and Summary .4-1
4.1.1 Rulemaking History and Current Regulations 4-2
4.2 Industry Profile 4-3
4.2.1 Demand 4-3
4.2.1.1 Uranium Uses . 4-5
4.2.2 Sources of Supply 4-10
4.2.3 Industry Structure and Performance . 4-21
4.2.4 Economic and Financial Characteristics 4-24
4.2.4.1 Employment Analysis 4-24
4.2.4.2 Community Impact Analysis 4-26
4.2.4.3 Financial Analysis 4-27
4.2.5 Industry Forecast and Outlook 4-31
4.2.5.1 Projections of Domestic Production 4-33
4.2.5.2 Near-Term Projections 4-34
4.2.6 Evaluation of Forecasts and Uranium Market Demand 4-36
4.2.6.1 Domestic Uranium Resources 4-36
4.2.6.2 Total Electricity Generation 4-42
4.2.6.3 Employment Projections 4-44
4.3 Current Emissions, Risks, and Control Methods 4-4?
4,3.1 Current Emissions and Estimated Risk Levels 4-49
4.3.1.1 Methodology for the Assessment of Risks
from Operating and Standby Mills 4-49
4.3.1.2 Methodology for the Assessment of
Post-disposal Risks 4-53
4.3.1.3 Methodology for the Assessment of Risks
from New Impoundments. 4-56
xi
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TABLE OF CONTENTS
Page
4.3.1.4 Exposures and Risks from. Operating and
Standby Mills 4-56
4.3.1.5 Post-disposa! Exposures and Risks 4-59
4.3.2 Technologies for Long-term Post-disposal Emission Control ......... 4-63
4.4 Analysis of Benefits and Costs 4-65
4.4.1 Benefits and Costs of Reducing Allowable Limits From 20 pCi/m2/sec . 4-66
4.4.1.1 Benefits of Reducing the Allowable Limits 4-66
4.4.1.2 Costs of Reducing the Allowable Limits 4-67
4.4.2 Benefit And Costs of Reducing Allowable Emissions During Operations 4-73
4.4.2.1 Methods of Reducing Allowable Limits to 20 pCi/mVsec .... 4-73
4.4.2.2 Benefits of Reducing Allowable Limits to 20 pCi/m /sec .... 4-75
4.4.2.3 Costs of Reducing Allowable Limits to 20 pCi/m2/sec ...... 4-75
4.4.3 Analysis of Benefits and Costs of Promulgating Future Work
Practice Standards 4-77
4.4.3.1 Work Practices for New Tailings Impoundments ........... 4-80
4.4.3.2 Comparison of Control Technologies for
New Tailings Impoundments -. . 4-81
4.4.3.3 Benefits of Promulgating Future Work Practice Standards .... 4-82
4.4.3.4 Costs of Promulgating Future Work Practice Standards 4-89
4.5 Economic Impacts 4-95
4.5.1 Increased Production Cost 4-95
4.5.2 Regulatory Flexibility Analysis 4-98
REFERENCES 4-101
5. HIGH-LEVEL WASTE DISPOSAL 5-1
5.1 Introduction and Summary 5-1
5.2 Industry Profile . 5-1
5.2.1 Introduction 5-1
5.2.2 Facilities for the Ultimate Disposal of High-Level Waste 5-2
5.2.2.1 The Waste Isolation Pilot Plant (WIPP) 5-2
5.2.2.2 Yucca Mountain Geologic Repository 5-2
5.2.3 Demand for High-Level Waste Storage 5-2
5.2.4 Supply of High-Level Waste Storage 5-3
5.3 Current Emissions, Risk Levels and Feasible Control Methods 5-3
5.3.1 Introduction 5-3
5.3.2 Current Emissions and Estimated Risk 5-3
5.3.3 Control Technologies 5-4
5.4 Analysis of Benefits and Costs 5-4
5.4.1 Introduction 5-4
5.4.2 Least-Cost Control Technologies 5-4
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TABLE OF CONTENTS
Eagfi
5.4.3 Health and Other Benefits 5-5
5.5 Industry Cost and Economic Impact Analysis 5-5
REFERENCES 5-6
6. DEPARTMENT OF ENERGY FACILITIES 6-1
6.1 Introduction and Summary 6-1
6.2 Industry Profile .6-1
6.3 Current Risk Levels, and Feasible Control Methods 6-3
6.3.1 Introduction 6-3
6.3.2 Facility Descriptions 6-3
6.3.3 Control Technologies 6-6
6.4 Analysis of Benefits and Costs 6-7
6.4.1 Introduction 6-7
6.4.2 Cost of Control Technologies 6-7
6.4.3 Health and Other Benefits 6-10
6.5 Industry Cost and Economic Impacts 6-11
REFERENCES ..... 6-12
7. DEPARTMENT OF ENERGY RADON SITES 7-1
7.1 Introduction and Summary 7-1
7.2 Industry Profile 7-1
7.2.1 Feed Materials Production Center (FMPC) . 7-2
7.2.2 Niagara Falls Storage Site (NFSS) 7-2
7.2.3 Weldon Spring Site (WSS) 7-2
7.2.4 Middlesex Sampling Plant (MSP) .. 7-3
7.2.5 Monticello Uranium Mill Tailings (MUMT) Pile 7-4
7.3 Current Emission, Risk Levels, and Feasible Control Methods 7-4
7.3.1 Introduction 7-4
7.3.2 Current Emissions and Estimated Risk Levels 7-4
7.3.2.1 FMPC 7-4
7.3.2.2 NFSS - 7-7
7.3.2.3 WSS 7-7
7.3.2.4 MSP 7-7
7.3.2.5 MUMT - 7-8
7.3.3 Control Technologies 7-8
7.4 Analysis of Benefits and Costs 7-9
7.4.1 Costs and Benefits of Meeting Various Radon Flux Rates 7-9
7.4.1.1 FMPC 7-10
xiii
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TABLE OF CONTENTS
Page
7.4.1.2 NFSS 7-10
7.4.1.3 WSS 7-10
7.4.1.4 MSP 7-14
7.4.1.5 MUMT 7-14
7.4.2 Sensitivity Analysis 7-14
7.5 Industry Cost and Economic Impact Analysis 7-15
REFERENCES - 7-19
8. ELEMENTAL PHOSPHORUS PLANTS 8-1
8.1 Introduction and Summary . 8-1
8.2 Industry Profile 8-3
8.2.1 Demand 8-3
8.2.2 Supply 8-7
8.2.2.1 Monsanto Company 8-10
8.2.2.2 FMC Corporation 8-13
8.2.2.3 Rhdne-Poulenc (Stauffer) 8-13
8.2.2.4 Occidental Petroleum Corporation 8-18
8.2.3 Competitive Products and Processes 8-18
8.2.4 Economic and Financial Characteristics 8-20
8.2.4.1 Prices 8-21
8.2.4.2 Employment . 8-21
8.2.5 Outlook 8-21
8.3 Current Emissions, Risk Levels, and Feasible Control Methods . 8-24
8.3.1 Current Emissions and Estimated Risk Levels 8-25
8.3.1.1 Process Description 8-25
8.3.1.2 Existing Effluent Controls 8-26
8.3.1.3 Emissions 8-26
8.3.2 Control Technologies for Elemental Phosphorus Plants ............. 8-31
8.3.3 Cost of Control Technologies 8-32
8.3.3.1 Venturi Scrubber Cost Assumptions 8-33
8.3.3.2 Wet ESP Cost Assumptions 8-34
8.3.3.3 SD/FF Cost Assumptions 8-34
8.3.3.4 HEPA Filter Cost Assumptions 8-35
8.3.4 Emissions Control Alternatives 8-36
8.3.5 Performance of Control Alternatives 8-38
8.4 Analysis of Benefits and Costs 8-39
8.4.1 Benefits of Po-210 Emissions Control 8-39
8.4.2 Costs of Po-210 Emissions Control 8-50
8.4.3 Estimates of Benefits and Costs 8-56
8.4.4 Alternatives for Ample Margin of Safety for Elemental Phosphorus . . . 8-64
xiv
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TABLE OF CONTENTS
Page
8.5 Economic Impact Analysis 8-70
8.5.1 Production Costs 8-72
8.5.1.1 Components of Cost 8-72
8.5.1 J. I Phosphate Rock 8-74
8.5.1.1.2 Coke 8-74
8.5.1.1.3 Electricity 8-74
8.5.1.1.4 Labor 8-76
8.5.1.2 Total Costs Per Plant 8-76
8.5.2 Measuring Economic Impacts 8-76
8.5.3 Regulatory Flexibility Analysis 8-83
REFERENCES 8-86
9. PHOSPHOGYPSUM STACKS 9-1
9.1 Introduction and Summary 9-1
9.2 Industry Profile 9-1
9.2.1 Characteristics of Phosphoric Acid Production 9-3
9.2.1.1 Determinants of Phosphoric Acid Supply 9-3
9.2.1.2 Products 9-22
9.2.1.3 U.S. Phosphate Producers 9-22
9.2.1.4 Employment 9-33
9.2.2 Characteristics of Phosphoric Acid Demand 9-35
9.2.2.1 Determinants of Domestic Demand . 9-35
9.2.2.2 Determinants of Foreign Demand 9-39
9.2.2.3 World Demand for U.S. Phosphate Exports ............... 9-41
9.2.2.4 Demand Forecasts 9-48
9.2.3 Other Issues 9-52
9.2.3.1 Substitutes 9-52
9.2.3.2 Alternative Uses for Phosphogypsum . . 9-53
9.3 Current Emissions, Risk Levels and Feasible Control Methods . 9-59
9.3.1 Introduction . 9-59
9.3.2 Physical Attributes of Phosphogypsum Stacks 9-60
9.3.2.1 Design and Construction 9-60
9.3.2.2 Radon Emissions from Uncontrolled Stacks .............. 9-60
9.3.2.3 Risks Due to Controlled Stacks 9-62
9.3.3 Feasible Control Methods 9-62
9.3.3.1 Description of Controls 9-62
9.3.3.2 Costs of Controls 9-67
9.3.3.3 Emission Reductions Due to Controls 9-68
9.3.3.4 Reduction of Risk Due to Controls 9-69
xv
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TABLE OF CONTENTS
Page
9.4 Analysis of Benefits and Costs 9-69
9.4.1 Introduction 9-69
9.4.2 Least-Cost Control Technologies for Affected Plants 9-69
9.4.3 Health Benefits of Controlling Radon Emissions , 9-72
9.4.4 Health Benefits and Cost Estimates 9-72
9.4.5 Sensitivity Analysis . . . 9-78
9.5 Industry Cost and Economic Impact Analysis 9-78
9.5.1 Introduction 9-78
9.5.2 Production Costs and Market Prices 9-79
9.5.3 Measuring Economic Impacts 9-85
9.5.3.1 Background 9-85
9.5.3.2 Changes in Quantity of P205 product
Due to Control Requirements . 9-86
9.5.3.3 Methodology for Estimating Economic Impacts 9-87
9.5.3.4 Other Impacts of Radon Control
Requirements on the U.S. Economy . 9-93
9.6 Regulatory Flexibility Analysis . 9-95
9.6.1 Introduction 9-95
9.6.2 Small Business . 9-95
9.6.3 Small Government Entities 9-95
9.A Appendix A 9-A1
9.B Appendix B 9-B1
REFERENCES 9-96
10. COAL-FIRED BOILERS 10-1
10.1 Introduction and Summary . 10-1
10.2 Industry Profile 10-1
10.2.1 Demand 10-2
10.2.2 Supply 10-2
10.2.3 Industry Structure and Profile 10-2
10.3 Current Emissions, Risk Levels, and Feasible Control Methods 10-6
10.3.1 Introduction 10-6
10.3.2 Current Emissions and Estimated Risk 10-6
10.3.3 Control Technologies 10-6
10.4 Analysis of Benefits and Costs 10-8
10.4.1 Introduction 10-8
10.4.2 Least-cost Control Technologies 10-11
10.4.3 Health and Other Benefits 10-11
10.4.4 Estimates of Benefits and Costs . 10-11
xvi
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TABLE OF CONTENTS
Page
REFERENCES . 10-17
11. NRC-LICENSED AND NON-DOE FEDERAL FACILITIES 11-1
11.1 Introduction and Summary 1 l-l
11.2 Industry Profile 11-2
11.3 Current Emissions, Risk Levels, and Feasible Control Methods ............. 11-3
11.3.1 Introduction . H-3
11.3.2 Current Emissions and Estimated Risk Levels 11-3
11.3.3 Control Technologies J J-6
11.4 Analysis of Benefits and Costs 11-7
11.5 Industry Cost and Economic Impact 11-7
REFERENCES ... 11-10
12. SURFACE URANIUM MINES 12-1
12.1 Introduction and Summary 12-1
12.2 Industry Profile 12-1
12.2.1 Introduction 12-1
12.2.2 Demand for Uranium 12-1
12.2.3 Supply of Uranium . 12-2
12.3 Current Emissions, Risk Levels, and Feasible Control Methods ............. 12-7
12.4 Analysis of Benefits . 12-7
12.5 Industry Cost and Economic Impact Analysis 12-7
REFERENCES 12-8
xvii
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I IST OF TABLES
Table
1 -1 Uranium Mills Licensed by the Nuclear Regulatory Commission 1-3
1-2 Uranium Mill Capacity (Tons of Ore per Day) 1-4
1-3 Light Water Commercial Fuel
Fabrication Facilities
Licensed by the NRC as of June, 1987 . 1-6
1 -4 Fatal Cancer Risks from Atmospheric Radioactive Emissions from
Uranium Fuel Cycle Facilities 1-8
1 -5 Atmospheric Radioactive Emissions Assumed for References
Dry and Wet Process Uranium Conversion Facilities 1-10
1-6 Fatal Cancer Risk Due to Atmospheric Radioactive
Emissions - Uranium Conversions Facilities 1-11
1-7 Fatal Cancer Risks due to Atmospheric Radioactive Emissions -
Uranium Conversion Facilities 1-12
2-1 Currently Operating Underground Uranium Mines
in the United States 2-9
2-2 Current Risk Levels due to Radon-222 2-10
2-3 Alternative 1: Measures taken and their effects on
Maximum Exposed Individuals 2-12
2-4 Alternative 2: Measures taken and their effects on
Maximum Exposed Individuals . 2-14
2-5 Alternative 3: Measures taken and their effects on
Maximum Exposed Individuals 2-15
2-6 Matrix of MIRS as Stack Height and Emissions at
Pigeon Mines Vary 2-16
2-7 Pigeon Mine, Summary of Risk Reductions and Costs 2-18
2-8 Matrix of Costs of Various Combinations of Stack
Height and Shut-down Times for Pigeon Mine 2-19
2-9 Health Benefits due to Alternative One . 2-22
2-10 Health Benefits due to Alternative Two 2-23
2-11 Health Benefits due to Alternative Three 2-24
xviii
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LIST OF TABLES
Page
2-12 Costs of Alternative One 2-25
2-13 Costs of Alternative Two 2-26
2-13 Costs of Alternative Three 2-26
2-10 Number of Miners and Shifts per Day by Mine 2-29
2-11 Number of Miners and Mining Operations by County 2-29
3-1 Status and Planned Remedial Action at Inactive
Uranium Mill Sites 3-4
3-2 Summary of Radon-222 Emissions from Inactive
Uranium Mill Tailings Disposal Sites 3-7
3-3 Estimated Number of Persons Living Within 5 km of the
Centroid of Tailings Disposal Sites for Inactive Mills 3-9
3-4 Estimated Exposures and Risks to Nearby Populations
Assuming Alternative Flux Rates 3-10
3-5 Estimated Fatal Cancers Per Year in the Regional (0-80km)
Populations Assuming Alternative Flux Rates 3-11
3-6 Estimated Distribution of Fatal Cancer Risks to the Regional
(0-80km) Populations Assuming Alternative Flux Rates 3-13
3-7 Total and Annualized Risk and Reduction of Risk
(Committed Cancers) of Lowering the Allowable Limit
to 6 pCi/m2/sec and to 2 pCi/m2/sec 3-17
3-8 Costs of Achieving the Doe Approved Design Flux 3-19
3-9 Costs of Achieving the 6 pCi/m2/sec Option 3-20
3-10 Costs of Achieving the 2 pCi/m2/sec Option 3-21
3-11 Incremental Present Value Costs of Lowering the Allowable
Limit to 6 pCi/m2/sec and to 2 pCi/m2/sec 3-22
3-12 Incremental Annualized Cost of Lowering the Allowable Limit
to 6 pCi/m /sec and to 2 pCi/m /sec 3-23
4-1 Status of U.S. Nuclear Power Plants as of December 31, 1986. .............. 4-6
4-2 Deliveries of Uranium to DOE Enrichment
Plants by Domestic Utilities 4-7
xlx
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LIST OF TABLES
Page
4-3 Exports of Uranium (Thousand Short Tons of U308) 4-8
4-4 Average Contract Price and Market Price Settlements for
Actual Deliveries 1982-1986 4-11
4-5 Historical Nuexco Exchange Values (Nominal Dollars Per Pound of U3Oa) .... 4-12
4-6 Prices for Foreign-Origin Uranium . .4-13
4-7 Total Uranium Concentrate Production, 1947-1986 . . 4-15
4-8 Production of Uranium Concentrate by Conventional
Mills and Other Sources, 1974-1986 (Short Tons U3Os) 4-16
4-9 Uranium Mill Capacity (Tons of Ore Per Day) . 4-18
4-10 Import of Uranium Concentrate for Commercial Uses,
1974-1986 (Short Tons U308) 4-19
4-11 U.S. Commercially-Owned Uranium Inventories as of
December 31, 1984, 1985, and 1986 (Short Tons U308 Equivalent) 4-20
4-12 Capital Expenditures, Employment, and Active Mills;
Conventional Uranium Milling Industry 4-22
4-13 Operating Status and Capacity of Licensed Conventional
Uranium Mills as of June, 1989 4-23
4-14 Employment in the U.S. Uranium Milling Industry by State ............... 4-25
4-15 Financial Statistics of Domestic Uranium Industry, 1982-1986 4-28
4-16 Homestake Mining Company Uranium Operations, 1982-1986 4-30
4-17 Rio Algom Uranium Operations, 1981-1986 4-32
4-18 Annual and Projected Domestic Production of Yellowcake 1980-2000 4-35
4-19 Projected Nuclear Power Capacity (Reference Case) 4-38
4-20 Domestic Uranium Resources Endowment (Thousands of Short Tons) 4-40
4-21 Projections of Consumption of Electricity from
Domestic 9-235 in 2000 Under the Reference Case Scenario 4-43
4-22 Average Annual Percentage Change in Electricity Consumption,
1987-2000 4-45
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LIST OF TABLES
Eiie
4-23 Average Annual Percentage Change in Per Capita
Electricity Consumption, 1987-2000 4-46
4-24 Employment Projects 1987-2000 (Person Years) 4-48
4-25 Summary of Operable Tailings Impoundment Areas
Radium-226 Content at Operating and Standby Mills 4-51
4-26 Summary of Radon Source Terms Calculated for
Operable Mill Tailings Impoundments 4-52
4-27 Estimated Number of Persons Living Within 5 km of the
Centroid of Tailings Impoundments of Licensed Mills 4-54
4-28 Summary of Uranium Mill Tailings Impoundment Areas, Flux
Rates, and Post-UMTRCA Radon-222 Release Rates 4-55
4-29 Estimated Exposures and Risks to Individuals Living Near
Operable Tailings Impoundments with No Controls. 4-57
4-30 Estimated Fatal Cancers per Year in the Regional (0-80km)
Populations Around Operable Tailings Impoundments 4-58
4-31 Estimated Distribution of the Fatal Cancer Risk to the
Regional Populations from Operable Tailings Piles 4-58
4-32 Estimated Exposures and Risks to Nearby Populations
Assuming Alternative Flux Rates . 4-60
4-33 Estimated Fatal Cancers per Year in the Regional Populations
Assuming Alternative Radon Flux Rates 4-61
4-34 Estimated Distribution of Fatal Cancer Risk to the Regional
Populations Assuming Alternative Flux Rates 4-62
4-35 Total and Annualized Risk and Reduction of Risk of Lowering
the Allowable flux Limit to 6 and 2 pCi/m /sec 4-68
4-36 Costs of Achieving the 20 pCi/m2/sec Option
(1988 Dollars, Millions) 4-69
4-37 Costs of Achieving the 6 pCi/m2/sec Option
(1988 Dollars, Millions) 4-70
4-38 Costs of Achieving the 2 pCi/m2/sec Option
(1988 Dollars, Million) 4-71
4-39 Incremental Present Value Cost of Lowering the Allowable
Limit to 6 pCi/m2/sec and 2 pCi/m2/sec .
(1988 Dollars, 1989 through 2088) 4-72
xxi
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I.TST OF TABLES
Faee
4-40 Incremental Annualized Cost of Lowering the Allowable
Limit to 6 pCi/m2/sec and 2 pCi/m2/sec
(1988 Dollars, 1989 through 2088) 4-74
4-41 Risks and Reduction of Risks for Continued Operations
at 20 pCi/m2/sec 4-76
4-42A Earth and Water Cover Required to Achieve
Emissions of 20 pCi/m2/sec 4-78
4-42B Cost of Earth Cover and Water Required to
Achieve Emissions of 20 pCi/m /Sec . 4-79
4-43 Estimated Total Cost For New Tailings Control
Technology (Millions of 1985 Dollars) 4-84
4-44 Radon-222 Emissions and Emissions Reduction
Resulting From Alternative Work Practices (kCi) 4-85
4-45 Radon-222 Risks and Reductions of Risks Resulting
From Alternative Work Practices (Committed Cancers) 4-88
4-46 Costs For a Single Cell Partially Below Grade
New Model Tailings Impoundment 4-90
4-47 Costs For a Phased Design Partially Below
Grade New Model Tailings Impoundment 4-91
4-48 Costs For a Continuous Design Partially
Below Grade New Model Tailings Impoundment 4-92
4-49 Summary of Net Present Values of Alternative
Work Practices (Millions of 1988 Dollars) . 4-93
4-50 Summary of Annualized Costs of Alternative Work
Practices (Millions of 1988 Dollars) 4-94
4-51 Comparison of the Present Value of the Estimated Cost
of Impacts with Selected Financial Statistics of the
Domestic Uranium Industry: 1982-1986 4-97
4-52 Impacts on the Electrical Power Industry 4-99
4-53 Electrical Generation by NK.RC Region, 1987 4-100
4A-1 Calculation of Cost of Water Required to Reduce Allowable
Emissions to 20 pCi/m2/sec 4-105
5-1 Emissions and Risks from Normal Operation at
xxii
-------
LIST OF TABLES
Ems&
HLW Disposal Facilities 5-4
6-1 Department of Energy Facilities 6-2
6-2 Summary of Estimated Risks Around DOE Facilities 6-4
6-3 DOE Facilities Fatal Cancer Risks With and Without Supplementary
Alternative 4 Controls 6-8
6-4 Controls, Risk Reduction, and Costs Associated with
Meeting Alternative 4, by Facility 6-9
7-1 Exposures and Risks to Nearby Individuals From DOE Radon Sites 7-5
7-2 Estimated Fatal Cancers Per Year; in the Regional (0-8Gkm)
Populations Around DOE Radon Sites 7-6
7-3 Costs and Reduced Risks Resulting from Covering the Sources
to Lower Radon Flux Rates to 20 pCi/m2/sec 7-11
7-4 Costs and Reduced Risks Resulting from Covering the Sources to Lower
Radon Flux Rates to pCi/m2/sec 7-12
7-5 Costs and Reduced Risks Resulting from Covering the Sources
to Lower Radon Flux Rates to 2 pCi/m2/sec 7-13
7-6 Reduction in Emissions and Cancer Rates Attributable
to Controls; U.S. Totals 7-15
7-7 Incremental Costs and Risk Reductions for Various
Flux Standards 7-16
7-8 Net Present Value of Cost of Supplemental Contracts to Meet
a Flux of 20 pCi/m2/sec at DOE Radon Facilities;
U.S. Total 7-18
8-1 Production and Shipment of Elemental Phosphorus -- 1964-1987 (tons) 8-4
8-2 Uses for Phosphorus Chemicals 8-5
8-3 Elemental Phosphorus Producers and Estimated Capacity 8-8
8-4 U.S. Capacities for Phosphorus and Phosphorus Chemicals - 1985 8-9
8-5 Elemental Phosphorus Production Capacity 8-11
8-6 Revenues from Elemental Phosphorus Production and Total Corporate Revenues 8-12
8-7 Elemental Phosphorus Market Share: Monsanto 8-14
xxiii
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LIST OF TABLES
Flit
8-8 Monsanto's Position in Phosphorus Markets -- 1984 8-14
8-9 Elemental Phosphorus Market Share: FMC 8-15
8-10 FMC's Position in Phosphorus Markets - 1984 8-15
8-11 Elemental Phosphorus Market Share: Stauffer 8-17
8-J2 Stauffer's Position in Phosphorus Markets 8-17
8-13 Elemental Phosphorus Market Share: Occidental 8-19
8-14 Occidental's Position in Phosphorus Markets - 3984 8-19
8-15 Average Price Range — Phosphorus — White 8-22
8-16 1987 Employment by State for the Elemental Phosphorus Industry 8-23
8-17 Radionuclide Emissions from Calciners at Elemental Phosphorus Plants ....... 8-28
8-18 Estimated Annual Radionuclide Emissions from Elemental Phosphorus Plants . . 8-28
8-19 Populations and Distances to the Maximum Exposed Individuals Around
Elemental Phosphorus Plants 8-29
8-20 Fatal Cancer Risks from Radionuclide Emissions from Elemental Phosphorus
Plants 8-30
8-21 Distribution of Lifetime Fatal Cancer Risk in the Regional (0-80 km)
Population Around Operating Elemental Phosphorus Plants ................ 8-30
8-22 Distribution of Lifetime Fatal Cancer Risk in the Regional (0-80 km)
Population Around Idle Elemental Phosphorus Plants 8-30
8-23 Estimated Po-210 and Pb-210 Emissions at the Scrubber/ESP Inlet 8-39
8-24 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal: Industry Totals 8-40
8-25 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal at FMC's Pocatello, Idaho, Plant 8-41
8-26 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal at Monsanto's Soda Springs, Idaho, Plant 8-42
8-27 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal at Stauffer's Mount Pleasant, Tennessee, Plant 8-43
8-28 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal at Stauffer's Silver Bow, Montana, Plant 8-44
xxiv
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LIST OF TABLES
Page
8-29 Cost of Alternative Control Systems and Efficiency of Polonium-210
Removal at Occidental's Columbia, Tennessee, Plant 8-45
8-30 Estimated Po-210 Emission Levels Achieved by Control Alternatives ........ 8-47
8-31 Fatal Cancer Risks from Radionuclide Emissions from Elemental Phosphorus
Plants and Risk Reductions from Alternate Control Technologies ........... 8-48
8-31a Reduction in Fatal Cancer Risks to Nearby Individuals and to Regional
Populations for Each Alternate Control Technology 8-49
8-32 Control Technology Costs and Estimated Po-210 Emission Rates
at FMC's Pocatello, Idaho, Plant 8-51
8-33 Control Technology Costs and Estimated Po-210 Emission Rates
at Monsanto's Soda Springs, Idaho, Plant 8-52
8-34 Control Technology Costs and Estimated Po-210 Emission Rates
at Stauffer's Mount Pleasant, Tennessee, Plant 8-53
8-35 Control Technology Costs and Estimated Po-210 Emission Rates
at Stauffer's Silver Bow, Montana, Plant 8-54
8-36 Control Technology Costs and Estimated Po-210 Emission Rates
at Occidental's Columbia, Tennessee, Plant 8-55
8-3? Least-Cost Control Alternatives Required to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by
Plant — FMC - Idaho 8-57
8-38 Least-Cost Control Alternatives Required to Meet Various Emissions Standards
with Subsequent Emissions and Risks, by Plant -- Monsanto - Idaho 8-58
8-39 Least-Cost Control Alternatives Required to Meet Various Emissions Standards
with Subsequent Emissions and Risks, by Plant — Occidental - Tennessee .... 8-59
8-40 Least-Cost Control Alternatives Required to Meet Various Emissions Standards
with Subsequent Emissions and Risks, by Plant — Stauffer - Montana ....... 8-60
8-41 Least-Cost Control Alternatives Required to Meet Various Emissions Standards
with Subsequent Emissions and Risks, by Plant -- Stauffer - Tennessee 8-61
8-42 Total Annualized Costs of Alternative Emissions Standards:
Sum of All Operating Plants 8-62
8-43 Total Incidence with Alternative Emissions Standards:
Sum of All Operating Plants 8-63
8-44 Alternatives for Ample Margin of Safety for Elemental Phosphorus Plants,
xxv
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LIST OF TABLES
Page
According to Various Emissions Levels 8-65
8-44a Alternatives for Ample Margin of Safety for Elemental Phosphorus Plants,
Using Different Control Technologies 8-68
8-45 Cost of Elemental Phosphorus 8-73
8-46 Costs of Phosphate Rock Used in Phosphorus Production 8-75
8-47 Costs of Electricity Used in Phosphorus Productions 8-77
8-48 Labor Costs . 8-78
8-49 Summary of Cost Estimates, by Plant . 8-79
8-50 Revenues from Elemental Phosphorus Production and Total Corporate Revenues 8-82
8-51 Impact on Capital Expenditures 8-84
9-1 Production of Phosphoric Acid, Wet Process Phosphoric Acid,
and Phosphate Fertilizer Metric Tons 9-4
9-2 Price of Phosphoric Acid, Sulfur,
Phosphate Rock and Diammonium Phosphate . . 9-8
9-3 Phosphate Fertilizer Production Costs 9-10
9-4 Phosphate Rock Statistics on World
Supply Rock Mining Capacity 9-13
9-5 Phosphate Rock Statistics on World
Supply Demonstrated Rock Reserves 9-14
9-6 U.S. Sulphur Recover Trends 1980-1985 9-21
9-7 Financial Condition of Phosphate Industry 9-25
9-8 Producers of Phosphate Rock, Wet Process Phosphoric,
and Phosphate Fertilizers (Thousand Metric Tons Per Year) 9-26
9-9 Capacities of Major Phosphoric Acid Producers, Estimates
for 1988/89 (Metric Tons Per Year) 9-27
9-10 Operating Rates for U.S. Fertilizer Producers 9-28
9-11 Employment in the Phosphate Industry (Thousands) ..................... 9-34
9-12 U.S. Exports of Phosphate Fertilizers
(Thousand Metric Tons, Thousand Dollars) 9-45
xxvi
-------
LIST OF TABLES
Page
9-13 Trade in Phosphate Products by Major Exporter, 1981-1984
Phosphate Fertilizer (Metric Tons, P205) . . 9-47
9-14 Summary of World Phosphate Fertilizer Demand Forecasts
(Million Nutrient Metric Tons P205) 9-49
9-15 Forecasts of Fertilizer Demand by Region and
Source, 1995-2000 9-51
9-16 Stack Parameters 9-61
9-17 Radon Flux Rates by Regional Group 9-63
9-18 Incremental Cancer Risks Associated With Exposure
to Radon Emitted From Phosphogypsum Stacks with No Controls 9-64
9-19 Control Parameters for Representative Stacks 9-66
9-20 Reduction in Risk to the Most Exposed Individual 9-70
9-21 Reduction in Risk to Population Within 80km of Stack 9-71
9-22 Cost Effectiveness of Control in Terms of Emission Reductions 9-73
9-23 Cost of Controlling Radon in Dollars Per 1000/MT of
Plant Capacity, Annualized Over A Five Year Period 9-80
9-24 World Market Share of U.S. P,05 Producers Exports in Absence of
Radon Control Measures in I TOO MT (Lower Phosphate Rock Cost) 9-89
9-25 World Market Share of U.S. P-,05 Producers Exports in Absence of
Radon Control Measures in 1000 MT (Higher Phosphate Rock Cost) 9-90
10-1 Coal Ash Distribution by Boiler Type 10-4
10-2 Numbers and Capacities of Industrial Boilers 10-5
10-3 Typical Uranium and Thorium Concentrations in Coal 10-7
10-4 U-238 Emission Factors for Coal-Fired Utility Boilers 10-9
10-5 Th-232 Emission Factors for Coal-Fired Utility Boilers 10-10
10-6 Estimated Radiation Dose Rates from Large Coal-Fired Utility Boilers 10-12
10-7 Estimated Radiation Dose Rates from the Reference
Coal-Fired Industrial Boiler 10-13
xxvii
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LIST OF TABLES
Faee
10-8 Estimated Distribution of the Fatal Cancer Risk to the Regional
(G-80km) Populations from All Coal-Fired Utility Boilers ,. . . 10-14
10-9 Estimated Distribution of the Fatal Cancer Risk to the Regional
(0-80km) Populations from All Coal-Fired Industrial Boilers 10-15
11-1 NRC Licensed and Non-DOE Facilities Fatal Cancers Per Year 11-4
11-2 Costs and Benefits for Controls on the Two Sources
for Which Controls are Required 11-8
12-1 Number of Significant Production Surface Uranium Mines by State 12-4
12-2 Reasonably Assured Resources by Mining Method
At the End of 1986 in the U.S. (million pounds of U3Os) 12-5
12-3 United States and Selected Foreign Uranium Resources as of End of 1986 12-6
xxviii
-------
LIST OF FIGURES
Figure Page
2-1 Costs of Controls by Stack Height 2-19
3-1 Cost of Lowering the Allowable Flux 3-24
4-1 Sources of Uranium Supply 4-37
4-2 U.S. Uranium Production 4-37
4-3 Model Impoundment Emissions (kCi/Year) 4-86
9-1 Price of P205 and Related Products . 9-7
9-2 Uses for Phosphoric Acid, 1985-86 . 9-23
9-3 United States Fertilizer Consumption 9-38
9-4 U.S. P205 Exports (Lower Rock Costs) . 9-92
9-5 U.S. P205 Exports (Higher Rock Costs) 9-92
12-1 Uranium Production U.S. Open-Pit Mines and Total Output 12-3
xxix
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CHAPTER 1
URANIUM FU& CYCLE
-------
1. URANIUM FUEL CYCLE FACILITIES
1.1 Introduction and Summary
The uranium fuel cycle involves six types of major industrial facilities. These major facilities
include:
o Uranium mills
o Uranium hexaflouride conversion facilities
o Uranium enrichment facilities
o Fuel fabricators
o Light-water power reactors
o Fuel reprocessing plants
Releases of radioactive materials from these sources are subject to the limits established by 40 CFR
190. A comprehensive evaluation of the potential public health impacts of the release of radioactive
materials into the ambient air from the uranium fuel cycle was prepared by the EPA and a list can
be found in Volume 2 of this Final Environmental Impact Statement [EPA89], The uranium
enrichment facilities are discussed in Chapter 6, "Department of Energy Facilities." Fuel reprocessing
plants are not discussed since there are currently no operating fuel reprocessing plants in the United
States. The remaining four types of facilities are discussed below.
This chapter will provide a brief industry profile, estimates of emissions and associated risk levels,
discussion of feasible emission control methods, and an economic impact analysis. The risk to
regional populations (persons living within 80 km of the source) from the four facility types covered
in this chapter* are estimated to be equivalent to one fatal cancer every one hundred years. Risk to
both regional and national populations are estimated to be equivalent to one fatal cancer every ten
years [EPA89],
^Excluding radon emissions from uranium mill tailings.
1-1
-------
1.2 Industry Profile
The four major components of the uranium fuel cycle included in this chapter are uranium mills,
uranium conversion facilities, fuel fabrication facilities, and nuclear power facilities. These facilities
are licensed by the Nuclear Regulatory Commission (NRC) or the Agreement States. Each of these
four facility types are briefly described below. More detailed descriptions for some may be found
in complementary chapters for uranium mill tailing piles and uranium enrichment plants. A fifth
major component, uranium enrichment facilities, are owned by the Federal government and operated
by contractors under the direction of the Department of Energy (DOE). Enrichment facilities are
considered in Chapter 6.
1-2.2 Uranium Mills
A detailed profile of the uranium mill industry is contained in Chapter 4: "Licensed Uranium Mill
Tailings." Although there are 27 uranium mills within the U.S., only four were operating in 1988.
Of the remainder, eight were on standby, fourteen were being decommissioned and one was never
operated. The four operating mills have a total capacity of 9,600 tons of ore per day, reflecting a
decline in capacity from 50,000 tons per day in 1981 when 21 plants were in operation, (Tables 1-
I and 1-2 present data on milling capacity and the recent capacity trends). These developments are
due to a combination of 1) rising imports and 2) declining demand resulting from cancellation of
nuclear power plant construction projects. Domestic production of yellowcake, the product of
uranium milling, is expected to increase over ten percent by the year 2000, but short-run forecasts
of domestic production call for a continuing decline [DOE87b]. The financial strength of the
industry has weakened considerably since its peak demand years in late 1970's and early 1980's. The
industry was unprofitable for three of the past five years.
1-2.3 Uranium Conversion Facilities
There are two commercially operating conversion facilities in the United States. These facilities
purify uranium oxide or yellowcake to uranium hexafluoride (UFg), the chemical form of the
uranium entering the enrichment plant. The two conversion facilities are the Allied Chemical
Corporation facility at Metropolis, Illinois and the Kerr-McGee Nuclear Corporation at Sequoyah,
Oklahoma. The Allied plant is a dry process plant with a capacity of 12,600 metric tons per year and
has been operational since 1968, while the Kerr-McGee plant is a wet process plant with a capacity
1-2
-------
Table 1-1: Uranium Mills Licenses by the U.S. Nuclear Regulatory Commission
as of December 1, 1988
Rated
Licensee
Location
Capacity
Status
Process
(tons/day)
American Nuclear
Gas Hills, WY
950
3
1,5
Anaconde
Blue water, NM
6000
3
1,3
Atlas Minerals
Moab, UT
1400
3
2,3
Bear Creek Uranium
Converse Co., WY
2000
3
1,3
Bodum Resources
Marquez, NM
2000
4
1,3
Chevron Resources
Panna Maria, TX
2500
1
1,3
Conoco-Pioneer
Falls City, TX
3400
3
1,3
Cotter
Cannon City, CO
1200
2
1,3
Dawn Mining
Ford, WA
450
3
1,3
Exxon
Ray Point, TX
—
3
--
Exxon Minerals
Converse Co., WY
3200
3
1,3
Homestake Mining
Grants, NM
3400
1
4,6
BP American
Seboyeta, NM
1600
3
—
Minerals Exploration
Sweetwater Co., WY
3000
2
1,3
Pathfinder Mines
Gas Hills, WY
2500
2
1,3
Pathfinder Mines
Shirley Basin, WY
1700
1
1,3
Petrotomics
Shirley Basin, WY
1500
3
1,3
Plateau Resources
Shootaring, UT
750
2
1,3
Quivira
Ambrosia Lake, NM
—
2
—
Rio Alogm
La Sat, UT
750
2
4,6
TV A
Edgemont, SD
3
—
Umetco Minerals
Gas Hills, WY
1400
3
1,5
Umeteo Minerals
Blanding, UT
2000
1
1,7
Umetco Minerals
Uravan, CO
1300
2
1,3
UNC Mining
Church Rock, NM
3000
3
1,3
Western Nuclear
Jeffrey City, WY
1700
3
1,3
Western Nuclear
Wellpinit, WA
2000
2
1,3
STATUS CODES:
PROCESS CODES:
1 = Facility Operating
2 = Facility Shutdown
3 » Facility Being Decommissioned
4 = Facility Built, Never Operated
1 = Acid Leach
2 = Alkaline Leach
3 = Solvent Extraction
4 = Carbonate Leach
5 = Eluex
6 = Caustic Precipitation
7 = Column ion exchange
SOURCE: [EPA89]
1-3
-------
Table 1 -2: Uranium Mill Capacity (Tons of Ore per Day)
Year
Total
Capacity
Operating
Capacity
Operating
Capacity
Utilization
Rate
Total
Capacity
Utilization
Rate
1981
54,050
49,800
83%
77%
1982
55,050
33,650
74%
45%
1983
51,650
29,250
58%
33%
1984
48,450
19,250
64%
25%
1985
47,250
6,550
78%
11%
1986
42,650
11,650
32%
9%
Source: (DOE 87 )
1-4
-------
of 9,100 tons per year that has operated since 1970 (AEC74, DGE88], It is anticipated that the
existing uranium conversion plants will be able to accommodate the future demand for uranium by
nuclear power plants.
1.2.4 Fuel Fabrication Facilities
There are seven licensed uranium fuel fabrication facilities in the United States, but only five were
actively operating as of January 1, 1988. Table 1-3 lists and describes the seven facilities. Light
water reactor (LWR) fuels are fabricated from uranium which has been enriched in the U-235
isotope. The uranium hexafluoride, UFg, is processed to increase the U-235 content from 0.7
percent up to two to four percent by weight. The enriched uranium hexafluoride product is shipped
to the LWR fuel fabrication plant where it is converted into solid uranium dioxide pellets and
inserted into zirconium tubes that are fabricated into fuel assemblies for use in nuclear power plants.
Two of the five operating facilities use enriched uranium hexafluoride to produce fuel assemblies,
while two use uranium dioxide. The fifth facility converts UFg to UC>2 and recovers uranium from
scrap materials generated in the various processes at the plant. There are two processes used to
convert UFg to UOj - a wet process, ammonium diuranate, and a dry process, direct conversion.
1-2.5 Light-water Power Reactors
There are 102 operable commercial nuclear power reactors in the United States, Of these,
approximately two-thirds are pressurized water (PWR) and one-third are boiling water reactors
(BWR) [NN88],
The future of the nuclear power industry in the United States depends on the demand for electricity,
interest rates, prices of alternative fuels, environmental concerns, the regulatory climate, and public
attitudes. The probable range of nuclear power capacity by the year 2000 is estimated to be from
100 to 110 plants.
1.3 Current Emissions. Risk Levels, and Feasible Controls Methods
1.3.1 Introduction
The emission rate for a facility will depend on the source and the control system currently in use.
Risk levels depend on the emission levels, release points, demographic and meteorological factors and
1-5
-------
Table 1-3; Light Hater Commercial fuel Fabrication Facilities Licensed lay the Nuclear
Regulatory Commission as of June, 1987.
1980 Operating
Process Used Operating License
Facility to Convert Capacity as of
Licensee Location Operations UF6 to U02 Final Product (tons/year) June 1987
Advanced
Nuclear
Fuels
Babcock &
Hi Ico* -
CNFP
Babcock &
Hi Icox
Combustion
Engineering
Combustion
Engineering
Seneral
Electric
Hestinghouse
Electric
Richland,
Washington
Lynchburg,
Virginia
Apollo,
Pennsylvania
Windsor,
Connecticut
Hematite,
Missouri
Hi Lmington,
North Carolina
Columbia,
South Carolina
LEU a/ Conversion Dry & Wet
(UF6 to U02),
Fabrication & Scrap
Recovery; Commercial
LHR Fuel
LEU Fabrication;
Commercial LHR Fuel
Authorized Oecontam- Met
ination; Pending
Nuclear Reactor
Service Operations
LEU Fabrication;
Commercial LHR Fuel
LEU Conversion Dry
(UF6 to U02) S
Scrap Recovery
LEU Conversion Pry K Het
CUF6 to U02) S
Fabrication;
Commercial LHR Fuel
LEU Conversion Ory & Het
(UF6 to U02);
Fabrication 8 Scrap
Recovery; Commercial
LHR Fuel
Complete Fuel
Assemblies
Use U02 Powder
to Produce Fuel
Assemblies
U02 Powder
Use 002 Powder
to Produce Fuel
Assemblies
U02 Powder
Covplete Fuel
Assemblies
Complete Fuel
Assemblies
TOTAL
a/ Low enrichment uranium
650
(2505
250
(150)
150
1,500
750
3,300
NO
YES
NO
YES
YES
YES
YES
Source: CEPA89J
-------
the pathways for exposure or ingestion. Estimates of exposure and lifetime fatal cancer risks to
nearby individuals and to those within an 80 kilometer radius serve as the basis for the risk
assessments. The risks are summarized in Table 1-4 for both nearby and regional populations
[EPA89].
1.3.2 Current Emissions and Estimated Risk Levels
1.3.2.1 Uranium Mtils
Emissions of radionuclides from uranium mills include those created during ore storage and milling
processes, and those emitted by the mill tailings. Radon emissions from mill tailings piles are
discussed in Chapter 4 of this volume and are not considered in this chapter.
Emissions from ore storage result from the drying of the ore and its subsequent entrainment by wind
or from transfer operations. The milling process includes the crushing and grinding of ore and the
leaching of uranium from the ore through either acid or alkaline processing, depending upon the
lime content of the ore. The precipitate that is formed is then dried in large ovens and packaged for
transport. After the uranium product that can be extracted by leaching is separated from the ore,
the remaining ore is pumped as slurry to a tailings impoundment area. A portion of the liquid is
recovered and recycled, while the remainder is allowed to evaporate, producing a solid tailings pile
composed of a sand fraction and a slime fraction. Active tailings piles contain both wet and dry
areas. As sections dry out, the tailings can become a source of windblown dust. The dried slime
component is particularly prone to becoming windborne due to its small particle size. The process
steps that generate the significant emissions (other than radon from tailings piles) are crushing,
drying, and packaging. Ninety percent of the U-234 and U-238 are released from the dryer area,
while the Th-230 and Ra-226 emissions result primarily from operations such as crushing.
Emissions for this source category are analyzed in detail in Chapter 4 of Volume 2 of the
Environmental Impact Statement, including a description of the basis for the site-specific and model
facilities used to assess the airborne releases of radionuclides from uranium mills. Also presented is
information on the source term, meteorological, and demographic assumptions. Site-specific source
term, meteorological, and demographic data for each of the four operating mills and for six of the
seven mills on standby, were supplied as input to the assessment codes. A model mill was used for
the assessment of doses and risks from the tailings piles of inactive mills. Outputs of the codes
include estimates of: dose equivalents to the most exposed individuals (mrem/y); lifetime fatal
1-7
-------
Table 1-4 Fatal Cancer Risks from Atmospheric Radioactive Emission from Uranium Fuel
Cycle Facilities (Excluding Radon from Tailing Piles)
Highest Individual Regional (0-80 km)
Lifetime Fatal Population
Facility Cancer Risk Deaths/y
Uranium Mills
Ambrosia Lake
2E-7
3E-5
Homestake
2E-4
2E-3
La Sal
2E-6
3E-5
Lucky Mc
1E-7
7E-6
Panna Maria
3E-6
5E-5
Sherwood
IE-6
8E-5
Shirley Basin
6E-7
9E-5
Shootaring
2E-7
7E-7
Sweetwater
7E-7
2E-5
White Mesa
6E-7
2E-5
Model Inactive Tailings
2E-4
1E-4
Total 2E-3
Uranium Conversion
Dry
3E-5
8E-4
Wet
4E-5
6E-4
Fuel Fabrication
4E-6
8E-5
Nuclear Power Reactors
Pressurized
Water Reactors
3E-6
7E-4
Boiling Water
Reactors
5E-6
1E-3
1-8
-------
cancer risk to the most exposed individuals; dose equivalents to the regional (0-80 km) population
(person-rem/y); and the number of cancer deaths in the regional population per year of operation
(deaths/year).
The fatal cancer risks are summarized in Table 1-4 for both nearby and regional populations affected
by either operating or closed mills. The total deaths per year in the 80 km regional population for
uranium mill segment of the source category is estimated to be 2E-3.
1.3.2.2 Uranium Fuel Conversion Facilities
Two processes are used to convert uranium oxide to uranium hexaflouride. The dry hydrofluor
process generates higher uranium emissions than the solvent extraction process since large amounts
of dust are produced in the sampling, pre-treatment, and reaction stages. The solvent extraction
process releases uranium as both soluble and insoluble aerosols which are vented to the environment.
The atmospheric emissions used in the risk assessments for the reference dry and wet conversion
facilities are shown in Table 1-5. The plant parameters utilized are specific to each plant [NRC 84,
NRC85b], Table 1-4 shows fatal cancer risks due to atmospheric radioactive emissions. The risk to
nearby individuals of fatal cancer is estimated at 3E-5 and 4E-5 for the dry and wet processes,
respectively. The lifetime risk to the regional population is 8E-4 and 6E-4 fatal cancers per year for
the dry and wet processes, respectively (see Table J -6). The total risk for all uranium conversion
facilities is estimated to be 1E-3 fatal cancers per year of operation in the regional populations, with
a total of about 900,000 persons.
1.3.2.3 Uranium Fuel Fabrication Facilities
A model fuel fabrication facility was developed to estimate the risks associated with this class of
facilities. The Westinghouse plant at Columbia, South Carolina was used as the basis for the model
facility for most emissions.
Table 1-7 shows the expected emissions from the model plant. The climatological and demographic
data utilized are representative of the area proximate to the Westinghouse Facility at Columbia,
South Carolina which was the basis for the model plant. The predominant exposure pathway is via
inhalation, primarily of U-234. On a regional basis the risk of fatal cancers is estimated to be 8E-
5 per year of operation. The total risk for an assumed industry of five operating fuel fabrication
facilities is approximately 4E-4 fatal cancers per year.
1-9
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Table 1-5 Atmospheric Radioactive Emissions Assumed for Reference Dry and Wet Process
Uranium Conversion Facilities.
Emissions Solubility Class (%)W
Facility Process Radionuclide (Ci/year) D W Y
Allied Corp. Dry
Metropolis, IL
Sequoya Fuels Wet
Sequova, OK
U-Natural^ 0.10000
Th-230W 0.00050
Ra-226W 0.00001
U-Natural^ 0.050
Th-230)c| 0.005
Ra-226W 0.005
56
30
14
0
0
100
100
0
65
5
30
0
0
100
0
100
0
Solubility classes D, W, and Y refer to the retention of inhaled radionuclides in the lungs;
representative half-times for retention are less than 10 days for class D, 10-100 days for class
W, and greater than 100 days for class W, and greater than 100 days for class Y.
Particle size 3.4 um.
Particle size fuml % (Average: J980-19841
4.2 to 10.2 9.3
2.1 to 4.2 9.7
1.3 to 2.1 5.5
0.69 to 1.3 6.5
0.39 to 0.69 13.5
0.00 to 0.39 55.3
SOURCE: [EPA 89]
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Table 1-6 Fatal Cancer Risks due to Atmospheric Radioactive Emissions-
Uranium Conversion Facilities
Nearby
Regional (0-80 Km)
Individuals Lifetime
Population
Process
Fatal Cancer Risk
Deaths/Year
Dry
3E-5
8E-4
Wet
4E-5
6E-4
Source; EPA 89
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Table 1-7 Fatal Cancer Risks doe to Atmospheric Radioactive Emissioas-
Uranium Conversion Facilities
Nearby
Regional (0-80 Km)
Individuals Lifetime
Population
Process
Fatal Cancer Risk
Deaths/Year
Dry
3E-5
8E-4
Wet
4E-5
6B-4
Source: EPA 89
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1-3,2.4 Nuclear Power Reactors
Radionuclides are produced during the fission process and accumulate within the nuclear fuel.
Reactors also experience periodic fuel failure, resulting in leakage of fission or activation products
out of the fuel and into the coolant. The primary sources of gaseous emissions from boiling water
reactors (BWR's) are from the off-gas treatment system and building ventilation system exhaust.
Pressurized water reactors (PWR) discharge radioactive products through four systems, including
those for BWRs plus the steam generator's blowdown exhaust and the exhaust of non-condensable
gases at the main condenser.
The predominant pathway of exposure from BWRs is air immersion, resulting from the release of
radioactive xenon and krypton. Air immersion and inhalation are the most important exposure
pathways for the model PWRs, with the primary exposures coming from strontium-90 and xenon.
Doses and risks were estimated in Volume 2 of the Environmental Impact Statement. The lifetime
risk of fatal cancer for nearby individuals ranges from 3E-6 for the model PWR to 5E-6 for the
model BWRs. The incremental risk to the regional population is IE-3 fatal cancers per model BWR
per year of operation and 7E-4 fatal cancers per model PWR per year of operation. Summing this
risk across the population of power plants yields a total risk of 9E-2 cancers per year for the United
States. These estimates assume non-overlapping populations for exposure to nuclear power reactors
and may understate the risk to some individuals residing near multiple reactors.
1.3.3 Control Technologies
Currently available emission control techniques for the four components of the uranium fuel cycle
covered by this chapter are discussed in the following sub-sections. Because all achieve emission
control and risk levels that are considered adequate, no further work was done to identify more
stringent emission control approaches,
1-3.3.1 Uranium Mills
Controls to reduce radioactive particulate emissions currently exist and can be applied to various
stages of uranium milling. These include grinding and leaching of the ore to extract uranium oxide,
drying and packaging the product, and storage of the mill tailings. These controls are briefly
discussed in this section. Control of radon emissions from tailings piles is discussed in Chapter 4 of
this volume.
1-13
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Controls for emissions from the milling operations -- grinding, leaching, drying and packaging --
have been evaluated by the NRC [NRC80], Milling dust is controlled by the placing of exhaust
hoods at the crusher, screens and transfer points. The off-gases from the drying operation are passed
through a dust separation system before discharge. Air exhaust hoods are placed in the packaging
area and run through a dust collector prior to venting. The use of wet scrubbers is the primary
method of removing dust from the exhaust gases. Rated collection efficiencies vary from
approximately 94 to 99.9 percent depending upon the type of scrubber.
The cost for each additional tenth of a percent of improvement of efficiency increases as the
efficiency level increases. For example, a medium-energy venturi scrubber, with 99.7 percent rated
efficiency, costs $305,000 (in 19E0 prices) over a fifteen year lifetime, while a high-energy venturi
scrubber, with 99.9 percent rated efficiency, costs $430,000. The additional 0.2 percent of efficiency
costs $125,000.
A variety of controls for windblown radioactive particulates from mill tailings piles have also been
analyzed and are discussed in Volume 2, Chapter 4 of Environmental Impact Statement, These
include; wetting of tailings, the use of tank trucks or sprinkling systems; leaching of tailings;
solidification of tailings; application of stabilizers such as latex or polymers to tailings surfaces; and
covering of tailings, either above or below ground. The application of latex stabilizers to the tailings
piles is a cost-effective method for controlling dust from the piles. This method is currently in use
and has proved effective for up to one year per application. Its cost is estimated at $1.03 million for
an annual application to a 30 hectares pile.
The stationary sprinkling system is the second most cost effective alternative. When installed and
operated by existing maintenance personnel, this alternative is more cost-effective than the
application of latex stabilizers. The cost of a stationary sprinkling system to cover a total of 30
hectares is estimated to be $1.9 million. Some evidence at specific plants indicate that this cost can
be reduced considerably [EPA89]. An added advantage of such a system is that evaporation of the
tailings pond water, an operational goal of each milling operation, would be substantially increased.
The value of this benefit has not been estimated.
1-14
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1.3.3.2 Uranium Conversion Facilities
Well-proven particulate control technologies such as fabric filters and scrubbers can be added to the
existing control systems at uranium hexafluoride conversion plants to reduce emissions. The
selection of additional controls must take into account the presence of moisture and corrosive
contaminants (particularly fluorine) in some of the exhaust lines.
A previous study has estimated the cost of providing additional fabric filters for both the wet and
dry process plants [TEK81J. The estimated capital costs of the systems (1979 $) are approximately
$2.1 million and $4.5 million for the wet and dry plant, respectively. The total annual costs
(operating and maintenance) for the wet and dry process plants are approximately $0.6 million and
$1.3 million, respectively (EPA89],
1.3.3.3 Uranium Fuel Fabrication Facilities
Current control techniques for fuel fabrication facilities depend upon the processes involved. The
ammonium diuranate facility process gases are processed through wet scrubbers and high efficiency
particle air (HEPA) filters with 90 and 95 percent efficiency, respectively. Ventilation off-gases are
sent through roughing and HEPA filters prior to discharge. The direct conversion facility process
gas is passed through sintered metal filters to remove solids and then to scrubbers for HF removal,
dilution and final discharge.
1.3.3.4 Nuclear Power Reactors
Nuclear power reactors in use in the U.S. are of two types: boiling water reactors (BWRs) and
pressurized water reactors (PWRs); While there are common approaches to control of radionuclide
emissions released to the atmosphere from the two types of reactors, there are also differences in
approach.
Both types of reactor use HEPA filters and charcoal filtration units to remove particulate and
radioiodine emissions from building and ventilation exhausts. HEPA filters are designed and treated
to ensure 99.97 percent efficiency for particulate emissions. Charcoal filters can be designed for
various levels of efficiency, the most common of which has a decontamination factor of 100. Both
also employ various strategies to delay the release of noble gases, allowing those with shorter lives
to decay before being released. Both BWRs and PWRs also employ various indirect methods of
1-15
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reducing atmospheric emissions. These are applied to individual pumps, tanks and valves on a case-
by-case basis.
There are also control strategies and methods that are applied to BWRs or PWRs uniquely, depending
on their special features. Because there are so many possible configurations, and the cost of each
element depends on factors specific to the application, there is no concise summary of costs for
controlling radioactive emissions from nuclear power reactors.
1.4 Industry Cost and Economic Impact Analysis
Any radionuclide emission control costs imposed on the uranium fuel cycle facilities would be
expected to weaken further the position of the domestic nuclear industry. Alternative sources of
nuclear fuel supply from imports and the alternatives to nuclear electric power will become more
attractive if uranium fuel production costs increase.
1-16
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REFERENCES
AEC74 U. S. Atomic Energy Commission, Fuels and Materials Directorate of Licensing,
Environmental Survey of the Uranium Fuel Cycle, April 1974.
DO88 Dolezal, W., personal communication with Dave Goldm, SC&A, Inc., September 1988.
DOE87 U.S. Department of Energy, Domestic Uranium Mining and Milling Industry: 1986
Viability Assessment, DOE/EIA-0477 (86), November 23, 1987.
EPA79 U.S. Environmental Protection Agency, Radiological Impact Caused by Emissions
of Radionuclides in Air in the United States, preliminary report, EPA 520/7-79-006,
August 1979.
!PA84a U. S. Environmental Protection Agency, Final Rule for Radon-222 Emissions from
Licensed Uranium Mill Tailings, Background Information Document for Final Rules,
volume II, EPA /520-1-84-022-2, October 1984.
EPA84b U. S. Environmental Protection Agency, Radionuclides: Background Information
Document for Final Rules, volume I, EPA 520/1-84-022-2, October 1984.
EPA89 Risk Assessments, Vol. 2.
NN88 Nuclear News, February 1988.
NRC74 U. S, Nuclear Regulatory Commission, Environmental Statement Related to Operation
of Shirley Basin Mill, December 1974.
NRC80 U. S. Nuclear Regulatory Commission, Final Generic Environmental Impact Statement
on Uranium Milling, September 1980.
NRC82 U. S. Nuclear Regulatory Commission, Technical Guidance for Siting Criteria
Development, NUREG//CR-2239, November 1982.
NRC84 U. S. Nuclear Regulatory Commission (NRC), Environmental Impact Appraisal for the
Renewal of Source License No, SUB-526, NUREG-1071, May 1984.
NRC85a U. S. NRC, Environmental Assessment for Renewal of Special Nuclear Material
License No. SNM-I107, NUREG-1118, May 1985.
NRC85b U, S. NRC, op cit., August 1985.
1-17
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CHAPTER 2
UNDERGROUND URANIUM MINES
-------
2. UNDERGROUND URANIUM MINES
2.1 INTRODUCTION
Underground uranium mines are part of the domestic uranium industry that provides commercial
nuclear power plants their fuel. Other industrial categories in this industry are surface uranium
mines, uranium mills and other segments of the nuclear fuel cycle. All these activities are dependent
to a degree on nuclear power plants to generate demand for their output.
As is detailed in Chapter 4 of this volume, "Licensed Uranium Mill Tailings," and summarized in this
chapter, the demand for the products of domestic uranium production has been falling for some
time. Most mines and mills have gone out of production and many are permanently closed. The
remaining are analyzed here.
This chapter provides a brief profile of the uranium industry, describes the options for reducing
radon emissions from underground mines, the health benefits attributable to each option, the costs
attributable to each option and the impacts a regulation would have on the industry, the miners, their
communities and the U.S. economy.
2.2 industry Profile
The U.S. uranium mining industry is an integral part of a domestic uranium production industry that
includes companies engaged in uranium exploration, mining, milling, and downstream activities
leading to the production of fuel for nuclear power plants. The product of uranium mining is
uranium ore.
2.2.1 Demand
Domestic producers of uranium ore send it to uranium mills. The mills have two markets for their
production; the U.S. nuclear power industry and exports. The nuclear power industry is by far
the more important of the two. Military uses, once the only source of demand for uranium, have
been supplied solely by government stockpiles since 1970 [DOE 87a].
Demand for domestic uranium has declined since the late 1970s. In 1979, utilities delivered 15,450
tons of domestic uranium oxide to DOE for enrichment, 86 percent more than 1986 deliveries.
Exports too have declined substantially. In 1979, exports amounted to 3,100 tons, almost four times
as much as in 1986. A number of negative forces have combined to cause the current depressed state
2-1
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of the industry, Perhaps most importantly, the growth In electricity generated by nuclear plants and
the expansion of nuclear power capacity has been much slower than had been forecast jn the mid-
1970s. Th is slower growth is due in part to numerous construction delays and cancellations. Second,
imports have begun to play a major role in the U.S. uranium market. Import restrictions were
gradually withdrawn between 1975 and 1985. The result has been a steady increase in uranium
imports from nations possessing high grade (and thus low cost) uranium deposits. Expectations are
that a growing portion of utility requirements will be supplied by foreign-origin uranium during the
second half of this decade [JFA 85a],
Also contributing to the current downturn in the uranium industry are the large inventories being
held by both producers and utilities. Utilities, anticipating a growing need for uranium, entered into
long-term contracts to purchase large amounts of domestically-produced uranium. As actual needs
fell short of expected needs due to nuclear power plant construction delays and cancellations, large
inventories accumulated. These inventory supplies, currently estimated to cover four to five years
of utility requirements, adversely affect suppliers in two ways. They may extend the downturn in
uranium demand for a number of years by decreasing the need for utilities to enter into new
contracts. Also, high interest rates increased inventory holding costs, leading some utilities to
contribute to current excess supply by offering inventory stocks for sale on the spot market
[JFA 85a], More detail on uranium uses can be found in Chapter 4 of this volume.
2.2.2. Sou rces of Supply
The uranium used to fuel nuclear reactors is supplied by domestic and foreign producers, inventories
held by utilities, and secondary market transactions such as producer-to-producer sales,
utility-to-utility sales and loans, and utility-to-producer sales. The role of each is described in the
following sections.
2.2.2.1 Domestic Production
Table 4-7 in Chapter 4 shows trends in domestic production of uranium concentrate from 1947 to
1986, by state. Total production was relatively constant at 10,500 to 12,500 tons per year until 1977,
when it began an increase that peaked in 1980 at 21,852 tons. Production has declined almost every
year since, reaching only 6,753 tons in 1986 [DOE 87b],
2-2
-------
2.2,2.2 Imports
A second source of uranium is the import market. Until 1975, foreign uranium was effectively
banned from U.S. markets by a Federal law prohibiting the enrichment of imports for domestic use.
This restriction was lifted gradually after 1975, and was eliminated completely in 1984. From 1975
through 1977, imports amounted to a small portion of total domestic requirements, and U.S. exports
actually exceeded imports in each year from 1978 through 1980. By 1986, however, imports supplied
44 percent of U.S. requirements. Table 4 -10 in chapter 4 lists U.S. imports from 1974 through 1986
[DOE 87a],
Historically, the primary sources of U.S. uranium imports were Canada, South Africa and Australia.
In 1986, 59 percent of U.S. uranium imports were from Canada, and 41 percent were from Australia
and South Africa [DOE 87a],
Forecasts of import penetration call for the import share to grow through the 1990's. The Department
of Energy projects that without government intervention, between the years 1990 and 2000 imports
will range between 50 and 64 percent of domestic utility requirements, depending on demand.
2.2.2.3 Inventories
Utilities hold uranium inventories in order to meet changes in the scheduling of various stages of the
fuel cycle, such as minor delays in deliveries of uranium feed. Uranium inventories also protect the
utilities against disruption of nuclear fuel supplies. The average "forward coverage" currently desired
by domestic utilities (in terms of forward reactor operating requirements) is 18 months for natural
uranium (U3Og) and seven months for enriched uranium hexafluoride (UF6) [DOE 85a]. Table 4-
11 in chapter 4 lists inventories of commercially-owned natural and enriched uranium held in the
United States as of December 31, 1984, 1985, and 1987. DOE-owned inventories are not included.
The uranium inventory owned by utilities alone at the end of 1984 represented almost four years of
forward coverage.
2.2.2.4 Secondary Market Transactions
The secondary market for uranium includes producer-to-producer sales, utility-to-utility sales and
loans, and utility-to-producer sales. The secondary market, by definition, does not increase the
supply of uranium, only the alternatives for purchasing it. As such, secondary transactions can have
a significant impact on the demand for new production and on the year-to-year changes in
2-3
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inventories. The secondary market has been significant in recent years. During i986, sales of 6,800
tons of UjOg equivalent were made between domestic utilities and suppliers in the secondary market.
2.2.3 Financial Analysis
Selected financial data for the domestic uranium industry for 1982 to 1986 are shown in Table 4-
' " in copter 4. The data cover a subset of firms (the same firms for all years) that represent over
80 percent of the assets in the industry in each year. The firms included are those for which uranium
operations could be separated from other aspects of the organization's business, and for which an
acceptable level of consistency in financial reporting practices was available for all years.
As shown in Table 4-18 in chapter 4, net income accruing to the uranium industry was positive in
only two years, 1982 and 1983. The returns on assets (net income divided by total assets) in these
years were 0.7 and 1.4 percent respectively, and aggregate net earnings totalled $69.8 million. In
1984, 1985, and 1986, the returns on assets were -10.3, -21.6, and -2.3 percent, and aggregate net
losses reached $765.7 million. The loss in 1984 alone was $304.7 million on revenues of $608.9
million. Thus, the aggregate loss for the five years was $695.9 million. In 1977, 146 firms were
involved in domestic uranium exploration, 135 in mining and 26 in milling. In contrast, only 31
firms were actively engaged in exploration, 11 in mining and 5 in milling toward the end of 1986.
Of these firms, only 27 percent had positive net income after meeting operating expenses and other
obligations such as payment of taxes and recovery of depletion, depreciation and amortization. Many
of the firms (55 percent) reported net losses; the remaining 18 percent either had left the industry
or had no data to provide.
Most of the financial improvement in 1986 stemmed from the slowdown or the completion of
writeoffs of discontinued operations, revaluation of assets and abandonments. The domestic uranium
industry is significantly smaller than before, and its financial state will depend on higher product
prices or demand [DOE 87a],
Company-specific information on uranium production, revenues, profits, and plans is provided in
the following paragraphs. More detail is provided in Chapter 4.
2.2.3.1 Homestake Mining Company
Homestake Mining Company owns one conventional uranium mine and a 3400 ton per day mill in
Grants, New Mexico. During 1984, production of uranium was reduced to the minimum level at
which satisfactory unit costs could be maintained. Mine production has been confined to one mine
2-4
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operating on a five-day-week schedule for ten months of the year. Uranium concentrate was also
recovered from solution mining and ion-exchange. In 1986, uranium accounted for 14 percent of
the company's revenues, and 21 percent of operating earnings. The high profitability of the sector
for the year is attributed to existing contracts, expiring in 1987, that provide for sale prices above
current spot prices and production costs [AR 84, AR 85, AR 86}.
Rio Algom is a Canadian corporation engaged in the mining of a wide variety of materials, including
copper, steel, and uranium. In 1986, uranium operations accounted for 26 percent of corporate
revenue, but most (89 percent) was from Canadian production. In the United States, the company
owns one uranium mine and a 750 ton per day mill in La Sal, Utah.
In 1986, the company produced 457 tons of uranium oxide from its Utah mine. The mine operated
at approximately 50 percent of capacity in 1986, while the mill operated at capacity due to a
significant amount of toll milling [AR 86].1 In 1987, the La Sal mill produced about 350 tons of
uranium oxide using both company ore and ore from the Thornberg mine. The mill was placed on
standby in September of 1988, because the Lisbon and Thornberg mines' reserves were depleted [EPA
89],
2.2.3.3 Plateau Resources Limited
Plateau Resources, a wholly owned subsidiary of Consumers Power Co., was organized in 1976 to
acquire, explore, and develop properties for the mining, milling, and sale of uranium. All operations
were suspended in 1984 because of depressed demand and ail uranium assets were written down by
$46 million after taxes in 1984 and $21 million in 1985, to an estimated, net realizable value of
approximately $34 million. There is no assurance that the amount will ever be realized however.
2.2.3.4 Western Nuclear
Western Nuclear, a subsidiary of Phelps Dodge Corporation, owns two mine and mill complexes, one
in Wyoming and one in Washington. The capacities of its mills are 1700 and 2000 tons per day,
respectively. The Wyoming mill has been on standby since the early 1980s, and decommissioning is
anticipated. The Washington complex operated intermittently from 1981 through 1984. In late 1984,
1 "Toll milling" is the processing of ore from another company's mines on a contract basis.
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Phelps Dodge wrote off its entire "Energy" operation, of which Western Nuclear was a major part
(AR 84, AR 85}.
2,2,4 industry Forecast and Outlook
This section presents projections of total U.S. utility market requirements, domestic uranium
production, from both conventional and non-conventional sources, imports, employment and
electricity consumption. Developed for a 14-year period (1987-2000), these projections are
considered "near term." A basic assumption of the near term projections is that current market
conditions, as defined by the Department of Energy's Energy Information Administration
(DOE,EIA), will continue unchanged through the end of this century. This section is based on the
reference case projections in EIA's Domestic Uranium Mining and Milling Industry: 1986 Viability
Assessment [DOE 87a],
2.2.4.1 Projections of Domestic Production
The EIA's Reference case2 forecasts, for the 1987-2000 time period, are based on the output of EIA's
economic model, Domestic Evaluation of Uranium Resources and Economic Analysis (EUREKA).
The EUREKA model's methodology goes beyond the scope of this study; it is fully described in
Appendix C of the 1986 Viability Assessment. The EIA examines future developments in the
domestic uranium industry and in the domestic and international uranium markets under current
market conditions and under certain hypothetical supply disruption scenarios3. The current market
conditions are generally the same as those presented in Sections 4.2.1-4.2.4 of this study and are based
on historical trends in the domestic uranium industry as outlined in both the Viability Assessment
and the EIA's Uranium Industry Annual 1986.
2Prior to the 1986 Viability Assessment, EIA published two reference cases: a Lower Reference
case and an Upper Reference case, each with a low, a mean, and a high range of projected values.
In 1986, however, only the Lower Reference case was published. It is referred to simply as the
Reference case. As before, low, mean and high projected values were produced by EIA. This study
uses the mean.
The Reference case in the J986 Viability Assessment uses the underlying assumptions for the Lower
Reference case described in Commercial Nuclear Power 1987: Prospects for the United States and
the World [DOE 87a].
3These scenarios, the "current disruption status" scenario and the "projected disruption status"
scenario, are used to test the viability of the U.S. uranium industry, to examine the ability of this
industry to respond to an abrogation of various fractions of contracts for uranium imports intended
for domestic end use. Both of these bear only tangentially on this study and will not be discussed
further here.
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2.2.4,2 Near-Term Projections
Total domestic production of U3Oa, from both conventional and non-conventional uranium sources,
for 1980-1986 is shown in Table 4-18 of chapter 4, along with reference case projections for 1987-
2000, Annual domestic production peaked at 21,900 short tons after milling in 1980, and declined
to 6,750 short tons in 1986. Production is projected to remain below its 1980 peak. For example,
El A has projected domestic U3Oa production in 1992 at 6,450 short tons, while the output in the year
2000 is estimated to be 7,500 short tons. Annual domestic production from conventional mining
sources (i.e., from milling ore obtained from underground or open-pit mines, which historically has
accounted, on average, for roughly 70 percent of total annual domestic production) has fallen more
steeply, from 85 percent in 1980 to 53 percent in 1985. However, it increased from its 1985 level of
3,275 short tons to 5,825 short tons in 1986, This increase was due to an increase in the U3Og
concentration of the ore milled in that year.
Changes in the market, such as the ban on imports of uranium ore or concentrate from South Africa
and Namibia4, could influence conventional production much more than non-conventional UjOg
production, because non-conventional U3Og producers tend to have lower marginal costs of
production than do conventional producers. Therefore, production from non-conventional sources
tends to be less affected by fluctuations in uranium market prices. Wet process phosphoric acid,
copper waste dumps, and bellyrium ores constitute by-product methods of production of L'3Og. The
second significant non-conventional source is in situ leaching. By-product and in situ leaching both
accounted for 79 percent of the total non-conventional annual production of U3Os in 1986. Other
sources include mine water, and heap leaching, which accounted for the remaining 21 percent of total
annual non-conventional production in 1986.
The Reference case El A projections of domestic U 3Og production through the year 2000 are based
on a unit by unit review of nuclear power plants that are new, operating, under construction, or units
for which orders have been placed and for which licenses are currently being processed. Under ElA's
Reference case, nuclear generating capacity is expected to increase from 94.0 GWe in 1987 to 103.0
GWe in the year 2000 (Table 4-19). Historical and forecast data of total enrichment feed deliveries
(demand), net imports, and total production are graphed in Figure 4-1 [DOE 87a]. Historical data
4The U.S. Congress passed the Comprehensive Anti-Apartheid Act of 1986 on October 2, 1986.
Section 309 of that Act forbade the import into the United States of uranium ore or concentrate of
South African of Namibian origin after January 1, 1987. However, natural or enriched uranium
hexafluoride from these countries may be imported, according to a regulation issued by the U.S.
Department of the Treasury on which the U.S. Nuclear Regulatory Commission has concurred
[EPA 87b].
2-7
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and reference case projections for conventional and non-conventional production of domestic
uranium are plotted in Figure 4-2.
2.3 Current Emissions. Risk Levels, and Feasible Control Methods
2.3.1 Introduction
In this section, the current risks due to radon emissions from underground uranium mines are
described, ways of reducing these risks are discussed and the effects of two alternative rules for
reducing the risks to maximum exposed individuals due to radon emissions from uranium mines are
estimated.
2.3.2 Current Emissions and Estimated Risk Levels
Due to the ongoing decline of the uranium industry, the list of firms in operation, shown in Table
2-1, has continued to shrink. As of the fall of 1988, fourteen mines were producing and one other,
the Schwartzwalder mine owned by the Cotter Corporation, was on standby and was being explored.
Three of the producing mines, Pigeon, Pinenut and Kanab North, all owned by Energy Fuels
Nuclear, Inc., were breccia-pipe mines, which will be mined out in two to five years. Sheep
Mountain #1 will operate for five more years. Only the Mt. Taylor mine, with an expected life of
twenty years, has the possibility of operating for a significant amount of time. Section 23, owned
by the Homestake Mining Company, has an expected life of only 1.25 years. Information regarding
the expected life of the other eight mines is not available.
Estimates of current emissions and risk levels for these fifteen mines, ranked by maximum individual
risk (MIR), are shown in Table 2-2. Although Section 23 has the highest rate of radon emissions,
the highest individual risk is due to the La Sal mine and the highest population risk is due to
emissions from the Schwartzwalder mine.
2.3.3 Control Technologies
2.3.3.1 Introduction
After extensive efforts to devise control technologies that would reduce the emissions of radon-222
from underground mines, it was concluded that no suitable technology is available [EPA 89], The
approaches discussed here seek to limit the emissions of the mines by restricting their days of
operation and to reduce the risks from radon emissions to nearby populations by installing stacks that
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Table 2-1. Currently Operating Underground Uranium Mines in the United States.
State/Mine
Company
Type Expected Assumed Current
life
Arizona
Kanab North
P i geon
Pinenut
Colorado
CalI iham
Oeremo-Snyder
King SoIoman
Ni L
Schwartswalder
Energy Fuels Nuclear, inc
Energy Fuels Nuclear, Inc
Energy Fuels Nuclear, Inc
UMETCO Minerals Corp.
UMETCO Minerals Corp.
UMETCO Minerals Corp.
UMETCO Minerals Corp.
Cotter Corp.
Sunday UMETCO Minerals Corp.
Hitson-SiverbelI UMETCO Minerals Corp.
New Mexico
Mt. Taylor
Section 23
Utah
La sal
Snowba11-Pandora
yyoroing
Sheep Mountain 1
Chevron Resources Co.
Homestake Mining Co.
UMETCO Minerals Corp.
UMETCO Minerals Corp.
U.S. Energy Co.
Breccia-pipe
Breccia-pipe
Breccia-pipe
Modified Room
and Pi I tar
Modified Room
arid Pi I lar
Modified Room
and Pi 1lar
Modified Room
and Pi Ilar
Modified Room
and Pi liar with
Vein Structure
Modified Room
and Pi liar
Modified Room
and Pillar
Modified Room
and Pi Ilar
Modified Room
and Pi Ilar
Modified Room
and Pi liar
Modified Room
and Pillar
Random Drifting
NA
NA
NA
NA
Standby
NA
NA
20
1.25
NA
NA
270-360
270-360
270-360
NA
280
350
50
0
200
90
544
68
160
54
220
NA: Information Not Available
Source: (EPA89)
2-9
-------
TABLE 2-2 CURRENT RISK LEVELS DUE TO RADON-222
(Ranked by Maximum Individual Risk)
Maximum
Exposed
Individual Regional Exposure
I
Committed Fatal
Annual Radon-222
lifetime
1980 Population
Cancers Per tr
Mine
Release (Ci/y)
»„.i „. „ „. - ....
Cancer Risk
u/in 80 kit
{0-80 km)
La Sal
I
2460
I I
4.41-03
1
21,000
3.0E-03
Deremo-Snyder
960
1.71-03
30,000
1.0E-03
Sno«ba((-Pandora
2920
1.3E-03
21,000
4.06-03
Schwartzwalder
6385
1.2E-03
1,800,000
7.0E-01
Cat Iiham
260
1.16-03
30,000
4.0E-04
Sect tori 23
8894
4.1E-04
65,000
5.0E-02
King Solomon
2020
3.5E-04
67,000
5.0E-03
WiI son-Si IverbeLL
790
3.4E-04
30,000
1.06-03
Sunday
3120
3.3E-04
24,000
4.0E-03
Nil
690
7.3E-05
55,000
2.0E-03
Pigeon
2560
6.1E-05
7,800
2.0E-03
Mt. Taylor
2180
3.6E-05
50,000
3.0E-03
Kanab North
1640
2.4E-05
11,000
1.0E-03
Sheep Mountain No. 1
170
6.5E-06
5,200
2.0E-04
Pinenut
350
2.7E-06
8,300
2.0E-04
TOTAL 7.8E-01
2-10
-------
would reduce the higher concentrations of radon-222 at sites close to the mines. The proposed
regulations would allow combinations of these measures, and other measures that may be developed
in the future, so long as risk is reduced to acceptable levels.
Three alternative rules are under consideration and are discussed in this chapter. The first is to
require mines to reduce emissions through partial shutdowns and stack installations such that the
lifetime risk of cancer for the most exposed individual, also referred to as maximum individual risk
(MIR), is under 3F.-4. The second is to similarly reduce the MIR to below 1E-4. The third is to
reduce the MIR to below 3E-5.
2.3.3.2 Alternative One: Maximum Individual Risk Under 1E-4
The first alternative rule is that mines should employ a combination of 1) a reduction of operating
days per year to reduce annual radon-222 emissions and 2) construction of stacks to release radon-
222 emissions from higher elevations such that the risk of fatal cancer to the most exposed individual
is reduced to under 1E-4, Both of these measures have the effect of reducing the lifetime risk of
fatal cancer to the most exposed individual.
While reduced operations are feasible, there are some complications in estimating the cost and the
amount of emission reductions that would result. This is because the costs of temporarily closing a
mine and maintaining it while it is closed are not clear. Some venting of the mine will be necessary
for the safety of maintenance workers. This venting would affect the reduction of radon emissions
that would be otherwise achieved. Estimating the cost of the vents is more straight forward.
Analysis of the emission and risk levels due to alternative one, shown in Table 2-3, is based on the
assumption that radon emissions are proportional to the percentage of time the mine is open.
Six of the mines -- Mt. Taylor, Nil, Pinenut, Sheep Mountain No. 1, Pigeon, and Kanab North --
can meet alternative one without reducing emissions or increasing stack height. Note that the Mt.
Taylor mine already has a twenty meter stack.
In determining the measures to be taken to meet alternative one, the MIR for each combination of
stack height (baseline, 10, 20, 30 and 60 meters) and reductions in emissions from zero to one
hundred percent was calculated. For each stack height, the smallest emission reduction that reduced
the MIR to the designated level was then determined. The least costly combination of emission
reduction and stack height for each mine was selected for further analysis. This analysis is discussed
more thoroughly in section 2.4.2 below.
2-11
-------
Table 2-3: Alternative 1; Measures Taken and Their Effects on Maximun Exposed Individuals and
Populations within 80 km
Alternative 1; MIR BELOW 3E-4
Reduction Annual Risk to
Reduction
Stack
Emission
from initial
Population
in Population
mine
Height
Reduction
MIR
KIR
within 80 km
Risk
La Sal
0
95%
2.2E-04
4.2E-03
1.5E-04
2.9E-03
Schwartzwalder
0
75%
3.0E-04
9.QE-04
1.8E-01
5.36-01
CalIiharo
0
75%
2.8E-04
8.3E-04
1.0E-04
3.0E-04
Oeremo-Snyder
0
65%
2.6E-04
1.4E-03
1.56-04
8.5E-Q4
Snowball-Pandora
0
80%
2.0E-04
1.1E-03
8.06-04
3.2E-03
UiIson-SiIverbelI
0
15%
2.9E-04
5.1E-05
8.5E-04
1.5E-04
King Solomon
0
15%
3.0E-04
5.2E-05
4.36-03
7.5E-04
Section 23
0
30%
2.9E-04
1.2E-04
3.5E-02
1.5E-02
Sunday
0
10%
3.0E-04
3.3E-0S
3.6E-03
4.06-04
Mt. Taylor
20
0%
3.6E-05
0.QE+Q0
3.0E-03
0.0E+00
Sheep Mountain No. 1
0
0%
6.5E-06
0.0E+00
2.0E-04
O.OE+OO
Pinenut
0
01
2.7E-Q6
0.0E+O0
2.0E-04
O.OE+OO
Kanab North
0
0%
2.4E-05
Q.0E+00
1.0E-03
O.OE+OO
Nil
0
0%
7.3E-05
0.0E+00
2.0E-03
O.OE+OO
Pigeon
0
0%
6.1E-05
O.OE+OO
2.0B-03
O.OE+OO
2-12
-------
2,3,3.3 Alternative Two: Maximum Individual Ri.sk Under 1E-4
Table 2-4 describes the emissions and risk levels due to alternative two. Alternative two would
require some mines to further reduce operations in order to additionally reduce cancer risks to the
most exposed individuals. The same six mines that would not have to do anything under alternative
one would still not have to do anything under alternative two.
2-3.3.4 Alternative Three: Maximum Individual Risk Under 3E-5
Table 2-5 describes the emission and risk levels due to alternative three. Alternative three would
require some mines to further reduce operations or increase stack height in order to additionally
reduce cancer risks to the maximum exposed individuals. Note that three mines -- Sheep Mountain
No. I, Kanab North, and Pinenut -- meet alternative three without any reduction of emissions or
construction of stacks. The same issues as are involved in alternative one and two pertain to
alternative three.
2.4 Analysis of Benefits and Costs
2.4.1 Introduction
In this section, the benefits and costs of the alternatives under consideration are examined. Benefits
in terms of reductions of the risk of cancer to the most exposed individual and the 80 km population
are demonstrated. Costs for alternative one and two and cost differentials between the base case and
alternatives one and two are calculated. Finally, the effects of various assumptions on the conclusions
drawn in the above are assessed.
2.4.2 Least-Cost Control Strategies for Meeting Alternatives One. Two and Three
In order to complete the analysis of alternatives one, two, and three, it is necessary to determine
which combination of control parameters (emission reductions and stack heights) the mines' operators
would select. The rule allows them a set of options; the analysis assumes they would choose the least
costly option that meets the rule. Tables 2-3, 2-4, and 2-5 above show the outcome of the analysis
in terms of the combination of emission reduction and stack height selected, reductions in MIR and
population risk. This section discusses the details of the analysis.
The example used in this discussion is Pigeon Mine. Table 2-6 shows a matrix of maximum
individual risks (MIRs) for various combinations of emission reductions and stack heights for Pigeon
2-13
-------
Table 2-4: Alternative 2: Measures Taken and Their Effects ori Maxiawn Exposed individuals and
Populations within 80 km
Alternative 2; MIR BELOW 1E-4
Reduction Annual Risk to
Reduction
Stack
Emission
from initial
Population
in Population
mine
Height
Reduct i on
MIR
MIR
within 80 km
Risk
la Sal
0
100%
O.OE+OO
4.4E-03
0.0E+00
3.0E-03
Schwartzwalder
0
95X
6.OE-05
m
©
w
3.5E-02
6.7E-01
Cat Iiftam
0
95X
5.5E-05
1.0E-03
2.0E-05
3.8E-04
Deremo-Snyder
0
95%
8.SE-05
1.6E-03
5.0E-05
9.5E-04
Snowball - Pandora
D
95%
6.SE-05
1.2E-03
2.0E-04
3.8E-03
WiIson-SiIverbelI
0
75%
8.SE-05
2.6E-04
2.5E-04
7.5E-04
King Solomon
0
75%
8.SE-05
2.6E-04
1.3E-03
3.8E-03
Section 23
0
80X
6.2E-05
3.5E-04
1.0E-02
4.0E-02
Sunday
0
70*
9.9E-05
2.3E-04
1.2E-03
2.8E-03
Mt. Taylor
20
0%
3.&E-05
O.OE+OG
3.0E-03
O.OE+OO
Sheep Mountain No. 1
0
OS
6.5E-06
O.OE+QO
2.0E-04
0.0E+00
Pinenut
0
ox
2.7E-06
0.0E+00
2.0E-04
0.0E+00
Kartab North
0
0%
2.4E-0S
O.OE+OO
1.0E-03
O.OE+OO
Ni I
0
0%
7.3E-05
O.OE+OO
2.0E-03
0.0E+00
Pigeon
0
0%
6.1E-05
O.OE+OO
2.0E-03
0.0E+00
2-14
-------
Table 2-5: Alternative 3: Measures Taken and Their Effects on Maximum Exposed Individuals and
Populations within 80 km
Alternative 3; MIR BELOW 3E-5
Reduction
Annual Risk to
Reduction
Stack
Emi ssion
from initial
Population
in Population
mi ne
Height
Reduction
MIR
MIR
within 80 km
Risk
La Sal
0
100%
0.OE+0Q
4.4E-03
O.OE+OO
3.0E-03
SchwartzwaSder
0
100%
O.OE+OO
1.2E-03
O.OE+OO
7.0E-01
Cal Ufiam
0
100%
O.OE+OO
1.IE-03
0.OE+00
4.0E-04
Deremo-Snyder
0
100%
O.0E+OO
1.7E-03
O.OE+OO
1.0E-03
Snowba II - Pandora
0
100%
O.OE+OO
1.3E-03
O.OE+OO
4.0E-03
WiIson-SiIverbelI
0
95%
1.7E-05
3.2E-04
5.0E-05
9.5E-Q4
King Solomon
0
95%
1.8E-05
3.3E-04
2.5E-04
4.8E-03
Section 23
0
95%
2.1E-05
3.9E-04
2.5E-03
4.8E-02
Sunday
0
95%
1.7E-05
3.1E-04
2.0E-04
3.8E-03
Mt. Taylor
30
0%
2.7E-05
9.0E-06
3.0E-03
O.OE+OO
Sheep Mountain No. 1
0
0%
6.5E-06
O.OE+OO
2.0E-04
0.0E+00
P i nenut
0
0%
2.7E-06
0.0E+00
2.0E-04
0.0E+00
Kanab North
0
0%
2.4E-05
0.0E+00
1.0E-03
O.OE+OO
Hi I
0
60%
2.9E-05
4.4E-05
8.0E-04
1.2E-03
Pigeon
60
0%
3.0E-05
3.1E-05
2.0E-03
O.OE+OO
2-15
-------
Table 2-6: Matrix of MIRs as Stack Height end Emissions
at Pigeon Mine Vary
RISK TO NEAREST INDIVIDUAL (KIR)
REDUCTION - REDUCTION
IN STACK HEIGHT IN
EMISSION ---- EMISSJOH
LEVEL ON 10 U 20 M 30 M 60 M LEVEL
100%
O.QE+QO
O.OE+OO
O.OE+OO
O.OE+OO
O.OE+OO
100%
95%
3.1E-06
3.0E-06
2.8E-06
2.5E-06
1.5E-06
95%
90%
6.1E-06
5.9E-06
5.66-06
5.0E-06
3.0E-06
90%
85%
9.2E-06
8.9E-06
8.4E-06
7.5E-06
4.5E-06
85%
80%
1.2E-05
1.2E-05
1.1E-05
1.0E-05
6.0E-06
80%
75%
1.5E-05
1.5E-05
1.4E-05
1.3E-05
7.5E-06
75%
70%
1.8E-05
1.8E-05
1.7E-05
1.5E-05
9.0E-06
70%
65%
2.1E-05
2.1E-05
2.0E-05
1.7E-05
1.1E-05
65%
60%
2.4E-05
2.4E-05
2.2E-05
2.0E-05
1.2E-0S
60%
55%
2.7E-05
2.7E-05
2.5E-05
2.3E-05
1.4E-05
55%
50%
3.1E-05
3.0E-05
2.8E-05
2.5E-05
1.5E-05
50%
45%
3.4E-05
3.2E-05
3.16-05
2.8E-05
1.7E-05
45%
40%
3.7E-05
3.5E-05
3.4E-05
3.0E-05
1.8E-05
40%
35%
4.0E-05
3.8E-05
3.6E-05
3.3E-05
2.0E-05
35%
30%
4.3E-05
4.1E-05
3.9E-Q5
3.5E-05
2.1E-05
30%
25%
4.6E-05
4.4E-05
4.2E-05
3.8E-05
2.3E-05
25%
20%
4.9E-05
4.7E-05
4.5E-05
4.0E-05
2.4E-05
20%
15%
5.26-05
5.0E-05
4.8E-05
4.3E-05
2.6E-05
15%
10%
5.5E-05
5.3E-05
5.0E-05
4.5E-05
2.7E-05
10%
5%
5.8E-05
5.6E-05
5.3E-05
4.8E-05
2.9E-05
5%
0%
6.1E-05
5.9E-05
5.6E-05
5.0E-05
3.0E-05
0%
0 M
10 M
20 K
30 H
60 M
2-16
-------
Mine. For each stack height, MIRs increase as reductions in emission levels decrease. For alternative
two, MIR < le-4, looking down the column for a stack height of zero (i.e., the baseline stack height),
the table shows the rule can be met at Pigeon Mine with no emission reductions. The largest number
in the column is less than 1E-4. Table 2-7 shows the reduction in emission levels needed to comply
with alternatives one, two, and three. For each stack height, alternatives one and two can be satisfied
with no emission reductions. When the third alternative is considered, looking down the first column
of Table 2-6 indicates that a fifty-five percent reduction in emissions is needed to meet the 3E-5
limit. With a stack height.of ten meters, a fifty percent reduction is needed; with a stack height of
twenty meters, a fifty percent reduction is again needed; for thirty meters, a forty-five percent
reduction suffices; and for a sixty meter stack, no emission reduction is required.
The next step is to determine associated costs. Table 2-8 shows the cost for each stack height and
emission reduction combination. These costs are summarized in table 2-7. The costs of constructing
stacks of various heights were obtained from [SC89]. The other cost component is the present value
of the opportunity cost to the mine owners of removing the various quantities of uranium from the
market due to shutdowns. It was assumed, based on historical records, that all but two percent of
mine revenues are used to pay obligations to workers, capital improvements and other costs of doing
business. Also, the price of uranium at the mines was assumed to be $110.23 per MT. The
opportunity cost calculations were done without discounting. This accentuates the relative value of
uranium mined in future years. It is therefore interesting that tables 2-3, 2-4, and 2-5 indicate that
partial and sometimes complete shutdowns are less costly to mine owners than building stacks. Only
Pigeon Mine and Mt. Taylor Mine would opt for stack construction, and Mt. Taylor already has a
twenty meter stack.
In the case of Pigeon Mine the value of the uranium that could be mined if a sixty meter stack were
installed was sufficient to justify building the stack. Figure 2-1 (based on Table 2-7) shows that the
overall cost of complying with alternative three at Pigeon Mine at first remains relatively constant,
reaching a maximum at twenty meters, and then declines sharply after thirty meters. Sixty meters
is the optimal stack height for Pigeon Mine under alternative three because it meets the rule. A taller
stack would gain nothing because it would not allow any greater production of uranium.
Analyses similar to that done for Pigeon Mine were also performed for the other fourteen mines.
These are summarized in Tables 2-3, 2-4, and 2-5 above.
2-17
-------
TABLE 2-7: Pigeon Mine, Summary of Risk Reductions and Costs
risk to nearest individual
for MIR <= 3e-4
REDUCTION
IN
STACK HEIGHT
EMISSION
resulting
{in meters)
LEVEL
MIR
cost
0
0%
6.1E-05
$0
10
ox
5.9E-05
$31,200
20
0%
5.6E-05
$80,500
30
0%
5.0E-05
$146,600
60
0%
3.0E-05
$291,400
Mini mum cost:
$0
risk to nearest
individual
for MIR <= 1e-4
REDUCTION
IN
STACK HEIGHT
EMISSION
resulting
(in meters)
LEVEL
MIR
cost
0
0%
6.1E-05
$0
10
0%
5.9E-05
$31,200
20
0%
5.6E-05
$80,500
30
0%
5.0E-05
$146,600
60
0%
3-0E-05
$291,400
Minimum cost:
$0
risk to nearest
individual
for MIR <= 3e-5
REDUCTION
IN
STACK HEIGHT
EMISSION
resulting
(in meters)
LEVEL
MIR
cost
0
55%
2.7E-05
$836,464
10
50%
3.0E-05
$791,622
20
50%
2.8E-05
$840,922
30
45%
2.86-05
$830,979
60
OX
3.0E-05
$291,400
Minimum cost: $291,400
2-18
-------
TABLE 2-8: Matrix of Costs of Various Combinations of Stack Height and
Shutdown Time for Pigeon Mine.
The last column is the cost
of shutdown by percent of
The first row is the cost of constructing stacks of various heights. a one year shutdown
Other rows are sums of costs of shutdown and of constructing stacks.
0 M
10 N
20 K
30 M
60 H
percent of
year shutdown
cost of
shutdown
$0
$31,200
$80
500
$146,600
$291,400
OX
$0
$76
042
$107,242
$156
542
$222,642
$367,442
5%
$76,042
$152
084
$183,284
$232
584
$298,684
$443,484
10X
$152,084
$228
126
$259,326
$308
626
$374,726
$519,526
15%
$228,126
$304
169
$335,369
$384
669
$450,769
$595,569
20%
$304,169
$380
211
$411,411
$460
711
$526,811
$671,611
25%
$380,211
$456
253
$487,453
$536
753
$602,853
$747,653
30%
$456,253
$532
295
$563,495
$612
795
$678,895
$823,695
35%
$532,295
$608
337
$639,537
$688
837
$754,937
$899,737
40%
$608,337
$684
379
$715,579
$764
879
$830,979
$975,779
45%
$684,379
$760
422
$791,622
$840
922
$907,022
$1,051,822
50%
$760,422
$836
464
$867,664
$916
964
$983,064
$1,127,864
55%
$836,464
$912
506
$943,706
$993
006
$1,059,106
$1,203,906
60%
$912,506
$988
548
$1,019,748
$1,069
048
$1,135,148
$1,279,948
65%
$988,548
$1,064
590
$1,095,790
$1,145
090
$1,211,190
$1,355,990
70%
$1,064,590
$1,140
632
$1,171,832
$1,221
132
$1,287,232
$1,432,032
75%
$1,140,632
$1,216
675
$1,247,875
$1,297
175
$1,363,275
$1,508,075
80%
$1,216,675
$1,292
717
$1,323,917
$1,373
217
$1,439,317
$1,584,117
85%
$1,292,717
$1,368
759
$1,399,959
$1,449
259
$1,515,359
$1,660,159
90%
$1,368,759
$1,444
801
$1,476,001
$1,525
301
$1,591,401
$1,736,201
95%
$1,444,801
$1,520
843
$1,552,043
$1,601
343
$1,667,443
$1,812,243
100%
$1,520,843
2-19
-------
FIGURE 2-1: PIGEON MINE, CONTROL COSTS
BY STACK HEIGHT, MIR < 3E-5
Cost of Meeting Standard (in 1000 $)
1000
800
600
400
200
20
30
40
50
70
0
10
60
Stack Height (in meters)
Series 1
-------
2.4.3 Benefits of Control Alternatives
Tables 2-9, 2-10, and 2-11 list the health benefits of alternatives one, two, and three relative to the
baseline and relative to each other. The benefits are in terms of reductions in the risk of fatal cancer
to the most exposed individual and the incidence of fatal cancer in the 80 km population. Alternative
one will reduce the highest MIR from 4.4E-3 to 9.9E-5, a reduction of 4.3E-3. Alternative two also
eliminates the highest M1R (4.4E-3) and leaves the same uncontrolled mine as the new contributor
to the highest MIR which is again 9.9E-5. Alternative three will reduce the highest MIR from 4.4E-
3 to 3.0E-5, a reduction of 4.4E-3. With regard to the 80 km population, alternative one will reduce
the incidence of fatal cancers from 7.8E-1 to 2.3E-1, a reduction of 5.5E-1. Alternative two will
reduce the incidence of fatal cancers from 7.8E-1 to 5.9E-2, a reduction of 7.2E-1 cases annually
relative to the baseline incidence and a reduction of 1.7E-1 relative to alternative one. For
alternative three the resulting incidence of fatal cancer will be 1.0E-2, an annual reduction of 7.7 E-
I relative to the baseline incidence and of 4.9E-2 relative to alternative two. The greatest reduction
in risk to the 80 km population at an individual mine will be experienced at Schwartzwalder Mine
for all three alternatives. Schwartzwalder's reduction in risk to the 80 km population under
alternative one will be 5.3E-1 deaths avoided annually. For alternative two the reduction is 6.7E-
1 and for alternative three it is 7.0E-1.
Six mines will have no reductions in MIR or risk to the 80 km population under alternatives one and
two because they already meet the 1E-4 level. Similarly under option three, three mines already meet
the 3E-5 level. Applying alternative three to two other mines will reduce their MIRs. but will have
no effect on the risk to the 80 km population. At these two mines, stack heights will be raised, but
emissions will not be reduced.
2.4.4 Costs of Control Alternatives
In this section the aggregated costs of alternatives one, two, and three are analyzed. The economic
effects of the timing of costs are evaluated using the net present value of the cost stream. Tables 2-
12, 2-13, and 2-14 show the net present value of the cost streams for controlling emissions and
ambient concentrations during the remaining life of each mine. This is calculated using net discount
rates of zero, one, five, and ten percent.
In calculating the net present value, it was assumed that lower annual production rates would prolong
the life of the mine. The costs for each year in which output restrictions are binding include the
difference between revenues from operating at full capacity and at restricted capacity. When
restrictions are binding, the revenues from those additional years of production are added to the end
2-21
-------
Table 2-9: Health Benefits Due to Alternative One
Initial Risk of Fatal Cancer ALTERNATIVE 1: MIR BELOW 3E-4
Couroitted Fatal
Annual Risk to
Maximum
Cancers Per Yr
Reduction
Population
Reduction in
mine
Individual Risk
<0-80 km)
MIR
in MIR
within 80 km Population Risk
La Sal
4.4E-Q3
3.06-03
Q.QE+00
4.4E-03
1.5E-04
2.96-03
Calliham
1.1E-03
4.0E-04
5.56-05
1.06-03
t.0E-04
3.0E-04
Derema-Snyder
1.7E-03
1.0E-03
8.5E-05
1.6E-03
1.5E-04
8.5E-04
Schwartiwalder
1.2E-03
7.0E-01
6.0E-05
1.1E-03
1.7E-01
5.3E-01
SnowbalI-Pandora
1.3E-03
4.0E-03
6.5E-05
1.2E-03
8.0E-04
3.2E-03
King Solomon
3.5E-04
5.0E-03
8.8E-05
2.6E-04
4.3E-03
7.5E-04
WiI son-SiIverbeli
3.4E-04
1.0E-03
8.5E-05
2.6E-04
8.5E-04
1.5E-04
Section 23
4.1E-04
5.0E-02
6.2E-05
3.SE-Q4
3.5E-02
1.5E-02
Sunday
3.3E-04
4.0E-03
9.9E-05
2.3E-04
3.6E-03
4.0E-04
Mt. Taylor
3.6E-05
3.0E-03
3.6E-Q5
0.0E+00
3.0E-03
0.0E+00
Nil
7.3E-05
2.0E-03
7.3E-05
0.0E+00
2.0E-03
0.0E+00
Pinenut
2.7E-06
2.QE-04
2.7E-06
0.0E+00
2.0E-04
0.0E+00
Sheep Mountain No. 1
6.5E-06
2.0E-04
6.5E-06
O.OE+O0
2.0E-04
0.0E+00
Pigeon
6.1E-05
2.0E-03
6.1E-05
O.OE+OO
2.0E-03
O.OE+00
Kanab North
2.4E-05
1.0E-03
2.4E-05
O.OE+OO
1.0E-03
0.0E+00
Totals:
7.SE-01
2.3E-01
5.5E-01
2-22
-------
robte 2-10:
Health Benefits Owe to Alternative Two
ALTERNATIVE 2: MIR BELOU 16-4
I"
Reduction
in MIR
Reduction in Population Risk
Annual Risk to
Relative to
Relative to
Population
Relative to
Relative to
mine
MIR
Base
Alt. 1
within 80 km
Base
Alt. 1
La Sal
O.OE+OO
4.4E-03
O.OE+OO
O.OE+OO
3.0E-03
1.SE-04
Cal I iham
5.5E-05
1.0E-03
O.OE+OO
2.0E-05
3.8E-04
8.0E-05
Deremo-Snyder
8.5E-05
1.6E-03
O.OE+OO
5.0E-05
9.5E-04
1.0E-04
Schwartzwalder
6.0E-05
1.1E-03
O.OE+OO
3.5E-02
6.76-01
1.4E-01
SnowbatI-Pandora
6.5E-05
1.2E-D3
O.OE+OO
2.0E-04
3.8E-03
6.0E-04
King Solomon
S.8E-05
2.6E-04
O.OE+OO
1.ZE-03
3.8E-03
3.0E-03
WiI son-Si IverbelI
8.5E-05
2.6E-04
O.OE+OO
2.5E-04
7.SE-04
6.0E-04
Section 23
6.2E-Q5
3.5E-04
O.OE+OO
1.2E-02
3.8E-02
2.3E-02
Sunday
9.9E-05
2.3E-04
O.OE+OO
1.2E-03
2.8E-03
2.4E-03
Mt. Taylor
3.6E-05
O.OE+OO
O.OE+OO
3.0E-03
O.OE+OO
O.OE+OO
Nil
7.3E-05
O.OE+OO
O.OE+OO
2.0E-03
O.OE+OO
O.OE+OO
Pi nenut
2.7E-06
O.OE+OO
O.OE+OO
2.0E-04
O.OE+OO
O.OE+OO
Sheep Mountain No. 1
6.5E-06
O.OE+OO
O.OE+OO
2.0E-04
O.OE+OO
O.OE+OO
P i georv
6.IE-OS
O.OE+OO
o.oe+oo
2.0E-03
O.OE+OO
O.OE+OO
Kanab North
2.4E-05
0.0E+00
O.OE+OO
1.0E-03
O.OE+OO
O.OE+OO
Totals:
5.9E-02
7.2E-01
1.7E-01
2-23
-------
Table 2-11:
Health Benefits Due to Alternative Three
ALTERNATIVE 3: MIR BELOW 3E-5
'
Reduction
in MIR
Reduction in Population Risk
Annual Risk to
Relative to
Relative to
Population
Relative to
Relative to
mine
MIR
Base
Alt. 2
within 80 km
Base
Alt. 2
la Sal
O.QE+QO
4.4E-03
O.OE+OO
O.OE+OO
3.0E-03
O.OE+OO
Cal1 inam
0.OE+OO
1.1E-03
5.5E-Q5
O.OE+OO
4.0E-O4
2.0E-0S
Deremo-Snyder
O.OE+OO
1.7E-03
8.5E-05
O.OE+OO
1.0E-03
5.0E-05
Schwartzwalder
O.OE+OO
1.2E-03
6.0E-05
0.0E+00
7.0E-01
3.5E-02
Snowball-Pandora
O.OE+OO
1.3E-03
6.56-05
0.0E+00
4.0E-03
2.0E-04
King Solomon
1.8E-05
3.3E-04
7.0E-05
2.5E-04
4.86-03
1.0E-03
WiI son-SiIverbetI
1.7E-05
3.2E-04
6.8E-05
5.0E-05
9.5E-04
2.0E-04
Section 23
2.1E-05
3.9E-04
4.1E-05
2.5E-03
4.8E-02
1.0E-02
Sunday
1.7E-05
3.1E-04
8.2E-05
2.0E-04
3.8E-03
1.0E-03
Ht. Taylor
2.7E-05
9.0E-06
9.0E-06
3.0E-03
O.OE+OO
O.OE+OO
Nil
2.9E-05
4.4E-05
4.4E-05
B.0E-04
1.2E-03
1.2E-03
Pinenut
2.7E-06
0.0E+00
O.OE+OO
2.0E-04
O.OE+OO
O.OE+OO
Sheep Mountain No. 1
6.5E-Q6
O.OE+OO
O.OE+OO
2.0E-04
O.OE+OO
O.OE+OO
Pigeon
3.0E-05
3.1E-05
3.1E-05
2.0E-03
O.OE+OO
O.OE+OO
Kanab North
2.4E-05
O.OE+OO
O.OE+OO
1.0E-03
O.OE+OO
O.OE+OO
Totals:
1.0E-02
7.7E-01
4.9E-02
2-24
-------
Table 2-12: Costs of Alternative One
Uranium Ore Price at
Mine:
$110.23 per MT
Expected Rate of Return:
2%
Ore
NPV of
Alternative over life of i
mtn«
Expected
Production
Annual
at a discount
rate of
Stack
Emission
Li fe
Rate
Opportune ty
Stack -
Mine ID
Height
Reduction
(in years)
(MT/day)
Cost
Cost
0%
1%
5%
10:
La Sal
0
95%
7
160
$122,311
0
$856,178
$831,163
$743,125
$655,008
Cat I iharn
0
75%
(a)
so
(a)
0
$0
$0
$0
$0
Deremo-Snyder
0
85%
7
280
$191,514
0
$1,340,595
$1,301,426 $1
1,163,578
$1,025,605
Schwartzwalder
0
75%
startcfoy
0
$0
0
$0
$0
$0
$0
Snowbal t -Pandora
0
80%
7
54
$34,762
0
$243,335
$236,225
$211,204
$186,160
Kins Solomon
0
15%
7
350
$42,246
0
$295,720
$287,079
$256,672
$226,236
Mi Ison-SiIverbelI
0
15%
7
90
$10,863
0
$76,042
$71,820
$66,001
$58,175
Section 23
0
30%
1.25
68
$16,415
0
$20,519
$20,479
$20,324
$20,146
Sunday
0
10%
7
200
$16,094
0
$112,655
$109,364
$97,780
$86,18$
Mt, Taylor
20
0%
20
544
$0
0
$0
#0
$0
SO
Nil
0
0%
7
50
$0
0
$0
$0
$0
$0
Pinenut
0
0%
3
315
$0
0
$0
$0
$0
SO
Sheep Mountain no. 1
0
0%
5
220
*0
0
$0
$0
$0
m
Pigeon
0
0%
6
315
$0
0
$0
$0
$0
w
Kanab North
0
0%
6
315
$0
0
$0
$0
$0
so
(a) no information available regarding production activity at Calliham.
-------
Table 2-13: Costs of Alternative Two
Uranium Ore Price at
Mine:
$110.23 per MT
Expected Rate of Return:
2%
Ore
NPV of
Alternative i
aver tife of mine
Expected
Production
Annual
at a discount rate of
Stack
Emission
Life
Rate
Opportunity
Stack ¦
Mine 10
Height
Reduction
-------
Table 2-14:
Costs of Alternative Three
Uranium Ore Price at
Mine:
$110.23 per MT
Expected Rate of Return:
2%
Ore
NPV of
Alternative i
over life of mine
Expected
Production
ftrtnual
at a discount rate of
Stack
Emission
Li fe
Rate
Opportunity
Stack ¦
Mine ID
Height
Reduction
(in years}
-------
of the time stream. The mine with the highest cost is Derenio-Snyder Mine, under alternatives one
and two, and King Solomon Mine under alternative three.
2.5 Industry Cost and Economic Impact Analysis
2.5.1 Introduction
In this section the effects of the alternatives analyzed on economic entities are considered. This
includes assessing the relative impact of regulation on production costs, identifying which sectors of
the economy might experience adverse (or beneficial) economic effects, and the potential of the
regulation to affect small economic entities, such as small firms or small counties.
2.5.2 Production Cost Impacts
For purposes of illustration, these costs can be compared with the assumed return on uranium mining
of 2 percent, based on the experience of the last decade. Also, the trend towards closing all mines
indicates that profits may well be insufficient to sustain operations in the industry and any additional
costs may speed the demise of the mines.
2.5.3 Economic Impact Analysis
Although the cost of regulating uranium mines could result in mine closures, the effects of these
closures would be isolated to a small group of people -- the stockholders of the corporations who
own the mines, the 230 miners considered in Table 2-15 who currently work in six of the mines, and
the miners in the other mines for which no data was available. The employment and community
situation at the other mines, though undocumented, is likely to be similar to that for the mines
represented in Table 2-15. The effects of mine closure would not spread to the larger economy
because 1) in the depressed market for uranium there are other producers of ore -- U.S. surface
mines, by-product producers, and foreign mines -- who could continue to meet the current price and
to respond competitively in case of increased demand and 2) the miners live in different counties and
constitute a small proportion of workers in each.
As discussed in section 2.2, most underground uranium mines are subsidiaries of large corporations.
Most of the direct costs of compliance will be borne by stockholders or owners. Because operators
of underground uranium mines currently have little or no monopoly power they will not be able to
pass these costs on to the electric power industry.
Table 2-16 shows the number of miners at each of the six mines along with the total population in
the respective county. It also shows the number of mining establishments in the county and contrasts
2-28
-------
TMIE 2-15: Number of Miners and Shifts Per Say by Mine
For the Six Mines Where Information Is Available
Mine
Shifts/Day
Personnel
Schwartzualder
2
31
Section 23
1
27
Mt. Taylor
2
5?
Pigeon
3
38
Kanab North
3
42
Pinenut
3
35
TOTAL 230
TABLE 2-16: Number of Miners and Mining Operations by County
For the Six Mines Where Information Is Available
Number
Total
Mining
County
of Mine
Establish-
establish-
Mine
County Population
Workers
ments
ments
Schwartzwalder
Jefferson
427400
31
10387
7
Section 23
Grant
na
27
580
10
Cibola
23000
na
na
m
Mt. Taylor
McKinley
65800
57
921
4
Pigeon
Coconino
S6100
38
2101
4
Kanab North
Coconino
86100
42
2101
4
Pinenut
Mohave
76600
35
1827
d
d = withheld to prevent disclosure of private information
na = not available
Sources: County Business Patterns, 1986
Bureau of Census, Personal Communication
2-29
-------
that with the total number of workplaces. Because the number of miners involved is such a small
proportion of the overall population, no effect on unemployment rates is expected. The only ripple
effect would be the effect of mine closure on uranium mill employees who are also very small in
number.
2.5.4 Regulatory Flexibility Analysis
As shown in the previous sections, the major effects of the regulations will fall on relatively large
entities, the corporations that own the mines. Effects on unemployment rates in counties where the
mines are located will be unmeasurable, since the miners represent well under one percent of the
county populations.
2-30
-------
REFERENCES
AR84 The annual reports of all uranium-producing companies were examined for the years
1976-1986. The reference, AR, is followed by a date. The specific company
reference is to be found in the text.
AR85 The annual reports of all uranium-producing companies were examined for the years
1976-1986. The reference, AR, is followed by a date. The specific company
reference is to be found in the text.
AR86 The annual reports of all uranium-producing companies were examined for the years
1976-1986. The reference, AR, is followed by a date. The specific company
reference is to be found in the text,
DOE87a Department of Energy, Domestic Uranium Mining and Milling Industry; 1986
Viability Assessment, DOE/EIA-0477(86), November 23, 1987.
DOE87b Department of Energy, Uranium Industry Annual 1986, DOE/EIA-0478(86),
October 9, 1987.
EPA 89 Risk Assessment, Vol.2.
JFA85a Jack Faucett Associates, Economic Profile of the Uranium Mining Industry. Prepared
for U.S. Environmental Protection Agency, January 1985.
2-81
-------
CHAPTER 3
INACTIVE URANIUM MILL TAILINGS
-------
3. INACTIVE MILL TAILINGS
3.1 Introduction and Summary
The inactive uranium mill tailings source category is comprised of tailings and other wastes at 24
former processing sites designated as Title 1 sites under the Uranium Mill Tailings Radiation Control
Act (UMTRCA) of 1978. Radon-222, the decay product of the residual radium-226 in the tailings,
is emitted to the air from the tailings. Radon emissions from licensed uranium mill tailings sites are
addressed in Chapter 4.
The purpose of this chapter is to examine the costs, benefits, and economic impacts of reducing the
maximum allowable levels of radon-222 emissions after closure from the 20 pCi/m2/sec limit
established under UMTRCA. Options that are evaluated include reducing radon-222 emissions to
a maximum of 6 pCi/m2/sec, and to a maximum of 2 pCi m2/sec.
The remainder of this introduction provides a brief summary of the rulemaking history and the
current regulations. A profile of the inactive uranium milling industry is given in Section 3.2.
Section 3.3 addresses current emissions, risk levels and feasible control methods. Section 3.4 provides
estimated benefits and costs of the proposed options. The economic impacts are considered in
Section 3.5.
3.1.1 Rulemaking History and Current Regulations
In enacting the UMTRCA (Public Law 95-604, 42 USC 7901), Congress found that:
o "Uranium mill tailings located at active and inactive mill operations may pose a
potential and significant radiation health hazard to the public, and that..."
o "Every reasonable effort should be made to provide for the stabilization, disposal, and
control in a safe and environmentally sound manner of such tailings in order to
prevent or minimize radon diffusion into the environment and to prevent or minimize
other environmental hazards..."
3-1
-------
To these ends, the Act required the EPA to set generally applicable standards to protect the public
against both radiological and nonradiological hazards posed by residual radioactive materials at
uranium mill tailings sites. Residual radioactive material means (1) tailings waste resulting from the
valuable constituents, and (2) other wastes, including unprocessed ores or low-grade materials at sites
related to uranium ore processing. The term "tailings" is used to refer to all of these wastes.
UMTRCA divided uranium mill tailings sites into two groups: Title I covering inactive and
abandoned sites, and Title II covering those sites for which licenses had been issued by the Nuclear
Regulatory Commission (NRC), by its predecessor or by an Agreement State. Twenty-four sites
have been designated Title I sites under UMTRCA. Under the Act, the EPA developed generally
applicable standards governing the remedial activities of the Secretary of Energy or his designee
under Section 275a of the Atomic Energy Act of 1954 for those sites identified under Title I. The
Department of Energy (DOE) is responsible for the cleanup and long-term stabilization of the tailings
at these sites, consistent with the generally applicable standards developed by the EPA.
Under UMTRCA, the EPA was required to promulgate standards before the DOE could begin
cleanup of the Title I sites. These standards required, to the maximum extent practicable, that these
operations be consistent with the requirements of the Solid Waste Disposal Act (SWDA), as amended.
The SWDA includes the provisions of the Resource Conservation and Recovery Act (RCRA).
Because some buildings had been found to be contaminated with tailings resulting in high radiation
levels, interim standards for buildings were published in the Federal Register on April 22, 1980. This
allowed the DOE to proceed with the cleanup of off-site tailings contamination without waiting for
the formal promulgation of a regulation through the EPA rulemaking process. During this time,
proposed standards for the cleanup of the inactive mill tailings were published for comment.
The proposed cleanup standards were followed by proposed disposal standards, published in the
Federal Register on January 9, 1981. The disposal standards apply to the tailings at the 24 designated
sites and are designed to place them in a condition that would remain safe for a long time. The final
UMTRCA standards for the disposal and cleanup of inactive uranium mill tailings were issued on
January 5, 1983.
The American Mining Congress and others immediately petitioned the Tenth Circuit Court of
Appeals for a review of the standards. On September 3, 1985, the Tenth Circuit Court upheld the
inactive mill tailings standards except for the ground-water protection portions, which were
3-2
-------
remanded to EPA for revision. The EPA is currently developing new standards under this rule. The
disposal standard that applies to the 24 Title I sites (40 CFR 192, Subpart A) requires long-term
stabilization of the tailings and establishes a design standard limiting the average radon-222 emission
rate to 20 pCi/m2/sec or less.
3.2 Inactive Industry Profile
3.2.1 Current Status of Inactive Mills
A typical site contains the mill buildings where ore was processed to remove the uranium, ore storage
areas, and a tailings pile covering approximately 50 acres. The tailings pile is usually made by
depositing slurried sand wastes on flat ground to form a pond into which there is further deposition
of slurried sand, finer grained wastes ("slimes"), and process water. The water has since evaporated
or seeped into the ground, leaving a large pile of mostly sand-like material. Some inactive sites also
contain dried up raffinate ponds, special ponds where contaminated process water was stored until
it evaporated. Mil! buildings, ore storage areas, and dried up raffinate ponds are usually heavily
contaminated with radioactive material. The amount of tailings produced by a mill is about equal
in both weight and volume to the ore processed, since the recovered uranium is only a small part of
the ore.
3.2.2 Use of Inacthe Mill Sites
Housing and other structures that remain from milling operations have been frequently put to use.
Housing at Tuba City, Natui ita, Slick Rock, Shiprock, and Mexican Hat is occupied. Buildings on
mill sites at Gunnison, Naturita, Shiprock, Green River, and Mexican Hat are being used for
warehousing, schools, and for other purposes. Further, buildings are still used for company activities
at several sites. A sewage disposal site is operating at the former site in Salt Lake City. The pressure
for use of sites in urban areas is likely to increase with time as a result of population growth. The
status and current reclamation schedule for inactive uranium mill sites are presented in Table 3-1.
3-3
-------
Table 3-1. Status and Planned Remedial Action at Inactive Uranium Hill Sites (a).
Site
Quant i ty
Proposed
Schedule(b)
of Tailings
Action
Start
F i ni sh
(1,000,000 tons)
Monument Valley, AZ
1.2
Removal to Mexican Hat Site
FY90
FY91
Tuba City, AZ
0.8
Stabilization in place
Utf(c)
FY90
Durango, CO
1.6
Removal to Bodo Canyon Site
UU
mo
Grand Junction, CO
1.9
Removal to Cheney Site
UU
FY93
Gunnison, CO
0.5
Removal to Landfill Site
FY90
FY92
Maybe 11, CO
2.6
Stabilization in place
FY91
FY92
Naturita, CO
0.6
Removal to Dry Flats Site
FY91
FY92
New Rifle, CO
2.7
Removal to Estes Gulch Site
UU
FY92
Old Rifle, CO
0.4
Removal to Estes Gulch Site
UU
FY92
Slick Rock (NC)Cd),
CO
0.04
Removal to Slick Rock (UC)
-
DONE
Slick Rock CUC)(e),
CO
0.35
Stabilization in place
-
DONE
Lowman, ID
0.09
Stabilization in place
FY92
FY92
Ambrosia Lake, nm
2.6
Stabilization in place
UU
FY90
Shiprock, NM
1.5
Stabilization in place
-
DONE
Bel field, ND
...
Removal to Bowman Site
FY92
FY93
Bowman, ND
...
Stabilization in place
FY92
FY93
Lakeview, OR
0.13
Removal
-
DONE
Canonsburg, PA
0.4
Stabilization in place
-
DONE
Falls City, TX
2.5
Stabilization in place
FY90
FY92
Green River, UT
0.12
Stabilization in place
UU
DONE
Mexican Hat, UT
2.2
Stabilization in place
UU
FY91
Salt lake City, UT
1.7
Removal to S. Clive Site
-
DONE
Converse County, WY
0.19
Stabilization in place
yy
FY89
Riverton, WY
0.9
Removal to UMETCO's Gas
Hills Licensed Site
uw
FY91
(a) DOE88
(b) The start and finish dates refer to construction activities to stabilize and cover
the tailings. The finish dates do not include development and implementation of
the Surveillance and Monitoring Program or Certification that the remedial action is
complete.
(c) UU = underway, i.e., remedial actions to stabilize the tailings have been
initiated.
Cd) North Continent pile
(e) Union Carbide pile"
3-4
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3.3 Current Emissions. Risks, and Control Methods1
All but one of the 24 processing sites designated under Title I of the UMTRCA are situated in the
generally semi-arid to arid western United States, The site locations vary from isolated, sparsely
populated, rural settings to populated, urban communities.
The tailings contain residual radioactive materials, including traces of unrecovered uranium and most
of the daughter products, as well as various heavy metals and other elements, often at levels
exceeding established standards. The DOE's Uranium Mill Tailings Remedial Action Program
(UMTRAP) calls for the removal of tailings from sites in highly populated areas or where the long-
term stabilization is threatened by flooding or could result in the contamination of groundwater.
Under Public Law 95-604 the DOE is to complete disposal and stabilization by the end of fiscal year
(FY) 1994.
To date, disposal at seven sites has been completed and tailings at all sites are scheduled to be covered
by February 1993 (DOE88). As can be seen in Table 3-1, once the DOE planned actions are
completed, there will be a total of 19 disposal sites. However, since the remedial action at the
Converse County site calls for disposal under 40 feet of cover, there will be 18 sites where there is
a potential for radon-222 emissions that could cause risks to public health. ,/({Lai I
Li-
Previous analyses have shown that the only effective means of controlling radon emissions from the
tailings is to bury the tailings with an earthen cover thick enough to attenuate the radon flux from
the tailings. The UMTRCA standards require that the cover be designed so that the average radon
flux does not exceed 20 pCi/m2/sec. The design flux from the covers approved by the DOE range
from the UMTRCA limit of 20 pCi/m2/sec down to 0.5 pCi/m2/sec.
At sites where remedial action is pending, no controls are currently in place to reduce radon
emissions. Thin interim earthen covers have been used at some sites. These are intended primarily
to control wind erosion of the tailings and may reduce the amount of radon released to the air. At
sites where long-term stabilization under UMTRCA has been completed, thick earthen covers have
been placed on the tailings. As discussed in detail in Volume 2 of this Environmental Impact
Statement (Appendix B) earthen covers reduce the amount of radon released to the air by retaining
1The source for the following section on emissions, risks and control methods is Chapter 8,
Volume 2 of the Environmental Impact Statement (EPA89).
3-5
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the radon under the cover long enough for it to decay. It is assumed that these covers reduce the
radon flux to the flux for which they were designed,
3.3.1 Current Emissions and Estimated Risk Levels
The radon releases from the tailings at the IB inactive sites that will remain once UMTRCA disposal
is completed are assessed on a site-by-site basis. The following sections discuss how the radon release
rates are developed and the sources of the meteorological and demographic data used in the
assessment.
3-3.1.1 Development of the Radon Source Terms
Estimates for the radon source terms for the post-UMTRCA disposal sites are based on the DOE's
estimated radon fluxes through the approved cover designs and the areas of the disposal sites. The
DOE's design fluxes and the areas of the disposal sites are those reported in DOE88. For the
alternative fluxes of 6 and 2 pCi/m2/sec, the source terms are calculated using the lower of the design
flux or the appropriate flux limit. The areas of the final disposal sites, the cover design flux rate,
and the radon source terms calculated for each pile are presented in Table 3-2.
3.3.1.2 Demographic and Meteorological Data
To assess the exposures and risks that result from the release of radon-222, site-specific
meteorological and demographic data have been used. Demographic data for the nearby (0-5 km)
individuals are developed for each site by surveys conducted during site visits (PNL84). These
demographic data have been updated by the DOE and SC&A for certain piles (see Appendix A of
Vol II for details). The results of that survey are summarized in Table 3-3. Data for the populations
3-6
-------
Table 3-2, Summary of Radon-222 Emissions from Inactive Uranium Hilt Tailings Disposal Sites. (a)
State/Site
Area of
Cover
Radon-222 Releases
(Ci/y)
S< te
Design
Design
6 pCi/m2/s
2 pCi/m2/s
(acres)
Flux
Flux
Limit
Limit
(pCi/m2/s)
kri zona
Tuba City
22
9.3
2.6E+Q1
1.7E+01
5.6E+00
Colorado
Durango -Bodo Canyon
40
20.0
1.0E+Q2
3.1E+01
1.0E+01
Grand Junction - Cheney Site
62
6.5
5.1E+01
4.BE+01
1.6E+01
Gunnison - landfill Site
38
1.9
9.2E+00
9.2E+00
9.2E+00
Maybe11
80
7.1
7.3E+01
6.1E+01
2.0E+01
Naturita - Mill Site
23
5(b)
1.5E+01
1.SE+01
5.9E+00
New/Old Rifle - Estes Gulch
71
20.0
1.8E+02
5.4E+01
1.8E+01
Slick Rock - Combined
6
5.8
4.4E+00
4.4E+00
1.5E+00
Idaho
lowman
5
5.7
3.6E+00
3.6E+00
1.3E+00
Hen Mexico
Ambrosia lake
105
16.7
2.2E+02
8.0E+O1
2.7E+01
Shiprock
72
20.0
1.8E+02
5.5E+01
1.8E+01
North Dakota
Bowman/Bel field
12
3.9
6.0E+00
6.0E+00
3.1E+00
Oregon
Lakeview
30
7.5
2.9E+01
2.3E+01
7.7E+00
Pennsylvania
Canonsburg
18
7.0
1.6E+01
1.4E+01
4.6E+00
Texas
Fat Is Ci ty
146
13.2
2.56+02
1.1E+02
3.7E+01
Utah
Green River
9
0.5
5.7E-01
5.7E-01
5.7E-01
Mexican Hat
68
12.0
1.06+02
5.2E+01
1.7E+01
Salt lake City - S. Clive
50
20.0
1.3E+02
3.9E+01
1.3E+01
Totals
857
1.3E+03
5.9E+02
2.2E+02
(a) emissions are calculated based on the area of the site and the lower of the given flux
limit and the DOE approved design flux.
(b) Final cover design not available, design flux of 5 pCi/m2/sec assumed due to the fact
that only residuaI contamination exists at this site.
3-7
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between 5-80 km are generated using the computer code SECPOP. Meteorological data are obtained
from the nearest station with suitable joint frequency arrays. Details of the inputs that were provided
to the AJRDOS/DARTAB/RADRISK codes are presented in Appendix A of Volume 2 of the
Environmental Impact Statement,
3.3.1.3 Exposures and Risks to Nearby Individuals
The A1RDOS-EPA and DARTAB model codes are used to estimate the increased chance of lung
cancer for individuals living near a tailings impoundment and receiving the maximum exposure.
Estimates for the exposure and risk to nearby individuals once UMTRCA disposal is completed, as
well as under alternative flux rates of 6 and 2 pCi/m2/sec are shown in Table 3-4. The lifetime fatal
cancer risks for individuals residing near inactive disposal sites range from 4E-7 to 2E-4. The
maximum lifetime fatal cancer risk of about 2E-4 is estimated at the Shiprock site in New Mexico
at a distance of 750 meters from the impoundment center.
3.3.1.4 Exposures and Risks to the Regional Population
Collective population'risks, in deaths per year, for the region around the mill site are calculated from
the annual exposure in person-WLM (working level months) for the population in the assessment
area. Collective exposure calculations expressed in person-WLM are performed for each mill by
multiplying the estimated concentration in each annular sector by the population in that sector. The
estimated regional fatal cancers per year in the regional populations are presented for the'DOE
approved design flux and for alternative fluxes of 6 and 2 pCi/m2/sec in Table 3-5.
3.3.1.5 Exposures and Risks Under Alternative Standards
Once the tailings piles are stabilized and disposed of at the DOE cover design flux, the radon-222
emission rates will all be at or below the UMTRCA design limit of 20 pCi/m2/sec, As mentioned
above, alternative flux limits of 6 and 2 pCi/m2/sec are also evaluated. The exposures and risks
under each of the alternative standards are presented in Tables 3-4 and 3-5, respectively. These
estimates show that the maximum lifetime fatal cancer risk could be reduced from 2E-4 at the DOE
design flux to 7E-5 at a limit of 6 pCi/m2/sec, and to 2E-5 at a limit of 2 pCi/m2/sec. The number
of deaths per year that will occur in the regional population would be reduced by about one-half
3-8
-------
Table 3-3. Estimated Number of Persons Living Uithin 5 km of the Centre id of Tailings
Disposal Sites for Inactive Hills(a).
Distance (kilometers)
State/Site 0-0.5 0.5-1.0 1.0-2.0 2.0-3.0 3.0-4.0 4.0-5.0 Total
Arizona
Tuba City 0
Colorado
Durango 0
Grand Junction 0
Gunnison 0
Maybe11 0
Naturita 0
New/Old Rifle 0
Slick Rock 3
Idaho
Lowman 9
New Mexico
Ambrosia Lake 0
Shiprock 0
North Dakota
Bowman/Belfield 0
Oregon
Lakeview 0
Pennsylvania
Canonsburg 950
Texas
Fat Is City 0
Utah
Green River 0
Mexican Hat 0
Salt Lake City 0
Total 962
18 12 15
0 2 0
0 0 0
0 0 8
0 0 0
0 65 20
0 0 16
16 0 3
76 87 0
0 0 0
155 1,904 1,034
3 9 3
16 543 1,704
2,960 7,988 5,126
3 18 0
14 257 810
0 279 56
0 0 0
3,261 11,164 8,795
0 19 64
0
0
2
26
31
57
11
22
41
0
0
0
106
902
1,093
0
49
65
0
0
22
16
30
218
0
0
0
,016
839
4,948
6
12
33
457
464
4,184
830
281
22,135
15
9
45
397
20
1,498
0
0
335
0
0
0
5,880 4,678 34,740
(a) PML84, updated per SC&A site visits and DOE data {see Vol. 2, Appendix A).
3-9
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Table 3-4. Estimated Exposures and Risks to Nearby Populations Assuming Alternative Flux Rates.
DOE Design Flux 6 pCi/&i2/s Limit 2 pCi/«2/s Limit
Maximum Maximum Maximun
Radon
Maximum
Maximum Lifetime
Radon
Maximum
Maximum Lifetime
Radon
Maximum
Kaxiaua Lifetiae
State/Site
Distance (a)
Concentration Exposure
Fatal Cancer Risk
Concentration Exposure
Fatal Cancer Risk
Concentration Exposure
Fatal Cancer Risk
(meters)
(pCi/l)
(WU
To Individual
(pCi/l)
(UL>
To Individual
(pCi/l)
C«L)
To Individual
Arizona
Tuba City
1,500
2.0E-03
6.7E-06
9.0E-06
1.3E-03
4.4E-06
6.0E-06
4.4E-04
1.4E-06
2.0E-06
Colorado
Durango
1,500
1.1E-02
3.7E-05
5.0E-0S
3.31-03
1.1E-05
2.0E-D5
1.1E-03
3.7E-06
S.QE-06
Grand Junction
4,500
1.3E-03
5.7E-06
8.0E-06
1.3E-03
5.4E-06
7.0E-06
4.2E-Q2
1.8E-06
2.0E-06
Gunnison
4,500
1.6E-04
7.0E+07
1.0E-06
1.6E-04
7.0E-07
1.0E-06
1.6E-04
7.0E-07
1.0E-06
MaybeII
15,000
8.9E-04
5.8E-06
8.0E-06
7.4E-04
4.8E-06
7.0E-06
2.4E-04
1.6E-06
2.0E-06
Naturite
250
1.3E-02
3.5E-35
5.0E-05
1.3E-02
3.5E-05
5.0E-05
5.0E-03
1.4E-05
2.0E-05
New/Old Rifle
2,500
2.7E-03
9.86-06
1.0E-05
8.0E-04
2.9E-06
4.0E-06
2.7E-04
9.8E-07
1.0E-06
Slick Rock
250
3.6E-03
1.0E+05
1.0E-05
3.6E-03
1.0E-05
1.0E-05
1.2E-03
3.4E-06
5,06-06
Idaho
toman
250
4.4E-03
1.2E-05
2.0E-05
4.4E-03
1.2E-05
2.0E-05
1.9E-03
5.4E-Q6
6.0E-06
New Mexico
Ambrosia Lake
7,500
3.7E-04
1.9E-06
3.QE-06
1.46-04
6.9E-07
9.0E-07
4.6E-05
2.3E-07
3.0E-07
Shiproek
750
5.2E-02
1.6E+04
2.0E-04
1.6E-Q2
4.8E-05
7.0E-05
5.2E-03
1.6E-05
2.0E-05
North Dakota
Bowman/Belfield
750
7.5E-04
2.2E-06
3.0E-06
7.56-04
2.2E-06
3.0E-06
3.6E-04
1.2E-06
2.0E-06
Oregon
Lakeview
2,500
1.9E-03
6.8E-06
9.0E-06
1.5E-03
5.4E-Q6
7.0E-D6
4.9E-04
1.8E-06
2.0E-06
Pennsylvania
Canonsburg
250
2.0E-Q2
5.4E-05
8.0E-0S
1.7E-02
4.7E-05
7.0E-05
5.6E-03
1.6E-05
2,06-05
Texas
Falls City
lit-ah
1,500
1.4E-02
4.5E-05
6.0E-05
6.0E-03
2.0E-05
3.QE-05
2.0E-03
6.6E-06
9.0E-06
UvQII
Green River
750
2.1E-04
6.2E-07
9.0E-07
2.1E-Q4
6.2E-07
9.0E-07
2.1E-04
6.2E-07
9.0E-07
Mexican Hat
750
1.4E-02
4.1E-05
6.0E-0S
5.6E-03
1.9E-05
3.0E-05
1.8E-03
6.16-06
8.0E-06
Salt Lake City
15,000
4.2E-05
2.7E-Q7
4.0E-07
1.3E-05
8.2E-08
1.01-07
4.2E-06
2.7E-08
4.01*08
(a> Distance from center of a homogenous circular equivalent impoundment to the point where the exposures and risks were estimated.
-------
Table 3-5. Estimated Fatal Cancers per Year in the Regional (0-80 km) Populations Around
Inactive Tailings Disposal Sites Assuming Alternative Radon Flux Rates (a).
Design flux
6 pCi/m2/s
2 pCi/m2/s
State/Site
Fatal Cancers
per Year
Fatal Cancers
per Year
Fatal Cancers
per Year
Arizona
Tuba City
Colorado
Durango
Grand Junction
Gunnison
Maybe 11
Naturita
New/Old Rifle
Slick Rock
Idaho
lowraan
New Mexico
Ambrosia Lake
Shiprock
North Dakota
Bowman/Self ield
Oregon
Lakeview
Pennsylvania
Canonsburg
Texas
Falls City
Utah
Green River
Mexican Hat
Salt lake City
Totals
1.3E-04
6.7E-04
9.9E-04
7.5E-05
1.0E-04
3.5E-05
5.3E-04
6.4E-06
9.7E-06
5.3E-04
3.0E-03
4.0E-06
1.3E-04
4.7E-03
7.1E-03
3.3E-06
3.4E-04
4.9E-0S
1.8E-02
8.8E-05
2.1E-04
9.3E-04
7.5E-05
8.5E-05
3.5E-05
1.6E-04
6.4E-06
9.7E-06
1.9E-04
9.2E-04
4.0E-06
1.1E-04
4.1E-03
3.1E-03
3.3E-06
1.7E-04
1.5E-05
1.06-02
2.9E-05
6.7E-05
3.1E-04
7.5E-05
2.8E-05
1.4E-0S
S.3E-0S
2.2E-06
3.6E-06
6.5E-05
3.0E-04
2.1E-06
3.6E-05
1.4E-03
1.1E-03
3.3E-06
5.7E-0S
4.9E-06
3.5E-03
(a) Fatal cancers per year are calculated based on the lower of the given flux limit
and the DOE design flux.
3-11
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(from 2E-2 to I E-2) at a limit of 6 pCi/m2/sec. At a limit of 2 pCi/m2/sec, the deaths per year
would be reduced by about nine-tenths (from 2E-2 to 3E-3).
3.3.1.6 Distribution of the Fatal Cancer Risk
The frequency distribution of the estimated lifetime fatal cancer risk for all inactive uranium mill
tailings piles for each alternative are presented in Table 3-6. This distribution is developed by
simply summing the frequency distributions projected for each of the 18 facilities. The distribution
does not account for overlap in the populations exposed to radon-222 released from more than a
single mill. Given the remote locations of these facilities and the relatively large distances between
mills, this simplification does not significantly understate the lifetime fatal cancer risk to any
individual.
3.3.2 Control Technologies
Previous studies have examined the feasibility, effectiveness, and cost associated with various options
for controlling releases of radioactive materials from uranium mill tailings (NRC80, EPA82, EPA83,
EPA86). These studies have concluded that long-term stabilization and control will be required to
protect the public from the hazards associated with these tailings. The standards for long-term
disposal, established for these Title 1 sites under UMTRCA, provide for controls to prevent misuse
of the tailings, protect water resources, and limit releases of radon-222 to the air. The UMTRCA
standard established a design standard to limit long-term radon releases to an average flux no greater
than 20 pCi/m2/sec.
Both active and passive controls are available to reduce radon-222 emissions from tailings. Active
controls require that some institution, usually a government agency, take the responsibility for
continuing oversight of the piles, and for making repairs to the control system when needed. Fences,
warning signs, periodic inspections and repair, and restrictions on land use are measures that may be
used by the oversight agency. Passive controls are measures of sufficient permanence to require little
or no active intervention. Passive controls include measures such as thick earth or rock covers,
barriers (dikes) to protect against floods, burial below grade, and moving piles out of flood prone
areas or away from population centers. Of the two methods, active or institutional controls are not
preferred for long-term stabilization of radon-222 emissions, since institutional performance of
oversight duties over a substantial period of time may not be reliable.
3-12
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Table 3-6, Estimated Distribution of Fatai Cancer Risk to the Regional (0-80 km) Populations
from inactive Uranium Hilt Tailings Disposal Sites Assuming Alternative Flux Rates.
DOE Design flux 6 pCt/m2/s 2 pCi/m2/s
Risk Interval
Number of
Persons
Deaths
Per Yr
Number of
Persons
Deaths
Per Yr
Number of
Persons
Deaths
Per Yr
IE-1 to 1E+0
0
0
0
0
0
0
1E-2 to 1E-1
0
0
0
0
0
0
1E-3 to 1E-2
0
0
0
0
0
0
1E-4 to 1E-3
130(a)
4.0E-04
0
0
0
0
1E-5 to 1E-4
4,500
2.0E-03
2,500
1E-3
1,100
2E-4
1E-6 to 1E-5
89,000
2.0E-03
28,000
1E-3
7,500
3E-4
< 1E-6
4,900,000
1.0E-02
5,000,000
8£-2
5,000,000
3E-3
Totals*
5,000,000
2E-2
5,000,000
1E-2
5,000,000
3E-3
(a) AlI individuals in this risk interval reside near the Sbiprock disposal site in New Mexico.
* Totals may not add due to independent rounding.
3-13
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Previous studies (see above) have identified a number of options to provide long-term control of
radon-222 emissions from the tailings. These include earthen or synthetic covers, extraction of
radium from the tailings, chemical fixation, and sintering. These long-term control options are
discussed in detail in Volume 2 of this Environmental Impact Statement (Appendix B).
In comparison to other control technologies earth covers have been shown to be cost-effective
(NRC80). Apart from cost considerations, there are other benefits that accrue by using earth covers
as a method to control radon-222 emissions. For example, synthetic covers, such as plastic sheets,
do not reduce gamma radiation. However, earth covers that are thick enough to reduce radon-222
emissions will reduce gamma radiation to insignificant levels. Further, chemical and physical stresses
over a substantial period of time destabilize synthetic covers, while earthen covers are stable over the
long run provided the erosion caused by rain and wind is contained with vegetation or rock covers,
and appropriate precautions are taken against natural catastrophes.
Earthen covers also reduce the contamination of groundwater that results from two alternative
control methods: storing radioactive materials in underground mines (underground mines are typically
located under the water table), or using the leaching process to extract radioactive and non-
radioactive contaminants from mill tailings. Moreover, although underground mine disposal is an
effective method to protect against degradation and intrusion by man, it nevertheless incurs a social
cost. For example, storing tailings in underground mines eliminates the future development of the
mines' residual resources.
Finally, earthen covers provide more effective long-term stabilization than either water or soil
cement covers. Soil cement covers are comparable to earthen covers in terms of cost-effectiveness,
but the long-term performance of these is as yet unknown. Water covers do not provide the long-
term stability required for the 1000-year time periods required. Moreover, earth covers are more
effective stabilizers in arid regions than are water spraying control technologies.
Covering the dried tailings with earth is an effective method for reducing radon-222 emissions and
is already in use at inactive tailings impoundments. The depth of soil required for a given amount
pf control varies with the type of earth and radon-222 exhalation rate.
Earth covers decrease radon-222 emissions by the retaining radon-222 released from the tailings long
enough to allow a significant portion to decay in the cover. A rapid decrease in radon-222 emissions
3-14
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is immediately achieved by applying almost any type of earth. High-moisture content earths provide
greater radon-222 emission reduction because of their smaller diffusion coefficient.
In practice, earthen cover designs must take into account uncertainties in the measured values of the
specific cover materials used, the tailings to be covered, and predicted long-term values of
equilibrium moisture content for the specific location. The uncertainty in predicting reductions in
radon-222 flux increases rapidly as the required radon-222 emission limit is lowered.
The cost of adding earth covers depends on the location of the tailings impoundment, its layout, the
availability of earth, the topography of the disposal site, its surroundings, and the hauling distance.
Another factor affecting costs of cover material is its ease of excavation, in general, the more
difficult the excavation, the more elaborate and expensive the equipment required and the higher the
cost. The availability of materials, such as gravel, dirt, and clay, also affects costs. If the necessary
materials are not available locally, they must be purchased and/or hauled, and costs could increase
significantly as a result.
3-4 Analysis of Benefits and Costs
This section presents the benefits and costs of reducing the allowable radon emissions after closure
from the maximum limit of 20 pCi/m2/sec established under UMTRCA. Options which are
evaluated include lowering radon emissions to a maximum of 6 pCi/m2/sec or a maximum of 2
pCi/m2/sec.
This analysis assumes that UMTRCA is in place and that all controls required under UMTRCA will
be met regardless of any provisions resulting from this reconsideration of the CAA standards.
Therefore, the beginning point of this analysis (i.e., the baseline) assumes that all controls required
by UMTRCA are met, specifically that radon emission levels will be limited to a maximum of 20
pCi/m2/sec and that measures will be undertaken to achieve the long-run stability required by the
UMTRCA rules.
Benefits are measured as reductions in the estimates of committed fatal cancers resulting from lower
allowable emissions. Results are presented in terms of both total benefits and average annual
benefits. For the calculation of total benefits a 100-year time period is assumed.
3-15
-------
All costs are measured in 1988 dollars and represent the cost of both the disposal and stabilization of
the failings, Cos! estimates are calculated assuming no remedial actions have taken place. The costs
of meeting the DOE design flux, the 6 pCi/m2/sec and the 2 pCi/m2/sec are then estimated. The cost
of the alternative standards are the incremental costs from the baseline (DOE design flux) to the 6
or 2 pCi/m2/sec alternative. Results are presented in net present value and annualized cost, and are
estimated using real interest rates of zero, one percent, five percent and ten percent. A 100-year
time period is used.
3.4.1 Benefits
It is assumed that reductions in the radon flux rate provided by increasing the depth of cover will
yield proportional reductions in committed cancers. The resulting estimates of committed cancers
per year on a pile-by-pile basis are presented above for the DOE cover design flux, 6 and 2
pCi/m2/sec options in Table 3-5.
Table 3-7 summarizes the estimates of risk and reduction of risk (committed cancers) for the various
regulatory options. The table presents these estimates for the 100-year period as well as annual
averages. Over the 100-year time frame, the 6 pCi/m2/sec option lowers regional risks by 0.8
committed cancers. The incremental benefit of lowering the allowable flux rate from 6 pCi/m2/sec
to 2 pCi/m2/sec is estimated as 0.65 committed cancers.
3.4.2 Costs
For reasons described in Section 3.3.2, the supplemental control selected for long-term radon-222
control at inactive tailings impoundments is the earthen cover control option. The thickness of cover
required to achieve a given radon flux is a function of the initial radon flux frorn the pile. Five
operations are required to place earthen covers on inactive tailings piles. These include: regrading
slopes, procurement and placing of the dirt cover, placing gravel on the pile tops, placing of rip-
rap on the pile sides, and reclamation of the borrow pits. The estimation of earth cover thicknesses
and the costs for the five operations are described in detail in Appendix B of Volume 2 of the
Environmental Impact Statement.
Three overhead cost factors were used to adjust the cost of earth cover described above. First, a
factor of i .07 was applied to reflect general industry overhead and costs, (for a discussion of cost
factors see Appendix B, Volume 2). Second, a project cost factor of 3.4, based upon UMTRAP
experience, was applied to reflect additional government costs for community participation,
3-16
-------
Tabie 3-7". Totai and Annualized Risk arid Reduction of Sisk (Conrnitied Cancers)
of Lowering the Alienable Flux limit to 6 and 2 pCi/m2/sec.
20 pdCi/m2/sec
Baseline
Risk
6 p€i/m2/sec
Option
2 pCi/m2/sec
Opt i on
Risk
Risk
Reduction from
20 pCi/m2/sec
Baseline
Risk
Risk Risk
Reduction from Reduction from
20 pCi/m2/sec 6 pCi/m2/sec
Baseline Baseline
=s=sss=s=s:s=;
Risk
1.8
1.00
0.35
Cancers avoided
over 100 years:
0.80
1.45
0.65
Risk 0.0180 0.0100 0.0035
Annual cancers
avoided: 0.0080 0.0145 0.0065
3-17
-------
technology development and evaluation, site acquisition, costs for a planning contractor, management
support, design, construction management, and associated services. Finally, since many of these items
represent sunk costs, an alternative factor of 2.4, which measures only estimated future costs, is also
included in the analysis.
The estimates of costs on a pile-by-pile basis are presented for the DOE design flux, 6 and 2
pCi/m2/sec options in Tables 3-8, 3-9, and 3-10, respectively. Achieving the DOE design flux is
estimated to cost between $136 and $418 million. In contrast, reaching the 6 pCi/m2/sec option is
estimated to cost from $157 to $483 million, while compliance with the 2 pCi/m /sec option would
entail costs estimated to reach between $ 188 and $579 million,
-j
Expenditures to meet the DOE design flux or the 6 and 2 pCi/m /sec options are assumed to begin
in 1989 and be accomplished over five years. Dollar expenditures are in equal amounts in each of
the five years in current dollars.
Table 3-11 provides the incremental present value costs for the three radon fluxes and added costs
for lowering the allowable flux. Estimates for each of the DOE project cost factors and each of the
four real interest rates, are included. Lowering the allowable flux rate to 6 pCi/m2/sec will entail
added present value costs of between $13 and $64 million depending on assumptions as to project cost
and discount rates, while attainment of a 2 pCi/m2/sec flux rate would entail costs of $33 to $161
million. The incremental costs of moving from the 6 pCi/m2/sec option to the 2 pCi/m2/sec option
is estimated to range from $19 to $96 million.
The present value costs are also shown graphically in Figure 3-1. This graph indicates that the
marginal cost per unit of radon flux reduction is lower between 20 pCi/m2/sec and 6 pCi/m2/sec than
between 6 pCi/m2/sec and 2 pCi/m2/sec. This reflects the increasing depth of cover required per
unit decrease in radon flux. Figure 3-1 also shows that the cost per unit of radon flux reduction is
lower at higher real interest rates reflecting the reduced present value of future cash streams.
Table 3-12 provides similar estimates to those given in Table 3-11, except the values in 3-12 are
presented on an annualized cost basis. For the 6 pCi/m2/sec option, added costs on an annualized
basis range from $1.1 to $4.8 million depending on cost factor and discount rate assumptions. For
the 2 pCi/m2/sec option, added costs vary from $2.6 to $11.8 million.
3-18
-------
Table 3-8: Costs of Achieving the DOE Approved Cover Design F lux for Inactive Kill Tailiftgs,
(1988 $, Million).
Total Inct.
Total Incl.
Total Incl.
Cost
Cost
Cost
Regrade
Dirt
Apply
Apply
Reclaim
Factor
Factor
Factor
Pile Hame
S!opes
Cover Riprap
Gravel
Borrow Pits
Total
8 1.07
a 2.4
a 3.3
Tuba City
0
09
3
0?
0.41
0.20
0.15
3.93
4.20
9.42
12.96
Durarigo
0
23
4
81
0.75
0.37
0.23
6.39
6.84
15.34
21.09
Grand Junction
0
44
9
82
1.16
0.57
0,48
12.47
13.35
29.94
41.16
Gunn i son
0
21
6
65
0.71
0.35
0.32
8.25
8.83
19.81
27.23
Maybe 11
0
65
9
14
1.50
0.74
0.45
12.48
13.35
29.94
41.17
Naturi ta
0
10
1
77
0.44
0.22
0.09
2.61
2.80
6.27
8.62
Rifle
0
54
8
77
1.33
0.66
0.43
11.73
12.55
28.15
38.70
Slick Rock
0
01
0
61
0.11
0.06
0.03
0.82
0.88
1.98
2.72
Lowman
0
01
0
57
0.09
0.05
0.03
0.75
0.80
1.79
2.46
Ambrosia Lake
0
98
12
68
1.97
0.97
0.62
17.21
18.42
41.31
56.80
Shsprock
0
55
7
49
1.35
0.67
0.37
10.42
11.15
25.00
34.38
Bowman/Belfielc
0
04
1
05
0.22
0.11
0.05
1.47
1.58
3.53
4.86
Lakeview
0
15
2
75
0.56
0.28
0.13
3.86
4.14
9.28
12.75
Canonsburg
0
0?
3
57
0.34
0.17
0.17
4.32
4.62
1.0.36
14.24
FalIs City
1
60
13
32
2.74
1.35
0.65
19.66
21.03
47.17
64.86
Green River
0
02
1
54
0.17
0.08
o.os
1.89
2.02
4.54
6.25
Mexican Hat
0
02
0
93
0.13
0.06
0.05
1.19
1.27
2.85
3.92
Salt Lake
0
32
5
40
0.93
0.46
0.26
7.37
7.88
17.68
24.32
Totals
6
05
93
.92
14.91
7.36
4.58
126.81
135.69
304.35
418.49
3-19
-------
Table 3-9: Costs of Achieving the 6 pCi/m2/sec Flux limit.
(1988 $, Million).
Total !ncl.
Total Incl.
Total Incl.
Cost
Cost
Cost
Regracfe
Dirt
Apply
Apply
Reclaim
Factor
Factor
Factor
Pile Name
Slopes
Cover Riprap Gravel Borrow Pits
Total
3 1.07
a 2.4
a 3.3
Tuba City
0.09
3.40
0
41
0.20
0
17
4.27
4
57
10.25
14.10
Durango
0.23
6.46
0
75
0.37
0
31
8.12
8
69
19.49
26.80
Grand Junction
0.44
9.99
1
16
0,57
0
49
12.65
13
54
30.36
41.75
Gunnison
0,21
6.65
0
71
0.35
0
32
8.25
8
83
19.81
27.23
Maybe 11
0.65
9.60
1
50
0.74
0
47
12.96
13
87
31.10
42.76
Naturi ta
0.10
1.77
0
44
0.22
0
09
2.61
2
80
6.27
8.62
Rifle
0.54
11.69
1
33
0.66
0
57
14.79
15
83
35.50
48.81
Siick Rock
0.01
0.61
0
11
0,06
0
03
0.82
0
88
1.98
2.72
lowntan
0.01
0.57
0
09
0.05
0
03
0.75
0
80
1.79
2.46
Ambrosia Lake
0.98
16,35
1
97
0.97
0
80
21.07
22
54
50.56
69.52
Shiprock
0.55
10.45
1
35
0.67
0
51
13.52
14
47
32.45
44.62
Bowman/Bet field 0.04
1,05
0
22
0.11
0
05
1.47
1
58
3.53
4.86
takeview
0.15
2.97
0
56
0.28
0
15
4.10
4
39
9.85
13.54
Canonsburg
0.07
3.66
0
34
0.17
0
18
4.41
4
72
10.60
14.57
Fal Is City
1.60
17.26
2
74
1.35
0
84
23.78
25
45
57.08
78.49
Green River
0.02
1.54
0
17
0.08
0
08
1.89
2
02
4.54
6,25
Mexican Hat
0.02
1.10
0
13
0.06
0
05
1.36
1
45
3.25
4.47
Salt Lake
0.32
7.44
0
93
0.46
0
36
9.51
10
18
22.83
31.39
Totals
6.05
112.55
14.91
7.36
5
49
146.35
156.60
351.25
482.97
Note: Costs calculated for the lower of 6 pCi/m2/sec or the DOE design flux.
3-20
-------
Table 3-10: Costs of Achieving the 2 pCi/m2/sec Flux Limit.
(1988 $, Million),
Total Incl. Total Jncl. Total Incl
Cost Cost Cost
Regrade Dirt Apply Apply Reclaim Factor Factor Factor
Pile Name Slopes Cover Riprap Gravel Borrow Pits Total 8 1.07 8 2.4 a 3.3
Tuba City
0.
09
4.22
0
41
0
20
0.21
5.14
5
50
12.33
16.96
Durango
0.
23
7.96
0
75
0
37
0,39
9.70
10
38
23.27
32.00
Grand Junction
0
44
12.32
1
16
0
57
0.60
15.09
16
15
36.23
49.81
Gunnison
0
21
6.65
0
71
0
35
0.32
8.25
8
83
19.81
27.23
Maybe 11
0
65
12.61
1
50
0
74
0.61
16.11
17
24
38.67
53.17
Naturi ta
0
10
2.50
0
44
0
22
0.12
3.38
3
62
8.12
11.17
Rifle
0
54
14.36
1
33
0
66
0.70
17.58
18
81
42.20
58.03
Slick Rock
0
01
0.83
0
11
0
06
0.04
1.05
1
13
2.53
3.48
lowman
0
01
0.75
0
09
0
05
0.04
0.93
1
00
2.24
3.08
Ambrosia Lake
0
98
20.30
1
97
0
97
0.99
25.20
26
97
60.49
83.18
Shiprock
0
55
13.15
1
35
0
67
0.64
16.35
17
50
39.25
53.97
Bowman/Bel field
0
04
1.32
0
22
0
11
0.06
1.76
1
88
4.22
5.81
Lakevi ew
0
15
4.10
0
56
0
28
0.20
5.28
5
65
12.68
17.43
Canonsburg
0
0?
4.34
0
34
0
17
0.21
5.12
5
48
12.30
16.91
falls City
1
60
22,74
2
74
1
35
1,11
29.54
31
61
70,89
97,48
Green River
0
02
1.54
0
17
0
08
0.08
1.89
2
02
4.54
6.25
Mexican Hat
0
02
1.35
0
13
0
06
0.07
1,62
1
74
3.90
5,36
Salt Lake
0
32
9.31
0
93
0
46
0.45
11.47
12
27
27.53
37.85
Totals
6
05
140.34
14
91
7
36
6.85
175.50
587
79
421.2!
579.16
Note: Costs calculated for the lower of 2 pCi/m2/sec or the DOE design flux.
3-21
-------
Table 3-11; Incremental Present Value Costs of towering the Allowable
limit to 6 pCi/m2/sec and 2 pCi/mZ/sec for Inactive Piles.
(1988 $, Millions)
6 p€i/m2/sec
Opt i on
2 pCi/iti2/see
Opt i on
Incremental Incremental Incremental
Cost From Cost From Cost From
20 pCi/m2/sec 20 pCi/m2/sec 6 pCi/m2/sec
Baseline Baseline Option
1.0? Cost Factor
0 % Real Interest Rate
1 % Real Interest Rate
5 X Real Interest Rate
10 % Real Interest Rate
$20.91
$19.90
$16.42
$13.10
$52.10
$49.57
$40.92
$32.64
$31.19
$29.68
$24.50
$19.54
1.4 DOE Cost Factor
0 % Real Interest Rate
1 % Real Interest Rate
5 % Real Interest Rate
10 % Real Interest Rate
$46.90
$44.62
$36.83
$29.38
$116.85
$111.19
$91.78
$73.22
$69.96
$66.57
$54.94
$43.83
2.3 DOE Cost Factor
0 X Real Interest Rate
1 % Real Interest Rate
5 % Real Interest Rate
10 % Real Interest Rate
$64.48
$61.36
$50.64
$40.40
$160.67
$152.89
$126.19
$100.68
$96.19
$91.53
$75.55
$60.27
3-22
-------
Table 3-12: Incremental Annualized Costs of lowering the Allowable
limit to 6 pCi/m2/sec and 2 pCi/m2/sec for Inactive Piles.
(1988 $, Millions)
1.07 Cost factor
0 % Real Interest Rate
1 % Real Interest Rate
5 % Real Interest Rate
10 X Real Interest Rate
1.4 DOE Cost Factor
0 % Real Interest Rate
1 % Real Interest Rate
5 % Real Interest Rate
10 % Real Interest Rate
2,3 DOE Cost Factor
0 % Real Interest Rate
t % Real Interest Rate
5 % Real Interest Rate
10 % Real Interest Rate
6 pCi/n»2/sec
Option
2 pCi/m2/sec
Opt i on
Incremental Incremental Incremental
Cost From Cost From Cost From
20 pCi/m2/see 20 pCi/m2/sec 6 pcf/m2/sec
Baseline Baseline Option
$1.05
SI.10
$1.32
$1.54
$2.60
$2.75
$3.28
$3.83
$1.56
$1.64
$1.97
$2.30
$2.34
$2.47
$2.96
$3.45
$5.84
$6.16
$7.36
$8.60
$3.50
$3.69
$4.41
$5.15
$3.22
$3.40
$4.06
$4.75
$8.03
$8.47
$10.13
$11.83
$4.81
$5.07
$6.06
$7.08
3-23
-------
Figure 3-1.
Cost of Lowering the Allowable Flux
450
400
350
300
250
200
150
(22)
(18)
(14)
(10)
(0)
Radon Flux (pCi/m2/sec)
0% Real Interest
5% Real Interest
1% Real Interest
10% Real Interest
-------
3.5 Economic 1mi>iu( Analysis
The purpose of this section is to evaluate the economic impacts of Federal and state expenditures to
comply with the costs associated with lowering the allowable radon-222 emission rate. No attempt
is made to quantify these impacts, instead a qualitative discussion is given.
The costs of regulatory remedial actions, for any inactive mills not on Indian lands, are shared by the
Federal and State governments. The Federal Government is accountable for ninety percent of these
costs. In the case of Indian lands, however, the Federal Government is solely responsible for any
costs associated with the disposal of tailings. Thus, these regulations have no impact on the uranium
industry. In addition, there will be no impact on small businesses.
Any regulatory remedial action is expected to have positive economic impacts at both the state and
local levels. The impacts are the result of fiscal injections and could be measured in terms of
increased local employment, income and standards of living. These funds would come from the
Federa 1 (DOE) and State budgets. The expenditures are transfer payments, i.e., the funds are
generated through taxes and spent on particular programs or areas. In most cases these expenditures
will result in higher Federal expenditures within each state than would have occurred without these
programs. There will be no disproportionate increase, however, in Federal taxes paid by residents
of these states.
3-25
-------
REFERENCES
DOE88 U.S. Department of Energy, "Annual Status Report on the Uranium Mill Tailings
Remedial Action Program," Washington, D.C., December 1988.
EPA82 U.S. Environmental Protection Agency, Final Environmental Impact Statement for
Remedial Action Standards for Inactive Uranium Processing Sites (40 CFR 192), Vol.1,
EPA 520/4-82-013-1, Office of Radiation Programs, Washington, D.C., October 1982.
EPA83 U.S. Environmental Protection Agency, Final Environmental Impact Statement for
Standards for the Control of By-Product Materials from Uranium Ore Processing (40
CFR 192), Vol, 1, EPA 520/1 -83-008-1, Office of Radiation Programs, Washington,
D.C. 1983
EPA86 U.S. Environmental Protection Agency, Final Rule for Radon-222 Emissions from
Licensed Uranium Mill Tailings, EPA 520/1-86-009, OFfice of R Adiation Programs,
Washington, D.C., August 1986.
EPA89 Risk Assessments, Vol. 2.
NM 85 Personal communication, Energy and Minerals Department, Mine Inspection Bureau,
State of New Mexico, December 1985.
NRC80 U.S. Nuclear Regulatory Commission, Final Generic Environmental Impact Statement
on Uranium Milling, NUREG-0706, Washington, D.C., September 1980.
PNL84 Pacific Northwest Laboratory. "Estimated Population Near Uranium Tailings," PNL-
4959, WC-70, Richland, WA, Janurary 1984.
3-26
-------
CHAPTER 4
LICENSED URANIUM MIX TAILINGS FACILITIES
-------
4. LICENSED MILL TAILINGS
4.1 Introduction and Summary
The licensed uranium mill tailings source category comprises the tailings impoundments and
evaporation ponds created by conventional acid or alkaline leach processes at uranium mills licensed
by the Nuclear Regulatory Commission (NRC) or the Agreement States. Recovery of uranium by
conventional milling results in the release of uranium and its decay products to the air. The risks
associated with the release of uranium and other radionuclides in the form of particulates are
addressed in the proposed regulation for the uranium fuel cycle source category (Chapter 1). This
assessment addresses only radon-222 released from the tailings impoundments and their associated
evaporation ponds. Previous evaluations have shown that radon releases from other milling operations
are insignificant [NRC8Q, EPA82, EPA83, EPA86J.
In August 1988, the conventional uranium milling industry in the United States consisted of 26
licensed facilities. The licensed conventional uranium mills that have operated are in Colorado, New
Mexico, South Dakota, Texas, Utah, Washington, and Wyoming. Only 4 of the 26 licensed facilities
were operating; 8 were on standby status; and 14 were being or have been decommissioned. The mills
on standby status are being maintained, but they are not processing uranium ore. When demand for
uranium increases, these standby mills can resume milling. The decommissioned mills have been
dismantled and have either been moved off-site or disposed of on-site. These mills can never resume
operations. Their associated tailings impoundments are either being reclaimed, or plans to reclaim
them have been made. Three other mills have been licensed, but two were never constructed, and
one was built but never operated. These three mills are not discussed further here [EPA89].
The purpose of this chapter is to examine the costs, benefits, and economic impacts of three separate
decisions that need to be addressed in promulgating the new Clean Air Act standards for release of
radionuclides from licensed uranium mill tailings piles. The first decision to address is whether to
reduce the limit on allowable radon-222 emissions after closure from the current Uranium Mill
Tailings Radiation Control Act (UMTRCA) standard of 20 pCi/m2/sec. Options that are evaluated
include allowable limits of 6 pCi/m2/sec and 2 pCi/m2/sec.
4-1
-------
The second decision to consider is whether to reduce the limit on allowable emissions of operating
mills without curtailing the operation of the mills. The limit to be considered is a maximum average
radon emission of 20 pCi/m2/sec during the operational life of the facility.
While the first two decisions are focused on existing piles, the third is concerned with future tailings
impoundments. The decision to be addressed for future tailings is whether work practice standards
should be promulgated for the control of radon emissions from operating mills in the future. Options
that are investigated include the replacement of the traditional single cell impoundment with phased
or continuous disposal impoundments.
The remainder of this introduction provides a brief summary of the rulemaking history and current
regulations. A profile of the uranium milling industry is given in Section 4.2. Included are industry
characteristics such as demand and supply, financial and community analyses, and projections of
industry production and employment. Section 4.3 addresses current emissions, risk levels and feasible
control methods. Section 4.4 provides estimated benefits and costs for each of the options under the
separate decision frameworks. The economic impacts are considered in Section 4.5.
4.1.1 Rulemaking History and Current Regulations
On January 13, 1977, the EPA issued Environmental Protection Standards for Nuclear Power
Operations. These standards {40 CFR 190) limit the total individual radiation dose during normal
operations from uranium fuel cycle facilities, including licensed uranium mills. However, when 40
CFR 190 was promulgated, considerable uncertainty existed regarding the public health risk from
radon-222 and the best method for managing new manmade sources of this radionuclide. Therefore,
the doses caused by emissions of radon-222 are excluded from the limits established in 40 CFR 190,
On April 6, 1983, the Agency proposed National Emission Standards for Hazardous Air Pollutants
(NESHAPS) for radionuclides under Section 112 of the Clean Air Act (CAA). At that time, it
determined that uranium fuel cycle facilities should be exempt from the NESHAP for NRC-Licensed
Facilities, since they were already subject to the dose limits of 40 CFR 190. During the comment
period, it was noted however, that radon-222 emissions from operating uranium mills posed
significant public health risks and that such emissions were not subject to any current or proposed
EPA standards.
4-2
-------
On September 30,1983, under the authority of UMTRCA, the Agency issued final standards (40 CFR
192) for the management of mill tailings at licensed facilities. Although the UMTRCA standard
requires procedures to maintain radon-222 emissions as low as reasonably achievable (ALARA)
during operations, it does not impose a numerical limit on radon-222 emissions until after closure of
a facility. Current NRC regulations impose a concentration limit at the boundary. After closure,
the tailings must be disposed of in accordance with the standard, and the post-disposal radon-222
emission rate cannot exceed an average of 20 pCi/m2/sec. At the time the UMTRCA standard was
promulgated, taking into account the comments received during the radionuclide NESHAPS
rulemaking, the Agency stated that it would issue a Notice of Proposed Rulemaking (under Section
112 of the CAA) with respect to control of radon-222 emissions from uranium tailings piles during
the operational period of a uranium mill. This notice was published on October 21, 1984.
On September 24, 1986, the Agency promulgated a NESHAP (40 CFR 61, Subpart W) for radon-
222 emissions from licensed uranium mills during operations. NESHAP imposes a work practice
standard of either phased or continuous disposal on ali new tailings impoundments and prohibits the
use of existing tailings piles after December 31, 1992.
4.2 Industry Profile
The U.S. uranium milling industry is an integral part of a domestic uranium production industry that
includes companies engaged in uranium exploration, mining, milling, and downstream activities
leading to the production of fuel for nuclear power plants. The product of uranium milling is
uranium concentrate, also referred to as uranium oxide, yellowcake, or U3Og. Uranium concentrate
may be produced either from mined and milled ore or through alternative sources such as solution
mining, heap leaching, mine water, mill tailings, low-grade stockpiles, and as a byproduct of other
activities. Only production from conventionally mined and milled ore is addressed in this chapter
(see Section 4.2.2).
4.2.1 Demand
Domestic producers of uranium concentrate have two markets for their production: the U.S. nuclear
power industry and exports. The nuclear power industry is the more important of the two. Military
uses, once the only source of demand for uranium, have been supplied solely by government
stockpiles since 1970 [DOE 87a].
4-3
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Demand for domestic uranium has declined since the late 1970s. In 1979, utilities delivered 15,450
tons of domestic uranium oxide to DOE for enrichment, 86 percent more than 1986 deliveries.
Exports, too, have declined substantially. In 1979, exports amounted to 3,100 tons, almost four times
as much as in 1986. A number of negative forces have combined to cause the current depressed state
of the industry. Perhaps most importantly, the growth in electricity generated by nuclear plants and
the expansion of nuclear power capacity has been much slower than had been forecast in the mid-
1970s. This slower growth is due in part to numerous construction delays and cancellations. Second,
imports have begun to play a major role in the U.S. uranium market. The import restrictions were
gradually withdrawn between 1975 and 1985. The result has been a steady increase in uranium
imports from nations possessing high grade (and thus low cost) uranium deposits. Expectations are
that a growing portion of utility requirements will be supplied by foreign-origin uranium during the
second half of this decade [JFA 85a].
Also contributing to the current downturn in the uranium industry are the large inventories being
held by both producers and utilities. Utilities, anticipating a growing need for uranium, entered into
long-term contracts to purchase large amounts of domestically-produced uranium. As actual needs
fell short of expected needs due to nuclear power plant construction delays and cancellations, large
inventories accumulated. These inventory supplies, currently estimated to cover four to five years
of utility requirements, adversely affect suppliers in two ways. They may extend the downturn in
uranium demand for a number of years by decreasing the need for utilities to enter into new
contracts. Also, high interest rates increased inventory holding costs, leading some utilities to
contribute to current excess supply by offering inventory stocks for sale on the spot market [JFA
85a],
The focus of the remainder of this section is total U.S. demand for uranium, not just demand for
domestic production or production from conventional mills. The first subsection details historical
uses of uranium. The concluding subsection provides a brief description of uranium prices and
pricing mechanisms.
4-4
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4.2.1.1 Uranium Uses
Military Applications
in the early 1950s, the U.S. government's need for uranium for defense uses far exceeded the world's
production capability. A federally funded production incentives program was then instituted. The
incentives program was so effective that the government phased it out in the 1960s and terminated
its purchase program in 1970. The government still has sufficient stockpiles to meet military
requirements well into the future.
Nuclear Power Plants
Since 1971, utilities which use uranium as fuel for nuclear power plants, have been virtually the only
source of demand for current uranium production. Commercial generation of nuclear powered
electricity began in 1957 with the operation of the first central station reactor at Shippingport,
Pennsylvania, At the end of 1986, 100 nuclear reactors were licensed to operate in the United States,
with 85.2 gjgawatts of net generating capacity [DOE 87c].
Demand for uranium by utilities may be directly linked to the fuel requirements of currently
operating or planned nuclear power plants. The status of U.S. nuclear power plants as of December
31, 1986 is shown in Table 4-1. Because of the long lead times associated with the ordering,
construction and permitting of nuclear power plants, it is extremely unlikely that any additional
orders for new nuclear plants will result in operable capacity before 1998 [DOE 87c]. Historical
consumption data for utilities are not available. The closest approximation is statistics on deliveries
by utilities of uranium to DOE enrichment plants. Deliveries for 1977 to 1986 are listed in Table 4-2.
Exports
Exports of uranium by producers have declined steady since 1979. In 1984, at 1,100 tons of U308,
exports were the lowest since 1976. Current commitments for exports total only 4,400 tons for
1985-2000 [DOE 85b], Exports for 1977-1986 are shown in Table 4-3.
4-5
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Table 4-1: Status of U.S. Nuclear Power Plants as of December 31, 1986.
Number Net Summer
of Capability
Status Beactors (GWe)
Operable
In Commercial Operation 98 82.9*
In Power Ascension 2 2.3
Total 100 85.2
In Construction Pipeline
In Low-Power Testing 7 7.1
Under Construction 14 16.1
Indefinitely Deferred 5 6.1
Total 26 29.4
Reactors on Order 2 2.2
Total 128 116.8
"Three Mile Island 2, Dresden 1, and Humboldt Bay are not included. The Hanford-N reactor is
included.
Source: (DOE 87c)
4-6
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Table 4-2: Deliveries of Uranium to DOE Enrichment Plants by Domestic Utilities.
Year
Amount Delivered
(Short Tons U30„)
U.S.
Origin
Foreign
Origin
Total
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
14,250
11,950
15,450
11,150
10,050
13,550
10,850
8,400
8,950
8,300
700
750
1,600
1,200
1,150
3,000
2,200
5,750
3,800
5,350
14,950
12,700
17,050
12,360
11,200
16,550
13,050
14,150
12,750
13,650
Sources; (DOE 84a, DOE 85b, DOE 86b, DOE 87b)
4-7
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Table 4-8: Exports of Uranium® (Thousand Short Tons of U3Og).
Historical Eroorta
Total
Producer
XSS
Exoorta
Exoorts
1967
NA
0.7
1968
NA
0.8
1969
N A
0.5
1970
NA
2.1
1971
NA
0.2
1972
NA
0.1
1978
N A
0.6
1974
NA
1.5
1975
NA
0.5
1976
NA
0.6
1977
NA
2.0
1978
N A
3.4
1979
N A
3.1
1980
NA
2.9
1981
NA
2.2
1982
8.10
2.2
1983
1.65
NA
1984
1.10
NA
1985
2.65
NA
1986
0.80
NA
Sources: (DOE 84a, DOE 85a, DOE 87b)
®TotaI exports include exports by utilities, producers and other suppliers (reactor manufacturers and
fuel fabricators). Data for exports by utilities and other suppliers were not collected until 1982.
NA = Not Available.
4-8
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Pricing
Two basic types of pricing arrangements dominate the procurement of uranium: contract pricing and
market pricing. In contract pricing, prices and their escalation factors, if any, are determined when
the contract is signed. In market pricing, the price is commonly determined just before delivery and
is based on the market price prevailing at that time. Some market price contracts contain a floor
price, set at the time the contracts are signed, that serves as a minimum on the eventual settled price.
Pricing arrangements that cannot be classified as either market or contract pricing are grouped in a
third category. This other category refers primarily to supply arrangements wherein the buyer has
direct control of a uranium property. Among 1986 deliveries of uranium, 36 percent used contract
pricing, 49 percent used market pricing, and 15 percent used other pricing arrangements [DOE 87a],
The concept of market pricing is probably the most complex of the three types. While it is common
to refer to a market or spot price for uranium, there is actually no centralized spot or futures market.
Contracts are negotiated between a producer and a utility either, through a middleman such as a
nuclear power plant manufacturer or through a broker. The price commonly referred to as the spot
price for uranium is a price published by the Nuclear Exchange Corporation (NUEXCO), the
principal uranium broker. This price, which NUEXCO calls the uranium exchange value, is a
monthly estimate of the price at which transactions for immediate delivery could have been
concluded as of the last day of the month [DOE 87cj.
Historical Prices and Pricing Mechanisms
Until 1968, prices were largely determined by the Atomic Energy Commission. In the early years
of the commercial uranium market, 1968 through 1973, the price of uranium declined and remained
low despite conditions of excess long-term demand. Beginning in 1973, the price of uranium jumped
due to immediate industry requirements, a surge in long term contracting resulting from changes in
procedures for enrichment service contracts, and other factors.
At the same time, the terms under which long-term contracts were priced began to change. Until
1973, contracting was typically under fixed price contracts with inflation provisions. However, in
1973, producers resisted signing fixed price contracts, because, as a result of production cost
increases, they were losing money on previous fixed price contracts, and because they anticipated
price rises in the future. In 1974, when the uranium market became a seller's market, market price
4-9
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contracts became popular. These contracts were written to guarantee the producer a base
rate-of-return on investment. In a short time, market price contracts became the norm.
In 1979-1980, the seller's market for uranium ended, and the uranium market witnessed a sharp
decline in prices due to postponements and cancellations of nuclear reactors, the build-up of uranium
inventories at utilities, and the growing competition from low-priced imported uranium. A sharp
decline in the nominal price of uranium began in 1980, dropping from over $40 per pound of U3Og
at the end of 1979 to $23,50 per pound by August 1981, In real terms (adjusted for inflation), the
price had actually begun dropping in 1976. The price in August 1981 in constant dollars was half
of what it had been in 1976, The price has continued to drop slowly from 1980 through 1987 [DOE
87aJ.
The average contract prices for deliveries made between 1982 and 1986 is given in Table 4-4. Market
price settlements for the same period are included with contract prices because, as settled prices, they
are similar to contract prices. This procedure gives a generally comprehensive average price for
actual deliveries (except for deliveries made under litigation settlements or other pricing
arrangements). Historical NUEXCO exchange values, or "spot prices" are listed in Table 4-5.
Prices of Foreign-Origin Uranium
Prices of imported uranium are substantially lower than domestic contract prices. The average price
paid for 1986 deliveries of imported uranium was $20.07 per pound of U3Og5 approximately
one-third less than the amount paid for domes tic-origin uranium, $30.01 [DOE 8 7a]. Table 4-6
shows the average price paid by domestic customers for 1981 to 1986 deliveries of foreign-origin
uranium.
4.2.2. Sources of SuddIv
The uranium used to fuel nuclear reactors is supplied by domestic and foreign producers, inventories
held by utilities, and secondary market transactions such as producer-to-producer sales,
utility-to-utility sales and loans, and utility-to-producer sales. The role of each is described in the
following sections.
4-10
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Table 4-4: Average Contract Price and Harket Price Settlements
for Actual Deliveries 1982-1986,
(Year of Delivery Dollars)
(a) CaXb)
Reported Quantity: Quantity: Adjusted
Year of Price Price Reported Price Not Reported Price
Delivery ($/tb) (Million lbs) (Billion lbs) (S/lb)
1982 38.37 16.7 2.6 39.82
1983 38.21 17.4 0.5 37.81
1984 32.65 16.1 0.3 32.38
1985 31.43 15.8 0.7 30.79
1986 30.01 12.1 0.0 30.01
Notes: (a) Price excludes uraniun delivered under litigation settleaents.
(b) The adjusted price is a weighted average of reported prices and
price estiaatas for respondents to the E« survey yho did not
supply price inforsation. Price estinates are based on regression
analysis of the reported prices.
Source : (DOE 87b)
4-11
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Table 4-5: Historical Nuexco Exchange Values.
(Nominal Dollars Per Pound of U30B)
Year
As of December 31
1968
6,50
1969
6.20
1970
6.15
1971
5.95
1972
5.95
1978
7.00
1974
15.00
1975
35.00
1976
41,00
1977
43.00
1978
43.25
1979
40.75
1980
27.00
1981
23.50
1982
20.25
1983
22.00
1984
15.25
1985
17.00
1986
16.75
1987
16.55
Source; [NUEXCO 8?]
4-12
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Table 4-6; Prices for Foreign-Origin Uranium.
Total
Average Price Per Amount Import Delivery
Pound of U3Oa of U30B Commitments Sampled
Year (Current Dollars ) {Thousand Short Tons) (Percent)
1981 82.90 2,20 67
1982 31.06 2.0S 58
1983 26.16 4.1Q 100
1984 21.08 5.55 89
1985 20.08 5.85 91
1986 20.07 &40 95
Source: [DOE 87b].
4-13
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Domestic Production
Table 4-7 shows trends in domestic production of uranium concentrate from 1947 to 1986, by state.
Total production was relatively constant at 10,500 to 13,000 tons per year until 1977, when it began
an increase that peaked in 1980 at 21,852 tons. Production has declined almost every year since,
reaching only 6,753 tons in 1986 [DOE 87b].
Coinciding with the overall decline in domestic production is a decline in the share of production
represented by conventional mills. Historically, conventional milling accounted for, on average,
approximately 70 percent of U.S. production. By 1985, the conventional share of production had
fallen to a low of 53.8 percent, but in 1986 it rose to 65.6 percent (Table 4-8). This increase in
market share is the result of an increase in the U3Og content of the ore being milled. Only high grade
ores can be cost-effectively milled under current market conditions.
By contrast, non-conventional uranium production has not declined as severely, and the share of
uranium produced by non-conventional methods has increased consistently. This is explained by the
low marginal cost of producing uranium as a by-product or from the water in a closed underground
mine. According to an unofficial 1983 DOE estimate, 50 percent of non-conventional production
is from by-product recovery, 40 percent is from in situ leaching, and ten percent from heap leaching
and mine water processing. Wet process phosphoric acid, copper waste dumps, and bellyrium ores
constitute by-product methods of production of U3Og. The second significant non-conventional
source is in situ leaching. In 1986, by-product and in situ leaching, together, accounted for 79
percent of the total non-conventional annual production of UjOg. Other less important sources
include mine water, and heap leaching, which accounted for 21 percent of total non-conventional
production in 1986.
The result of the decline in demand for conventional production has been severe overcapacity and
mill shutdowns [DOE 85a}. Milling capacity, which almost doubled between 1975 and 1980 when the
price of uranium was high and optimistic demand forecasts stimulated investment in milling facilities,
once enjoyed a utilization rate of 94 percent [JFA 85a]. In December 1986, capacity utilization was
about 32 percent at operating mills. The number of operating mills has declined dramatically also,
from 20 in 1981 to a low of two in June 1985 [DOE 85a]. NUEXCO indicates that six mills operated
in 1987, and Volume 2 of the Environmental Impact Statement reports that only four were operating
4-14
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Table 4-7: Total Uraniua Concentrate Production, 1947-1986,
Year(s) Colorado Naw Mexico Texas Utah Wyoming OthersCa) Total
1947-65
29,652
54,301
Cb)
28,924
18,449
8,380
139,706
1966
1,423
5,076
(b)
Cc)
2,248
1,842
10,589
1967
1,340
5,933
Cb)
Cc)
2,667
1,313
11,253
1968
1,614
6,192
Cb)
Cc)
2,873
1,689
12,368
1969
1,678
5,943
Cb)
Cc)
3,063
925
11,609
1970
Cc)
5,771
Cb)
Cc)
3,654
3,480
12,905
1971
Cc)
5,305
Cb)
Cc)
3,487
3,481
12,273
1972
(c)
5,464
Cb)
Cc)
4,216
3,220
12,900
1973
(c)
4,634
Cb)
Cc)
5,159
3,442
13,235
1974
Cc)
4,951
(b)
Cc)
3,767
2,810
11,528
1975
Cc)
5,191
Cc)
Cc)
3,447
2,962
11,600
1976
(c)
6,059
Cc)
Cc)
4,046
2,642
12,747
1977
Cc)
6,779
Cc)
Cc)
4,990
3,170
14,939
1978
Cc)
8,539
Cc)
Cc)
5,329
4,618
18,486
1979
Cc)
7,423
2,651
Cc)
5,452
3,210
18,736
1980
Cc)
7,751
3,408
Cc)
6,036
4,657
21,852
1981
Cc)
6,206
3,141
Cc)
4,355
5,535
19,237
1982
Ce)
3,906
2,131
Cc)
2,521
4,876
13,434
1983
Cc)
2,830
1,600
Cc)
2,630
3,519
10,579
1984
Sc)
1,458
1,310
Cc)
1,560
3,113
7,441
1985
Cc)
694
1,085
Cc)
1,214
2,667
5,657
1986
Cc)
376
1,293
Cc)
317
4,768
6,753
Notes: (a) Includes, for various years, Arizona, Colorado, Florida,
Louisiana, South Dakota, Texas, Utah, arid Washington.
Cb) Data were not collected.
(c) Included in the "others" category.
4-15
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Table 4-8: Production of Uraniua Concentrate by conventional Bills and other
Sources, 1978-1986 (short tons U308)
Conventional Average
Production U308
Conventional Other Total As a Percent Concentration
Year Production Productions) Production of Total of Ore Milled (X)
1978 17,172 1,315 18,486 93 0.131
1979 16,677 1,860 18,736 90 0.105
1980 18,903 2,950 21,852 87 0.118
1981 15,998 3,239 19,237 83 0.115
1982 10,447 2,988 13,434 78 0.119
1983 7,760 2,820 10,579 73 0.128
1984 4,813 2,628 7,441 65 0.112
1985 3,042 2,615 5,657 54 0.161
1986 4,427 2,327 6,753 66 0.336
Note:
-------
in 1988 (Table 4-13), but industry sources predict that the number of operating mills* couid drop to
three within two to five years. Uranium mill capacities and utilization levels are listed in Table 4-9.
imports
A second source of uranium is the import market. Until 1975, foreign uranium was effectively
banned from U.S. markets by a Federal law prohibiting the enrichment of imports for domestic use.
This restriction was lifted gradually after 1975, and was eliminated completely in 1984. From 1975
through 1977, imports amounted to a small portion of total domestic requirements, with U.S. exports
exceeding imports in each year from 1978 through 1980. By 1986, however, imports supplied 44
percent of U.S. requirements. Table 4-10 lists U.S. imports from 1974 through 1986 [DOE 87aJ,
The primary sources of U.S. uranium imports have been Canada, South Africa and Australia. In 1986,
59 percent of U.S. uranium imports were from Canada, and 41 percent were from Australia and South
Africa [DOE 87a].
Forecasts of import penetration call for the import share to grow through the 1990s. The Department
of Energy projects that without government intervention, between the year 1990 and 2000 imports
will range between 50 and 64 percent of domestic utility requirements, depending on demand levels.
Inventories
Utilities hold uranium inventories in order to meet changes in the scheduling of various stages of the
fuel cycle, such as minor delays in deliveries of uranium feed. Uranium inventories also protect the
utilities against disruption of nuclear fuel supplies. The average "forward coverage" currently desired
by domestic utilities (in terms of forward reactor operating requirements) is 18 months for natural
uranium (UjOg) and seven months for enriched uranium hexafluoride (UF6) [DOE 85a],
Table 4-11 lists inventories of commercially-owned natural and enriched uranium held in the United
States as of December 31, 1984, 1985, and 1986. DOE-owned inventories are not included. The
uranium inventory owned by utilities alone at the end of 1984 represented almost four years of
forward coverage.
4-17
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Table 4-9: Uranium Mill Capacity (Teas of Ore Per Day).
Operating Total
Capacity
Capacity
Total
Operating
Utilization
Utilization
Year
Caoacitv
Canamtv
Rate
Rate
1081
54,050
49,800
83
77
1982
55,050
83,650
74
45
1983
51,650
29,250
58
33
1984
48,450
19,250
64
25
1985
47,250
6,550
78
11
1986
42,650
11,650
32
9
Source:
(DOE 87a)
4-18
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Table 4-10; Imports of Uranium Concentrate for Commercial Uses, 1874-1986 (Short Tons
U3Oa)
Year of
Delivery
Tmnorts
1974
0
1975
700
1976
1,800
1977
2,800
1978
2,600
1979
1,500
1980
1,800
1981
8,300
1982
8,550
1983
4,100
1984
6,250
1985
5,850
1986
6,750
Source: (DOE 87b)
4-19
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Table 4-11: U.S. Commercially-Owned Uranium Inventories as of December 91, 1984, 1985, and
1980 (Short Tons U3Oe Equivalent)
1984
Owner Category Natural
Utilities
Suppliers
TOTAL
48,850
12.000
60,350
Enriched
31,760
_JQS
82,250
1985
Natural Enriched
44,100
mm
55,250
82,450
S3,150
1986
Natural Enriched
41,550
12,400
53,950
30,900
450
31,350
Source: [DOE 87b]
4-20
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Secondary Market Transactions
The secondary market for uranium includes producer-to-producer sales, utility-to-utility sales and
loans, and utility-to-producer sales. The secondary market, by definition, does not increase the
supply of uranium, only the alternatives for purchasing it. As such, secondary transactions can have
a significant impact on the demand for new production and on the year-to-year changes in
inventories. The secondary market has been significant in recent years. During 1986, sales of 6,800
tons of U308 equivalent were made between domestic utilities and suppliers in the secondary market.
4.2.3 Industry Structure and Performance
The number of firms participating in the domestic uranium milling industry declined between 1977
and 1985, but has since increased. In 1977, 26 companies owned active uranium mills. In 1983, the
number had fallen to 11, and in June 1985, there were only two [DOE 87b], In 1987, six companies
operated six mills and by August 1988, only four mills continued to operate. The status of the
industry can also be seen in trends in employment and capital expenditures (Table 4-12). Capital
expenditures in 1986 were $1 million, compared to $72 million in 1981 (1986 dollars) [DOE 87a,
DOE 87b], Employment in 1984 was 513 person-years, compared to 2,367 in 1981 [DOE 87a].
Mining and milling production data for individual companies are collected by DOE but are not
available to the public. However, some data on operating status are published. These are listed, by
firm and mill, in Table 4-13.
A wide variety of companies are represented within the uranium industry. In the industry's early
years, holdings were dominated by independent mining and exploration companies. Since then,
mergers, acquisitions, and the entry of conglomerates have considerably altered industry structure.
During the 1970s, the oil embargo and forecasts of growing demand for nuclear power made entry
into the uranium market attractive to oil companies and utilities. Of the six mills operating in 1987,
three were owned by foreign mining companies, one an American mining company, one by a
subsidiary of an oil company, and another by a subsidiary of a chemical company. These ownership
characteristics influence the current and future financial viability of the industry. The desire of the
parent companies to weather a downturn in the uranium market and to retain an interest in producing
4-21
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Table 4-12: Capital Expenditures, Employment, and Active Mills: Conventional Uranium Milling
Industry,
Capital Expenditures Employment Number of Active Mills
Year Million Constant 1986 8) (Person-Years) At Year-End
1981 72 2,367
1982 12 1,966 14
1983 3 1,518 12
1984 8 987 8
1985 9 514 4
1986 1 513 6
Sources: (DOE 87a, DOE 87b)
4-22
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Table 4-13, Operating status of licensed conventional uranium mi Us as of June, 1989.
June 1989.(a)
Operating
Status(b)
RecI amati on
Status(c)
Standby
Standby
Future
In Progress
Decommission
Oecocmiission
Dec oomi ss i on
Standby
Active
Cover in Place
In Progress
In Progress
In Progress
Future
Decommission
Completed
Active
Decommission
Deconrnission
Future
In Progress
Completed
Active
Standby
Deconrnission
Standby
Future
In Progress
In Progress
Future
Decommission
Standby
In Progress
Future
Standby
Decommission
Decommission
Decommission
Active
Standby
Decommission
Decommission
Future
In Progress
In Progress
In Progress
Future
Future
Cover in Place
Unknown
Decommission
Design Approval
State/Mi 11
Owner
Colorado
Canon City
Uravan
New Mexico
L-Bar
Churchrock
Biuewater
Ambrosia take
Homestake
South Dakota
Edgemont
Texas
Panna Maria
Conquista
Ray Point
Utah
White Mesa
Rio Algom
Moab
Shootaring
Washington
Dawn
Sherwood
Wyomi ng
Lucky He
Split Rock
Umetco
Bear Creek
Shirley Basin
Sweetwater
H ightand
FAP
Petrotomics
Cotter Corp.
Umetco Minerals
BP American
United Nuclear
Anaconda
Kerr-McGee
Homestake
TVA
Chevron
Conoco/pioneer
Exxon
Umetco Minerals
Rio Algom
Atlas
Plateau Resources
Dawn Mining
Western Nuclear
Pathfinder
Western Nuclear
Umetco Minerals
Rocky Mt. Energy
Pathfinder
Minerals Expl,
Exxon
American Nuclear
Corporation
Petrotomics
(a) Data obtained from conversations with cognizant personnel in Agreement States and the NRC,
comments submitted by individual companies and the American Minining Congress during the public
comment period, and site visits. Does not include mills licensed but not constructed.
(b) Active mills are currently processing ore and producing yetlowcake, Standby mills are not
currently processing ore but are capable of restarting. At mills designated by "Decommission", the
mill structure has been or is being dismantled and no future mi I ling will occur.
CO Terms to describe reclamation status are as follows: "Future", impoundment is being maintained
to accept additional tailings and reclamation activivities have not yet started; "Design Approval
Pending", final disposal design has been submitted for regulatory approval and reclamation
activities are underway; "In Progress", active reclamation has begun but final cover is not
completed; Cover in Place", final cover has been completed but final stabilization has not been
completed; and "Completed", disposal and stabilization have been accomplished in accordance with
Umtrca standards.
-------
properties is a function of their perception of the prospects for long-term profitability in domestic
uranium operations. Some firms continue to invest and to acquire properties, while others withdraw
from an extremely soft market. Foreign firms appear to have adopted a longer term viewpoint than
ha ve some of their domestic counterparts. It is likely that the industry will continue to undergo
structural change. This change will depend on domestic and foreign demand, costs of production,
and the industry's ability to compete with lower-priced imports [DOE 87a],
4.2.4 Economic and Financial Characteristics
4.2.4.1 Employment Analysis
Department of Energy estimates of employment in the uranium milling industry from 1984 to 1986
are listed in Table 4-14. Additional detail at the state level was obtained through discussions with
staff of the departments of mining or natural resources in the states with uranium mills. This is
provided in the following paragraphs. Historically, New Mexico and Wyoming have been the nation's
leading producers of uranium and have jointly been responsible for an estimated 70 to 75 percent of
total uranium concentrate production. Following the peak production period of 1981 and 1982, and
since the onset of the production decline in the latter part of 1982, it is estimated that approximately
7000 jobs have been lost in New Mexico as production fell from 253 million tons in 1982 to 36
million in 1984 [NM 85],1
The trend in Wyoming has been similar. In 1980, seven uranium mine-mill complexes and one
uranium mill employed a total of 2451 people. In 1981, employment dropped to 1361 people. In
1984, employment was down to 454 workers [WY 80, 81, and 84],
In Washington, before 1982 there were two mine-mill complexes: Midnight Mines (owned and
operated by Dawn Mining Company) and the Sherwood Mine (owned by Western Nuclear, a
subsidiary of Phelps Dodge Corporation). In 1981, Dawn employed 50 workers, and in 1982 it
employed 42. In 1981, Sherwood employed 45 workers, while in 1982 it employed 14 miners plus
98 maintenance workers. Both mine-mill complexes are currently inactive and unemployment
(estimated at 40 percent from 1982 to 1983) was estimated to be as high as 80 percent [WA 85].
Employment and output estimates by state sources may not agree with those provided by the
U.S. Department of Energy and presented elsewhere in this report, due to differences in data
collection procedures.
4-24
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Table 4-14: Employment in the U.S Uranium Milling Industry by State.
1984
State
Colorado
Wyoming
Arizona, New Mexico,
Texas, Utah, Washington
TOTAL
Person-Years
215
310
462
987
1985
State
Colorado
Wyoming
Arizona
New Mexico
Other
TOTAL
Person-Years
W
128
W
W
w
128
State
Arizona
Other
Total
1986
Person-Years
0
W
W
W = Withheld
Source: (DOE 86, DOE 87b)
4-25
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fn Colorado, there were 508 mineral industry operations in 1980, 100 of which were engaged in the
production of uranium, By 1985, however, there were only two mines or mine/mill complexes:
Centennial and Schwartzwalder, In 1980, the uranium industry employed approximately 1594
individuals [Nugent 80], whereas it is estimated that the two operations now employ about 200 people
[Co 85).
In Texas, there were, until recently, three mills: the Conquista Project (Conoco), Ray Point (Exxon)
and the Panna Maria complex (Chevron), The Conquista complex, it is estimated, employed over 500
people during its peak period from 1979 to 1980, and the Panna Maria complex about 250 people
during its peak period from 1981 to 1983. The Conquista Project and Ray Point have been closed
and are being decommissioned. The Panna Maria was operating at the close of 1987, but at a
considerably reduced rate. Employment there reached a low of seven to eight people in 1985.
Current employment is unknown [TX 85j.
4.2.4.2 Community Impact Analysis
The impact of trends in uranium milling on small communities dependent on uranium milling
facilities tends to vary depending on the location of the mines, the importance of uranium mining
and milling to the state, and the nature of the work force. Texas and Washington serve as interesting
case studies.
In Washington, the uranium facilities are located primarily in the Spokane Indian Reservation. Mining
soon became the main economic activity as the mining companies were under contractual obligation
to draw 51 percent of their labor force from the Indian community. When the two Washington
mine-mill complexes, Midnight Mines and Sherwood Mines, closed in 1983-1984, the unemployment
rate rose to about 80 percent. This is perhaps partly attributable to the absence of any other mining
activity on the reservation which might have absorbed some of the displaced workers. This high
unemployment rate also suggests limited mobility on the part of miners and workers. Thus, in the
case of Washington it would seem that the employment effects were concentrated, and felt largely
by the Indian community which served as the principal source of labor for uranium mining and
milling within the state [WA 85].
4-26
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In Texas, by contrast, the community impacts of the uranium industry are less significant. Most
uranium industry employees were originally farmers and ranchers, maintaining and upgrading their
properties during the lifetime of their mining careers. Moreover, they were mostly a commuting work
force so there was no residual pool of unemployed persons in the vicinity of the mines once the
decline in employment took place in the early 1980s. There were no uranium mining communities
as such in the State of Texas which were dependent on the mining and production of uranium for
their subsistence. Moreover, many workers were absorbed by the then booming petroleum and lignite
industries [TX 85].
In the case of both Colorado and Utah, the ability to absorb unemployed uranium workers is limited.
In Colorado, this has been due to the depressed state of the mining industry in general within the
state [CO 85J. In New Mexico, where uranium mining and milling are considered an important
economic activity, there were areas of concentrated impact - such as Gallup, the Laguna Pueblo area
and the Navajo Indian Reservation, The wide scale reduction in employment observed in recent
years, the reduction in sales and sales tax revenues, the loss of severance payments, a significant
amount of out-migration to Nevada and several other states, and a concomitant reduction in income
tax revenue have combined to make the impact significant and state-wide as opposed to
community-specific [NM 85].
4.2.4.3 Financial Analysis
Selected financial data for the domestic uranium industry for 1982 to 1986 are shown in Table 4-15.
The data cover a subset of firms (the same firms for all years) that represent over 80 percent of the
assets in the industry in each year. The firms included are those for which uranium operations
could be separated from other aspects of the organization's business, and for which an acceptable
level of consistency in financial reporting practices was available for all years. Financial data on the
milling industry alone are not available.
As shown in Table 4-15, net income accruing to the uranium industry was positive in only two years,
1982 and 1983. The returns on assets (net income divided by total assets) in these years were 0.7 and
1.4 percent respectively, and aggregate net earnings totalled $69.8 million. In 1984, 1985, and 1986,
the returns on assets were -10.3, -21.6, and -2.3 percent, and aggregate net losses reached $765.7
million. The loss in 1984 alone was $304.7 million on revenues of $608.9 million. Thus, the
aggregate loss for the five years was $695.9 million. In 1977, 146 firms were involved in domestic
4-27
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Table 4-15: Financial Statistics of the Domestic Uraniua Industry, 1982-1986. (Boilers, Billions)
1982
1983
1984
1985
1986
Incoae Statement
Operating Revenues
1069.5
857.9
608.9
581.5
444.9
Operating Incooe
15.9
77,3
-24.2
-37.2
-1.5
Net Incoae
24.1
45.7
-304.7
-419.4
-41.6
Source and Use of Funds
Net Incoae
24.1
45.7
-304.7
-419.4
-41.6
Depreciation, Depletion, and Amortization
240.1
162.5
117.6
92.1
68.5
Deferred Taxes
11.0
2.1
-28.5
-112.8
-6.7
Other Funds Provided Fro* Operations
65.7
9.4
157.8
207.5
60.5
Disposition of Property, Plant, and Equipment (Book Value)
7,0
30.8
231.7
366.6
25.8
Debt and Equity
343.9
15.2
77.5
125.0
144.6
Other Sources
23.0
151.1
167.1
253.4
174.6
Total Sources
714.8
416.8
418.5
512.4
425.7
Capital Expenditures (Property, Plant, and Equipment)
125.9
49.6
41.5
39.3
21.1
Debt Repayment
154.2
183.6
133.5
278.7
191.9
Other Uses
336.5
150.8
184.1
150.5
204.8
Total Uses
616.8
383.9
359.1
468.4
417.8
Change in Working Capital
98.0
32.9
41.4
43.9
8.1
Balance Sheet
Current Assets (Less Inventory)
428.2
380,8
568.9
472.9
488.1
Inventory
435.0
416.0
430.9
367.8
352.2
Net PP&E
2119.5
1733.2
1507.4
705.8
600.4
Other Honcurrent Assets
575.9
727.3
445.0
397.2
330.9
Total Assets
3S58.5
3257.2
2952.3
1943.7
1771.5
Current Liabilities
278.7
217.8
369.4
318.7
229.3
Deferred liabilities
1533.0
1730.7
1744.1
1016.3
10CS.9
Total Liabilities
1811.8
1948.4
2113.6
1335.0
1238.1
Equity
1746.8
1308.7
838.7
608.6
533.4
Total Liabilities
3558.5
3257.2
2952.3
1943.7
1771.5
Ratios (Percent)
Rates of Return
Net Incooe to Total Assets
0.7
1.4
-10.3
-21.6
-2.3
Net Incoae to Total Equity
1.4
3.5
-36.3
-68.9
-7.8
Net Incoae to Net Investment in Place
1.1
2.1
-17.3
-43.5
-5.2
Fund Flow Measures
Additions to PP&E to Total Sources of Funds
17.6
11.9
10.4
7.7
5.0
Leverage Measures
Deferred Liabilities to Total Equity
87.8
132.2
208.0
167.0
189.1
Deferred Liabilities to Total Assets
43.1
53.1
59.1
52.3
57.0
Liquidity Measures
Current Ratio
3.1
3.7
2.7
2.6
3.7
Liquidity Ratio
1.5
1.7
1.5
1.5
2.1
Source (DOE 87a)
4-28
-------
uranium exploration, 135 in mining and 26 in milling. In contrast, only 31 firms were actively
engaged in exploration, 11 in mining and 5 in milling toward the end of 1986. Of these firms, only
27 percent had positive net income after meeting operating expenses and other obligations such as
payment of taxes and recovery of depletion, depreciation and amortization. Fifty-five percent
reported net losses; the remaining 18 percent either had left the industry or had no data to provide.
Most of the financial improvement in 1986 stemmed from the slowdown or the completion of
writeoffs of discontinued operations, revaluation of assets and abandonments. The domestic uranium
industry is significantly smaller than before, and its financial state will depend on higher product
prices or demand [DOE 87a].
Company-specific information on uranium production, revenues, profits, and plans is provided in
the following paragraphs.
Homestake Mining Company
Homes take Mining Company owns one conventional uranium mine and a 3400 ton per day mill in
Grants, New Mexico. During 1984, production of uranium was reduced to the minimum level at
which satisfactory unit costs could be maintained. Mine production has been confined to one mine
operating on a five-day-week schedule for ten months of the year. Uranium concentrate was also
recovered from solution mining and ion-exchange. In 1986, uranium accounted for 14 percent of
the company's revenues, and 21 percent of operating earnings. The high profitability of the sector
for the year is attributed to existing contracts, expiring in 1987, that provide for sale prices above
current spot prices and production costs. Selected financial statistics are presented in Table 4-16 [AR
84, AR 85, AR 86].
Rio Algom
Rio Algom is a Canadian corporation engaged in the mining of a wide variety of materials, including
copper, steel, and uranium. In 1986, uranium operations accounted for 26 percent of corporate
revenue, but most (89 percent) was from Canadian production. In the United States, the company
owns one uranium mine and a 750 ton per day mill in La Sal, Utah.
4-29
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Table 4-16: Hoaestake Mining Coapany Uraniua Operations, 1982 Operations
1982
1983
1964
1985
1986
Revenues (Billions dollars)
63,70
58.60
57.90
68.20
49.80
Operating Incowe (Millions dollars)
15.60
11.40
19.60
22.80
12.70
Sales of U308 (Billions pounds)
N/A
1.13
1.13
0.94
1.05
Sales Price Per Pound of U308 (a)
46.20
49.76
51.21
49.70
47,50
Depreciation, Depletion, and
Amortization (Millions dollars)
20.00
14.30
4.40
12.50
4.30
Additions to Property, Plant, and
Equipment (Millions dollars)
1.00
0.00
0.70
0.00
0.00
Identifiable Assets (Millions dollar
80.00
73.00
66.90
43.70
24.90
Ca) Prices based on long-tera contracts that were to expire in 1986 and 1987.
N/A - not available
Source: CAR 84b, 85b, 86b)
4-80
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In 1986, the company produced 457 tons of uranium oxide from its Utah mine. The mine operated
at approximately 50 percent of capacity in 1986, while the mill operated at capacity due to a
significant amount of toll milling [AR 86].2 In 1987, the La Sal mill produced about 350 tons of
uranium oxide using both company ore and ore from the Thornberg mine. The mill was placed on
standby in September, because the Lisbon and Thornberg mines* reserves are depleted [EPA 89}.
Selected financial statistics on Rio Algom uranium operations are presented in Table 4-17.
Plateau Resources Limited
Plateau Resources, a wholly owned subsidiary of Consumers Power Co., was organized in 1976 to
acquire, explore, and develop properties for the mining, milling, and sale of uranium. All operations
were suspended in 1984 because of depressed demand and all uranium assets were written down by
$46 million after taxes in 1984 and $21 million in 1985, to an estimated net realizable value of
approximately $34 million. There is no assurance that the amount will ever be realized however. The
company's 800 ton per day mill at Ticaboo, Utah, which was constructed in 1980 and 1981, has never
been active. It does, however, remain on standby and could be activated [AR 84, 85, 86],
Western Nuclear
Western Nuclear, a subsidiary of Phelps Dodge Corporation, owns two mine and mill complexes, one
in Wyoming and one in Washington. The capacities of its mills are 1700 and 2000 tons per day,
respectively. The Wyoming mill has been on standby since the early 1980s, and decommissioning is
anticipated. The Washington complex operated intermittently from 1981 through 1984. In late 1984,
Phelps Dodge wrote off its entire "Energy" operation, of which Western Nuclear was a major part
[AR 84, AR 85].
4.2.5 Industry Forecast and Outlook
This section presents projections of total U.S. utility market requirements, domestic uranium
production, from both conventional and non-conventional sources, imports, employment and
electricity consumption. Developed for a 14-year period (1987-2000), these projections are
considered "near term." A basic assumption of the near term projections is that current market
2 "Toll milling" is the processing of ore from another company's mines on a contract basis.
4-31
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Table 4-1?; Rio Algoa Uranlua Operations, 1981-1986.
(Canadian Dollars, Billions)
1981 1982 1983 1984 1985 1986
Revenues
281.9
281.7
297.6
368.1
368.3
349.2
Operating Incoee
69.2
60.3
76.1
86.9
88.3
77.1
Capital Expenditures
17.3
13.7
87.8
(2.1)
3.8
60.9
Asset*
372.1
427.8
752.9
774
775.4
977.1
Depreciation, Amortization
30.7
28.1
29.9
37.6
36.2
39.5
Tons U308
Total Production 3,900 3,550 3,400 4,111 4,065 4,107
Canadian Production N/A K/A 3,233 3,800 3,700 3,650
U.S. Production N/A N/A 167 311 365 457
Source: Aft 87b
4-32
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conditions, as defined by the Department of Energy's Energy Information Administration (DOE,
EIA), will continue unchanged through the end of this century. This section is based on the
reference case projections in EIA's Domestic Uranium Mining and Milling Industry; 1986 Viability
Assessment [DOE 87a].
4.2.5.1 Projections of Domestic Production
The EIA's Reference case5 forecasts for 1987-2000 are based on the output of EIA's economic model,
Domestic Evaluation of Uranium Resources and Economic Analysis (EUREKA). The EUREKA
model's methodology goes beyond the scope of this study; it is fully described in Appendix C of the
1986 Viability Assessment. The EIA examines future developments in the domestic uranium industry
and in the domestic and international uranium markets under current market conditions and under
certain hypothetical supply disruption scenarios4. The current market conditions are generally the
same as those presented in Sections 4.2.1-4.2.4 of this study and are based on historical trends in the
domestic uranium industry as outlined in both the Viability Assessment and the EIA's Uranium
Industry Annual 1986. In addition to the uranium prices, production and imports as well as the
exploration expenditures, capital expenditures, and employment data developed for inclusion as
"current market conditions," the EIA includes one important assumption: that the Act of Congress
forbidding imports of uranium from South Africa and Namibia will be enforced5. Also taken into
"'Prior to the 1986 Viability Assessment, EIA published two reference cases; a Lower Reference
case and an Upper Reference case, each with a low, a mean, and a high range of projected values.
In 1986, however, only the Lower Reference case was published. It is referred to simply as the
Reference case. As before, low, mean and high projected values were produced by EIA. This study
uses the mean. The Reference case in the 1986 Viability Assessment uses the underlying assumptions
for the Lower Reference case described in Commercial Nuclear Power 1987; Prospects for the United
Slates and the World [DOE 87a].
4These scenarios, the "current disruption status" scenario and the "projected disruption status"
scenario, are used to test the viability of the U.S. uranium industry, to examine the ability of this
industry to respond to an abrogation of various fractions of contracts for uranium imports intended
for domestic end use. Both of these bear only tangentially on this study and will not be discussed
further here.
5"I"he U.S. Congress passed the Comprehensive Anti-Apartheid Act of 1986 on October 2, 1986.
Section 309 of that Act forbade the import into the United States of uranium ore or concentrate of
South African of Namibian origin after January I, 1987. However, natural or enriched uranium
hexafluoride from these countries may be imported, according to a regulation issued by the U.S.
Department of the Treasury on which the U.S. Nuclear Regulatory Commission has concurred
[£PA87b],
4-33
-------
account by DOE are assumptions on future electricity generation, fuel burnup levels, enrichment in
tails assay, and inventory drawdowns.
4.2.5.2 Near-Term Projections
Total domestic production of Us08, from both conventional and non-conventional uranium sources,
for 1980-1986, is shown in tabular form in Table 4-18, along with reference case projections for the
period 1987-2000. Annual domestic production peaked at 21,900 short tons after milling6 in 1980,
and declined to 6,750 short tons in 1986. Production is projected to remain well below the 1980 peak.
For example, EIA has projected domestic UjOg production in 1992 at 6,450 short tons, while output
in the year 2000 is estimated at 7,500 short tons. Annual domestic production from conventional
mining sources (i.e., from milling ore obtained from underground or open-pit mines, which
historically has accounted, on average, for roughly 70 percent of total annual domestic production)
has fallen more steeply: from 85 percent in 1980 to 53 percent in 1985. However, it increased from
its 1985 level of 3,275 short tons to 5,825 short tons in 1986. As was stated in section 4.2.2, this
increase was due to an increase in the U3Og concentration of the ore milled in that year.
Changes in the market, such as the legislative import ban on South Africa and Namibia, could
influence conventional production much more than non-conventional U3Os production, because non-
conventional U30B producers tend to have lower marginal costs of production than do conventional
producers. Therefore, production from non-conventional sources tends to be less affected by
fluctuations in uranium market prices. Wet process phosphoric acid, copper waste dumps, and
bellyrium ores constitute by-product methods of production of U3Og. The second significant son-
conventional source is in situ leaching. By-product and in situ leaching both accounted for 79
percent of the total non-conventional annual production of U3Og in 1986. Other less important
All U308 production data in this chapter is after milling and excludes U30„ which is not
recovered from the ores in milling. In recent years, milling recovery rate has been Between 95-97
percent. In this study, it is assumed to be 95 percent.
4.34
-------
Table 4-18: Annual and Projactad Domestic Production and Import! of Yellow Cake, 1980-2000.
(in thousands of short tons}
Ysar
Total
Production
% Annual
Chang*
CO
Oi
UUliKltKSAItttBIBltBB
1980
21.90
Mft
1981
19.20
-12.3%
1982
13.40
-30.2%
1983
10.60
-20.9%
1984
7.45
-29.7%
1985
5.65
-24.2%
1986
6.75
19.5%
1987
6.50
-3.7%
1988
6.85
5.4%
198S
7.00
2,2%
1990
£.55
-6.4%
1991
6.15
-6.1%
1992
6.45
4.9%
1993
6.90
7.0%
1994
1.20
4.3%
1995
7.20
0.0%
1996
7.45
3.5%
1997
7.50
0.7%
1998
7.45
-0.7%
1999
7.55
1.3%
2000
7.50
-0.7%
mmmmmmmmrnmm
MR«f*naairaBaBBHB
Conventional
Production
1B.9S
15.96
10.41
7.78
4.82
3.03
4.42
4.11
4.39
4.4 B
3.96
3.50
3.73
4.12
4.35
4.29
4.55
4.60
4.5 5
4.65
4.60
% Annual
Change
-15.8%
-34.8%
-25.3%
-38.0%
-37.1%
45.9%
-7.1%
7.0%
1.9%
-11.5%
-11.7%
6.7%
10.3%
5.7%
-1.5%
6.1%
1.1%
-1.1%
2.2%
-1.1%
Percent
Of Total
86.5%
83.1%
77.7%
73.4%
64.7%
53.6%
65.5%
63.2%
64.1%
64.0%
60.5%
56.9%
57.9%
59.7%
60.5%
59.6%
61.1%
61.3%
61.1%
61.6%
61.3%
Hon-Conventlona 1
Production
2.95
3.24
2.99
2. 02
2.63
2.62
2.33
2.39
2.46
2.52
2.59
2.65
2.72
2.78
2.85
2.91
2.90
2.90
2.90
2.90
2.90
% Annual
Changs
9.8%
-7.7%
-5.7%
-6.7%
-0.4%
-11.1%
2.8%
2.7%
2.6%
2.6%
2.5%
2.4%
2.4%
2.3%
2.3%
-0.3%
0.0%
0.0%
o;o%
0.0%
Percent
Of Total
13.5%
16.9%
22.3%
26.6%
35.3%
46.4%
34.5%
36.8%
35.9%
36.0%
39.5%
43.1%
42.1%
40.3%
39.5%
40.4%
38.9%
38.7%
38.9%
38.4%
38.7%
Average Brads of
% Annual
lestic Ore (%)
Import*
Change
lOTtVttarBKBBtKKSSHeBEECttt&SS
0.110
J.f©
_
0.115
3.30
83.3%
0.119
8.55
159.1%
0.128
4.10
-52.0%
0.112
6.25
52.4%
0.161
5.85
-6.4%
0.336
6.75
15.4%
0.284
4.85
-28.1%
0.200
5.20
5.2%
0.200
6.40
25.5%
0.200
7.60
18.7%
0.200
8.70
14.5%
0.200
8.65
-0,6*
0.200
8.60
-0.6%
0.200
8.15
-5.2%
0.200
8.60
5.5%
0.200
9.35
8.7%
0.200
9.75
4.3%
0.200
10.15
4.1%
0.200
10,05
-1.0%
0.200
9.75
-3.0%
Hote*i Total historical and projactad production of U308 are taken from (DOE87a). Data for 1980-1986 are actual,
while data for 1887-2000 ara projection* based on tha man valuaa for the Reference case. Projection* of
conventional production are calculated a* the difference between total 11308 production and non-conventional production, which
ia projected baaed on historical market share, capacity and unofficial EIA estimates.
Actual figure* ar* bol
-------
sources include mine water, and heap leaching, which accounted for the remaining 21 percent of total
annual non-conventional production in 1986.
The Reference case EIA projections of domestic UjOa production through the year 2000 are based
on a unit by unit review of nuclear power plants that are new, operating, under construction, or units
for which orders have been placed and for which licenses are currently being processed. Under EIA's
Reference case, nuclear generating capacity is expected to increase from 94.0 GWe in 1987 to 103.0
GWe in the year 2000 (Table 4-19). Historical and forecast data of total enrichment feed deliveries
(demand), net imports, and total production are graphed in Figure 4-1 [DOE 87a]. Historical data
and reference case projections for both conventional and non-conventional production of domestic
uranium are plotted in Figure 4-2.
4.2.6 Evaluation of Forecasts and Uranium Market Demand
This section compares the El A forecasts for total domestic production of U3Oa to total domestic
uranium resources, and discusses the relationship of the EIA forecasts to total electricity generation.
4-2.6.1 Domestic Uranium Resources
The projection of domestic U3Og production shown in Table 4-18 indicates that a total of a little over
98,000 short tons of U308 will be produced domestically over the next fourteen years. Over this
time period, perhaps 38,400 short tons of U3Ofl will be produced from by-product sources. A
discussion of the potential for by-product technology is presented below, followed by a discussion
of the extent of other domestic U3Og resources.
By-Products
The most significant domestic source of by-product uranium is phosphate mining and processing.
One source [JFA 1986] has estimated that current phosphate by-product production of uranium is
at approximately one-fourth of its capacity. It is likely to remain below its capacity well into the
next century. However, over the full fifteen-year period a substantial amount of U308 is likely to
4-36
-------
FIGURE 4-Is SOURCES OF URANIUM! SUPPLY
W YEM Mi®
e—-B 0 Eh—-i
9%
2QOO
O 0om«flie Bhr«M3U*©t£«M» 4- S>«tH£&*s4£e' X>«sel«jls&<£ <<~ TwSctl ShaypySy
& Ssk&e* osrte
FIGURE 4-2: U.S. URANIUM PRODUCTION
1980-1886 itID PEOreCTIOKS TO VEM ZOOffi
2000
PQI Ccmvm&tiaaMil
H cm —C v ©atii oxMatS
4-37
-------
Table 4-19: Projected Nuclear Power Capacity
(Reference Case}
Year
Nuclear Power Capacity
(SUe)
1987
94.0
1988
96.0
1989
99.6
1990
99.6
1991
101.9
1992
101.9
1993
101.9
1994
101.9
1995
101.9
1996
101.9
1997
101.9
1998
103.2
1999
103.2
2000
103.0
Source: (DOE 1987a:22)
4-38
-------
be obtained from this technology, perhaps as much as 15,000 short tons, in the Reference-case
scenario. In addition, there may be technological innovations which would make it feasible to obtain
U308 from phosphate rock.
Other potential sources of by-product uranium are: copper waste dumps; the red mud obtained when
alumina is removed from bauxite; and the beryllium ores of west-central Utah. A modest amount
of U3Oa is currently obtained from copper produced in Utah and Arizona. DOE estimated, in 1980,
[DOE 80] that 500 to 1000 tons of by-product U3Oa could be obtained annually from copper ores.
Also, DOE estimated that a few hundred short tons per year could be obtained annually from red
mud, and that 17 short tons could be obtained from beryllium ores annually, when an already
developed plan to recover uranium is employed.
Other Domestic Resources
DOE estimates of the total "endowment" of domestic U3Og resources, are shown in Table 4-20. The
"endowment" is defined as all U308 contained in deposits containing at least .01 percent (100 ppm)
of U308. The resource estimates shown are grouped according to resource category, and by "forward
cost of recovery." The three resource categories used by DOE, the primary source for the
information contained in Table 4-20, are those used by the International Atomic Energy Commission,
and the OECD nuclear power agency:
o Reasonably Assured Resources (RAR): The uranium that occurs in
known mineral deposits of such size, grade, and configuration that it
could be recovered within the given cost ranges, with currently proven
technology. Estimates of tonnage and grade are based on specific
sample data and measurements of the deposits and on knowledge of
deposit characteristics. RAR correspond to DOE's Reserve category.
o Estimated Additional Resources (EAR): The uranium in addition to
RAR that is expected to occur, mostly on the basis of direct geological
evidence, in extension of well-explored deposits, little explored
deposits, and undiscovered deposits believed to exist along well-
defined geological trends with known deposits, such that the uranium
can subsequently be recovered within the given cost ranges. Estimates
4-39
-------
Table 4-20: Domestic llranlua Resources Endowment
{thousands of short tens)
Forward Cost of Recovery
(Nominal Dollars)
Reasonably
Assured
Resources
Cumulative
Estimated
Additional
Resources
Cumulative
Speculative
Resources
Cumulative
gaaassBsasagasss
sgBssaaBgsgssgBsasassssag^s^gasgsggasa
$ 0 - $ 30 per pound
I 31 - i 50 per pound
I 51 - $ 100 per pound
161
357
458
161
918
815
SSSCSSSSSSSSKSSS
675
510
710
675
1,185
1,895
515
460
615
515
975
1,590
-------
of tonnage and grade are based 00 available sampling data and on
knowledge of the deposit characteristics, as determined in the best
known parts of the deposit or in similar deposits. EAR corresponds
to DOE's Provable Potential Resource category.
0 Speculative Resources (SR): Uranium in addition to EAR that is
thought to exist, mostly on the basis of indirect evidence and
geological extrapolations, in deposits discoverable with existing
exploration techniques. The locations of deposits in this category can
generally be specified only as being somewhere within given regions
or geological trends. As the term implies, the existence and size of
such deposits are speculative. The estimates in this category are less
reliable than estimates of EAR. SR corresponds to DOE's Possible
Potential Resources plus Speculative Potential Resource categories.
For each forward cost category of undiscovered resources, the estimates of resources at each cost
level are cumulative and include all lower-cost resources within that category.
The "forward cost of recovery" of uranium resources represents estimates of most future costs of
mining, processing, and marketing U3Oa, exclusive of return to capital. These estimates include the
costs of transportation, environment and waste management, construction of new operating units,
and maintenance of ali operating units, future exploration and development costs. Also, appropriate
indirect costs such as those for office overhead, taxes and royalties are included. Table 4-20 presents
estimates of all U308 resources having a "forward cost recovery" of no more than $ 100/lb [DOE 87b],
In addition to estimated U3Os resources in the endowment, there are some large lower grade U3Ofi
resources. The most significant of these are Chattanooga Shale deposits, seawater, and the marine
phosphorites from which U3Og is currently obtained as a by-product of phosphoric acid production.
It is estimated that the Gassaway Member of Chattanooga Shale is 55 to 70 ppm U308 and contains
about 5 million tons of U3Og, as well as larger amounts of vanadium, ammonia, sulfur and oil [MSR
78],
Seawater represents a huge, very low-grade source of uranium, averaging 3 to 4 parts per billion,
and containing perhaps five billion tons of U3Og. Using very optimistic assumptions, the cost of
recovery using current technology has been estimated to be $ 1400/lb of U3Os, albeit, a MIT study
4-41
-------
suggests that improved technology could reduce {he cost to $300/lb, and possibly to $100 or less per
pound fCA 79, RO 79],
If, 38,400 short tons of U3Oa is produced over the next fourteen years as a result of by-product
technology, then given our forecasts (presented earlier for total domestic production) approximately
60,000 short tons of U3Oe would have to be obtained from other domestic sources, A relatively
insignificant quantity of U3Oa could be obtained from existing tailings piles. It has been estimated
[DOE 87a] that 127,000 short tons of U308 could be extracted from mill tailings piles at a forward
cost of $100 or less per pound. Hence, the near term scenario indicates that 60,000 tons will be
obtained from other domestic sources over the next fourteen years.
Excluding speculative resources, Table 4-20 suggests that there are about 675 thousand short tons
U3Oa with a forward cost of recovery of no more than $30 per pound. Of these, 161,000 tons are
included in the Reasonably Assured Resources category. Given the estimate of total domestic
production in Table 4-18 (98,000 tons), it does not appear likely that the price of U3Oa will rise
above $30 per pound.
4.2.6.2 Total Electricity Generation
Corresponding to the production scenario of domestic U3Oa production for the year 2000 are a range
of possible projections of total electricity consumption. One end of this range represents the
situation in which electricity is produced from conventional fission, (i.e., from U-235) and uranium
imports from South Africa and Namibia continue to be restricted. In this situation, perhaps as much
as one quarter of all electricity is derived from conventional fission of domestically produced
uranium. The percentage of electricity may be lower than this as a result of greater use of electricity
from alternative sources, e.g., coal or solar. In constructing our scenarios, we have assumed that
there is no technological innovation which would permit either a cessation or a substantial reduction
in the construction of new uranium-fueled nuclear power plants. Under various assumptions, the
percentage of electricity derived from conventional fission of domestically produced uranium might
be as low as two percent, or lower if current technology changes.
A range of projections of total electricity consumption in the year 2000 is presented in Table 4-21.
The projections correspond to the previously presented Reference case scenario for total domestic
U308 production under the assumptions that 2, 5, 10 and 25 percent of electricity is derived from
4-42
-------
Table 4-21: Projections of Consumption of Electricity from Domestic U-235 In 2000 Under the
Reference Case Scenario. (Billions of KWh, net).
Percent of Electricity Domestic U308 Production Scenario
from Domestic U-235 Reference Case
25 % .932
10 % 2.380
5 % 4.660
2 % 11.650
Approximate Number of
1-GWe Units Supported
by Domestic U-235 40
Notes: These projections assume a fixed level of U3Os production, and varying reliance on total
demand-since lower the reliance the higher the total production scenario. Further, these
projections assume current reactor and enrichment technology
4-43
-------
domestic uranium sources. The projections presume that 31 million KWh (net) of electricity are
generated per ton of UsOg, [DOE 87d] and, therefore, that there is no significant increase in reactor
or enrichment-plant efficiency. If such efficiency improvements occur, the forecasts should be
revised upwards.
The projections shown in Table 4-21 suggest that between 0.932 and 11.650 billion KWh of
electricity will be produced from domestic sources in the year 2000. The more extreme values in this
range, however, represent relatively unlikely combinations of scenarios. These projections assume
a fixed level of U3Ofl production. The most likely projections of consumption of electricity
produced from domestic U-235 in the year 2000 are in the 5 and 10 percent range. These forecasts
indicate that between 2.33 and 4.66 billion KWh of electricity will be consumed in the year 2000.
In addition to the projections of electricity consumption, Table 4-21 also shows the approximate
number of i-GWe nuclear power plant units which would be supported by domestically produced
U-235 under the uranium production scenario, assuming a 66 percent average utilization rate.
Approximately, 40 units would be supported under the Reference case scenario. It should be noted
that a substantial (but undetermined) number of additional units would be supported by imported U-
235.
Projected average annual rates of change in electricity are obtained from the forecasts presented in
Table 4-21, and from DOE's forecast estimate of 2.46 billion KWh for 1987 [DOE 87e], The results
are presented in Table 4-22. The results range from an average decline of 7.2 percent per year to
an average increase of 12.7 percent year. For the most likely scenario, again refer to the values
corresponding to the 10 and 5 percent ranges.
It is also possible to express the rates of change in electricity consumption on a per capita basis, using
any of several projections of population growth. The U.S. Bureau of Census has recently published
data on population forecasts for the U.S. through the year 2080 [BC 84], According to the forecasts,
the U.S. population is assumed to rise from 232 million in 1982 to 267 million in the year 2000. The
average annual increase in population over this time period is .784 percent (though the actual rate of
increase is initially much higher and declines to zero by the end of the period). Using this
population estimate yields the projected average annual rates of change in per capita electricity
consumption shown in Table 4-23. These figures are just .784 percent smaller than the
corresponding figures shown in Table 4-22, and they range from a 7.98 percent annual decline to
4-44
-------
Table 4-22; Average Annual Percentage Change in Electricity Consumption, 1987-2000.
Percent Electricity
from Domestic U-288
25 %
10 %
5 %
2%
Domestic IJgOg Reference Cast
Production Scenario
- 7.2
- 0.5
4.9
12.7
4-45
-------
Table 4-28: Average Annual Percentage Change in Per Capita Electricity
Consumption, 1087-2000.
Percent of Electricity from Domestic U308 Reference Case
Domestic U-235 Production Scenario
25 %
- 7,88
10 %
- 1.16
5 %
4.27
2 %
12.07
4-46
-------
! 1.92 percent annual increase. For the most likely scenario, modest average annual decline of 1.20
percent to an average annual increase of 3.87 percent is expected.
4.2.6.3 Employment Protections
Employment projections and historical data for the uranium milling industry are presented in Table
4-24. Forecasts based upon the Reference case scenario show employment growing slowly from 1992
to 1997 after a stagnant, relatively cyclical period from 1987-1991.
The projections are developed in the following manner. Output per person-year is used as a measure
of productivity. Data for this variable are obtained by dividing total annual uranium concentrate
production from 1967-1986 by each year's total employment in the milling industry, and averaging
the results over the 20-year period. The resulting productivity factor of 7,44 short tons per person-
year is then divided into the relevant years of the production forecasts summarized in Table 4-18.
Average historical productivity is considered suitable for use in projecting future employment
because no technological innovations in uranium processing are expected which might affect mill
productivi ty.
4-3 Current Emissions, Risks, and Control Methods
Uranium mills extract uranium from ores which contain only 0.01 to 0.3 percent U3Og. The mills
are typically located near uranium mines in the western United States in areas of low population
density. Since the uranium ores typically contain a low percentage of uranium, virtually all of the
ore input to the mill remains as waste which is disposed of in the tailings impoundment. The
impoundment areas are formed from dikes built with tailings sands or with soil and rock from the
pond area. As the pond is filled, the dikes are raised with mill tailings sands.
During the operating period of the mill, radon releases from the tailings are required to be
maintained ALARA. The addition of wet tailings provides a water cover which reduces the radon
emissions. The beaches are sprayed to prevent wind erosion and control the radon. At the end of
the operating period, the tailings pond is dewatered, and the spraying of water on the beaches is
discontinued. This is done so that the tailings can dry sufficiently to provide a stable base for the
4-47
-------
Table 4-24: Employment Projections 1987-2000.
Uranium Miffing Industry
(person years) -
»ssss=:ssKSsasBssasai=BSS=:!!E = sSRasssaaffssffisr2=s
Employment
Year
Reference Case
1987
608
1988
635
1989
649
1990
608
1991
570
1992
598
1993
640
1994
668
1995
668
1996
691
1997
696
1998
691
1999
700
2000
696
<4 *"48
-------
heavy equipment needed to regrade the impoundment and place the earthen covers required to meet
the long-term disposal criteria of the UMTRCA standard,
4.3.1 Current Emissions and Estimated Risk Levels
The evaluation of the risks caused by emissions of radon from licensed conventional uranium mills
involves three distinct assessments: the risks that result from the continued use of existing
impoundments at the 11 facilities that are operating or on standby; the risks that will occur once all
existing piles are disposed of; and the risks that will result from future tailings impoundments. As
in the 1986 NESHAPS rulemaking for this source category, the exposures and risks for existing
impoundments are assessed on a site-by-site basis, while risks from future impoundments are
assessed using model impoundments to represent the alternative technologies. The following sections
detail how the radon release rates are developed and identify the sources of the meteorological and
demographic data used in the assessment.
4.3.1.1 Methodology for the Assessment of Risks from Operating and Standby Mills
The overall risk from operating and standby mills includes risks resulting from emissions during
the operating or standby phase, the drying out and disposal phase, and the post-disposal phase. The
following sections detail how the radon release rates were developed for each of these phases to
obtain the source terms for the 11 operating and standby mills. The sources of the meteorological
and demographic data used in the assessment are also discussed.
Development of the Radon Source Terms
The radon source terms are estimated based on the radon flux rate per unit area and the area of the
tailings. This assessment uses the same basic methodology for estimating radon releases and radon
source terms that was used in the 1986 NESHAPS rulemaking [EPA86], For each phase, the
methodology involves two estimates; the radon flux per unit area, and the wet and dry areas of the
tailings pile.
For both the operating or standby phase and the drying and disposal phase, the radon flux per unit
area is calculated on the assumption that 1 pCi/m2/sec radon-222 is emitted per pCi/g radium-226
in the tailings. This number could be lower because of moisture and other factors, but the
4-49
-------
conservative value was used since the piles continue to dry out. In the calculations of the specific
flux rates, the radium concentrations of the tailings used are those reported in previous studies by
the EPA and the NRC [EPA83, NRC80]. For the post-disposal phase, the assumed radon flux per
unit area is the design flux of the approved cover, if known, or the 20 pCi/m2/s (2 pCi/m2/s for
facilities in Colorado) limit established by the regulatory authorities responsible for the
implementation of the UMTRCA disposal standard.
Since water and earth covers effectively attenuate radon during the operating or standby phase, the
calculated radon flux rate is applied only to the dry area of the operable pile and any associated
evaporation ponds. The areas of the wet and dry fractions of the piles have been updated from
information obtained during the public comment period. Where new information was not provided,
areas are estimated from aerial photographs taken of each pile in 1986.
During the drying and disposal phase the calculated radon flux rates are applied to the total areas of
the impoundment and any associated evaporation ponds. For the post-disposal phase, the radon flux
is applied only to the area of the impoundment. The areas of any associated evaporation ponds are
not included since the radium contamination in these ponds is removed and transferred to the main
impoundment prior to stabilization. The total areas of the piles, along with the areas that are
estimated to be covered, ponded, wet, or dry, and the radium concentrations in the tailings are
shown in Table 4-25.
To obtain the radon source term for each facility, it was necessary to define the duration of each of
the three phases. The operating or standby phase is defined to be fifteen years. While it is
recognized that some of the impoundments do not have 15 years of capacity remaining at full
production, the limited processing that is now occurring makes it possible that these impoundments
could remain operational for that length of time. The drying out disposal period is defined to
require five years, based on industry and DOE experience to date. Finally, the post-disposal period
is defined as fifty years. The sum of the emissions estimated for each period was divided by 70 to
obtain the average release per year for input to the assessment codes. The radon source terms
calculated for each pile are given in Table 4-26.
4-50
-------
Table 4-25. Summary of operable tailings impoundment areas and raditJti-226
content at operating and standby mills.
_Surface Area (acres) Average
Ra-226
State/Jn^oundment Total Covered Ponded Met Dry CpCi/g)
Colorado
Canon City - Primary
90
0
88
2
0
400
Canon City - Secondary
40
0
40
0
0
400
Canon City - Total
130
0
128
2
0
400
New Mexico
Ambrosia take - Secondary
121
13
0
0
108
237
Ambrosia Lake - Evap. Ponds
280
0
162
0
118
22
Ambrosia Lake - Total
401
13
162
0
226
87
Homestake - Primary
170
0
100
0
70
300
Homestake - Secondary
40
40
0
0
0
300
Homestake - Total
210
40
100
0
70
300
Texas
Panna Maria
160
80
40
40
0
198
Utah
White Mesa
130
0
55
70
5
981
Rio Algom - Lower
47
0
18
29
0
420
Shootaring
7
0
2
1
4
280
Washington
Sherwood
80
0
0
40
40
200
Wyomi ng
Lucky Mc - Pile 1-3
203
108
35
0
60
220
Lucky Mc - Evap. Ponds
104
0
104
0
0
22
Lucky Mc - Total
307
108
139
0
60
153
Shirley Basin
275
0
179
36
60
208
Sweetwater
37
0
30
0
7
280
Totals
1,784
241
853
218
472
--
4-51
-------
Table 4-26. Sunwary of Radon Source Terms Calculated for Operable Mill
Tailings Impoundments.
Radon Emissions
S t a t e/1 impoundment
Operating/
Standby
Phase
CCf/y)
Drying/
Disposal
Phase
CCi/y)
Post-
Disposal
Phase
CCi/y)
Total
Over All
Phases
(Ci)
Average
Over Alt
Phases
(Ci/y>
Colorado
Canon City
New Mexico
Ambrosia Lake
Homestake
Texas
Panna Maria
Utah
White Mesa
Rio Algcxn
Shootaring
Washington
Sherwood
Wyomi ng
Lucky Mc
Shirley Basin
Sweetwater
O.OE+O
2.5E+3
5.8E+2
0.0E+0
6.36+2
o.oe+o
1.4E+2
1.0E+3
1.2E+3
1.6E+3
2.5E+2
6,66+3
4.4E+3
8.0E+3
4.0E+3
1.6E+4
5.0E+3
2.5E+2
2.0E+3
6.0E+3
7.3E+3
1,3E+5
3.3E+I
9.46+2
5.4E+2
4.1E+2
1.2E+2
2.4E+2
1 .BE+1
2.0E+2
5.2E+2
7.0E+2
9.5E+1
3.5E+4
1.1E+5
7.66+4
4.1E+4
9.7E+4
3.7E+4
4.3E+3
3.6E+4
7.3E+4
9.6E+4
1.5E+4
5.0E+2
1.5E+3
1.1E+3
5.8E+2
1.4E+3
5,36+2
6.1E+1
5.1E+2
1.QE+3
1,46+3
2.2E+2
4-52
-------
Demographic and Meteorological Data
Site-specific meteorological and demographic data are used in assessing the exposures and risks that
result from the release of radon. Demographic data for the nearby individuals (0-5 km) are
developed by visits to each site [PNL84J, The results of these surveys for all 26 licensed facilities are
shown in Table 4-27. The regional population data were generated using the computer code
SECPOP. Meteorological data are from the nearest station. Details of the inputs to the
AlRDOS/DARTAB/RADRISK codes are presented in Volume 2 of this Environmental Impact
Statement.
4.3.1.2 Methodology for the Assessment of Post-Disposal Risks
The UMTRCA rule-making {40 CFR 192) established requirements for the long-term stabilization
and disposal of uranium mill tailings. In addition to protection of groundwater and long-term
isolation to prevent misuse of tailings, the UMTRCA standards require that the tailings cover be
designed to limit the radon flux to a maximum of 20 pCi/m /sec. The NRC and the Agreement
States, which are responsible for implementing the UMTRCA requirements at licensed facilities,
. « .
require licensees to demonstrate that the cover designs will achieve the 20 pCi/m /s at the end of
1,000 years.
Development of Radon Source Terms
As was done for the assessment of Inactive Tailings (see Chapter 3), the post-disposal source terms
for each of the sites was estimated on the basis of the area of the tailings impoundments and the
design flux or measured performance of the cover. Where information on the design flux or cover
performance was unavailable, the UMTRCA limit of 20 pCi/m2/s (2 pCi/m2/s for facilities in
Colorado) was used. Table 4-28 summarizes the areas, radon flux rates through the covers, and
estimated annual emissions for each of the 26 licensed facilities once disposal is complete.
Source of Demographic and Meteorological Data
The demographic and meteorological data used to assess the post-UMTRCA disposal risks were
obtained in the same manner as those used in the assessment risks from operable and standby
impoundments. Table 4-27 summarizes the nearby (0-5 km) population around each of the sites.
4-53
-------
Table 4-27, Estimated Number of Persons Living Within 5 km of the Centroid of
Tailings Impoundments of licensed Hi lis.(a)
Distance (kilometers)
St ate/Impoundment 0.0-0.5 0.5-1.0 1.0-2.0 2.0-3.0 3.0-4,0 4,0-5.0 Total
184
2,76?
2,982 5,933
0
Colorado
Canon City*
Uravan*
New Mexico
L-Bar
Churchrock*
Bluewater*
Ambrosia Lake*
Homestake*
Texas
Panna Mar fa
Conquista
Ray Point
Utah
White Mesa
Rio Algom*
Moab
Shootaring
Washington
Dawn*
Sherwood*
Wyomi ng
Lucky He
Split Rock*
Umetco
Bear Creek
Shirley Basin
Sweetwater
Highland
FAP
Petrotomics
Total
(a) PNL84, except facilities marked with an asterisk were verified and updated
during site visits by SCSA in 1989.
0
0
0
0
0
0
I
0
0
0
0
42
124
166
0
0
18
52
51
150
271
0
0
0
25
220
294
539
0
0
0
0
0
0
0
0
0
187
104
42
57
390
0
12
42
33
81
285
453
0
0
3
12
9
18
42
0
0
21
21
30
58
130
0
0
0
0
0
8
8
0
0
0
0
0
40
40
0
0
9
33
1,094
1,225
2,361
0
0
0
0
0
171
171
0
3
93
157
96
62
411
0
0
0
0
32
17
49
0
0
0
0
0
0
0
0
0
0
30
75
40
145
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
6
0
6
0
0
0
0
0
0
0
0
0
0
0
96
0
96
0
15
373
651
4,641
5,531
11,211
4-54
-------
Table 4-28, Summary of Uranium Mi 11 Tattings Impoundment Areas, Flux
Rates, and Post-UMTRCA Radon-222 Release Rates,
Owner/i mpoundment
Surface
Area
(acres)
Radon Flux
Rate
Radon-222
Release Rate
cci/y)
Colorado
Canon City
Uravan
New Mexico
L-8ar
Churchrock
Bluewater
Ambrosia Lake
Homestake
South Dakota
Edgemont
Texas
Parma Maria
Conquista
Ray Point
Utah
Uhite Mesa
Rio Algom
Hoab
Shootaring
Washington
Dawn
Sherwood
Wyoming
Lucky Mc
Split Rock
umetco
Bear Creek
Shirley Basin
Sweetwater
Highland
FAP
Petrotomics
130
70
128
100
305
368
210
123
160
240
47
130
93
147
7
128
80
220
156
218
90
275
37
200
117
140
2
2
20
20
20
20
20
20
20
20
20
7
20
20
20
10
20
20
20
20
20
20
20
20
20
20
3.36+1
1,86+1
3.3E+2
2.6E+2
7.86+2
9.4E+2
5.4E+2
3,16+2
4.1E+2
6.1E+2
1.2E+2
1.2E+2
2.4E+2
3.8E+2
1.8E+1
1.6E+2
2.0E+2
5.2E+2
4.0E+2
5.6E+2
2.3E+2
7.0E+2
9.5E+1
5.1E+2
3.01+2
3.6E+2
4-55
-------
4,3,J.3 Methodology for the Assessment of Risks from New Impoundments
A number of alternative control technologies are available for use in new tailings impoundments.
Because both timing and disposal method affect the rate of emissions from tailings piles, emissions
are estimated for each alternative work practice, A complete description of the various control
technologies and the estimated emissions and risks from each are discussed below in Section 4.4.3,
Analysis of the Benefits and Costs of Promulgating Future Work Practice Standards.
4.3.1.4 Exposures and Risks from Operating and Standby Mills
Exposures and Risks to Nearby Individuals
The AlRDGS-EPA and DARTAB model codes are used to estimate the increased chance of lung
cancer for individuals living near an operable or standby tailings impoundment and receiving the
maximum exposure assuming no controls. The results of exposure to the average emissions from ail
phases, in terms of radon concentration (pCi/1), exposure (WL), and lifetime fatal cancer risk are
shown in Table 4-29. Table 4-29 also presents the lifetime fatal cancer risks attributable to the 15
year operating or standby period. The lifetime fatal cancer risks from all phases for individuals
residing near these mill sites range from 4E-4 to 5E-6. The lifetime fatal cancer risks to nearby
individuals from the operating or standby periods range from 3B-5 to nil, with the highest risk
estimated at the Homestake mill in New Mexico. The negligible risks during the operating or
standby phase estimated for the Panna Maris, Canon City and La Sal mills result from the fact that
the design of these impoundments allows them to be kept totally wet.
Exposures and Risks to the Regional Population
Collective population risks for the region around the mill site are calculated from the annual
exposure in person-WLM for the population in the assessment area. Collective exposure calculations
expressed in person-WLM are performed for each mill by multiplying the estimated concentration
in each annular sector by the population in that sector. Table 4-30 presents the estimated annual
regional fatal cancers from operable tailings impoundments for all phases of operations and for the
operating or standby phase only.
4-56
-------
TabSe 4-29. Estimated Exposures end Risks to Individuals Living Near Operable
Tailings Impoundments With Ho Contois.
State/KiU
Maximum
Radon Maximum
Concentration Exposure
Maximum
Lifetime
Fatal Cancer
Risk to
Individuals
Xaxiinum
Lifetime
Fatal Cancer
Risk to
Individuals
Distance(a)
(All Phases) (Operations) (meters)
Colorado
Canon City 4.2E-3 5.7E-5 2E-5
New Mexico
Ambrosia Lake 2.7E-3 1.4E-5 2E-5
Homestake 5.8E-2 1.9E-4 3E-4
Texas
Panna Maria 1.0E-1 3.0E-4 4E-4
Utah
White Mesa 2.2E-3 1.5E-5 2E-5
Rio Algoiri 1.5E-3 6.4E-6 9E-6
Shootaring 3.8E-4 3.8E-6 5E-6
Washington
Sherwood 4.8E-3 1.9E-5 3E-5
Wyomi ng
Lucky Mc 1.2E-3 8.4E-6 1E-5
Shirley Basin 2.2E-3 1.6E-5 2E-5
Sweetwater 6.1E-4 4.2E-6 6E-6
0E+0
9E-6
3S-5
OE+O
2E-6
0E+0
3E-6
1E-5
3E-6
5E-6
1S-6
3,500
7,500
1,500
750
25,000
4,500
4,500
3,500
25,000
25,000
25,000
(a) Distance from center of a homogenous circular equivalent impoundment
to the point where the exposures and risks Mere estimated.
4-57
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Table 4-30. Estimated Fatal Cancers per Year In the Regional (O-SQknt)
Populations around Operable Tailings Impoundments.
Fatal Cancers per Year
State Hill All Phases Operating Phase
Colorado
Canon City
6.6E-3
Q.OE+O
New Mexico
Ambrosia take
3.1E-3
1.5E-3
Hanestake
7.7E-3
8.3E-4
Texas
Panna Maria
1.4E-2
0.OE+O
Utah
White Mesa
1.1E-3
1.1E-4
Rio Algom
2.8E-4
0.0E+0
Shootaring
2.2E-5
1.1E-5
Washington
Sherwood
2.9E-3
1.2E-3
Wyoming
Lucky He
6.0E-4
1.6E-4
Shirley Basin
1.8E-3
4.5E-4
Sweetwater
1.2E-4
3.0E-5
Total
3.9E-2
4.3E-3
Table 4-31. Estimated Distribution of the Fatal Cancer Risk to the
Regional (0-80 km) Populations from Operable Uranium Mill
Tai Lings Piles.
Risk Interval Number of Persons Deaths/y
1E-1 to 1E+0
0
0
1E-2 to 1E-1
0
0
1E-3 to 1E-2
0
0
1E-4 to 1E-3
230
6E-4
1E-5 to 1E-4
31,000
9E-3
1E-6 to 1E-5
1,000,000
2E-2
« 1E»6
850,000
5E-3
Totals 1,900,000 4E-2
4-58
-------
The estimates indicate that these operable impoundments cause 4E-2 deaths/year (4 deaths in 100
years) in the regional (0-80 km) populations in all phases. The emissions from the operating or
standby period are estimated to cause 4E-3 deaths/year in the regional population; approximately 10
percent of the risk from all phases of operations.
Distribution of the Fatal Cancer Risk
The frequency distribution of the estimated lifetime fatal cancer risk from all licensed uranium mill
tailings under all dry conditions is presented in Table 4-31, This distribution is developed by
summing the distributions projected for each of the 11 facilities. The distribution does not account
for overlap in the populations exposed to radionuclides released from more than a single mill. Given
the remote locations of these facilities and the relatively large distances between mills, this
simplification does not significantly understate the lifetime fatal cancer risk to any individual.
4.3.1,5 Post Disposal Exposures and Risks
The exposures and risks that will remain once the impoundments at these 26 licensed sites are
disposed of are estimated for the existing UMTRCA disposal design standard of 20 pCi/m2/s and
for alternative fluxes of 6 and 2 pCi/mz/s. As was done for inactive tailings (see Chapter 3), the
source terms for each site were calculated based on the lower of the design {or measured flux rate)
or the applicable flux standard, and the areas of the impoundments. The estimates for all three
alternatives reflect the current demography around these sites.
Exposures and Risks under the UMTRCA Standard
Once all the tailings piles are stabilized and disposed of in accordance with the UMTRCA disposal
standard, the radon-222 emission rates will all be at or below 20/pCi/m2/s. Estimates of the post-
UMTRCA disposal risks to the nearby population are given for the design flux and for alternative
fluxes of 6 and 2 pCi/m2/sec in Table 4-32. Risks to the nearby populations and the estimated
distribution of fatal cancer risks are presented for each alternative flux standard in Table 4-33 and
Table 4-34, respectively.
4-59
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Table 4-32. Estimated Exposures and Risks to Nearby Populations Assuming Alternative Flux Rates (a).
Design F
lux
6 pCi/m2/s L irnit
2 pCi/m2/s
Limit
Max i (mm
Maximum
Maximum
Radon
Maximum
Maximum Lifetime
Radon
Maximum
Maximum Li fetime
Radon
Maximum
Maxim
1
•*»
§
State/Site
Distance (b)
Concentration Exposure
fatal Cancer Risk
Concentration Exposure
Fatal Cancer Risk
Concentration Exposure
fatal
Cancer Risk
(meters)
CpCi/l>
(WL)
To Individual
(pCi/l)
1
Colorado
Canon City
3,500
2.86+04
1.1E-06
2.06-06
2,86+04
1.1E-06
2.06-06
2.86*04
1.IE-06
2.Of -06
Uravan
7,500
1.3E-04
6.4E+07
9.06-07
1.3E-04
6.4E+07
9.0E-07
1.3E-04
6.46*07
9.06-07
New Mexico
l-8ar
3,500
6.1E-03
2.4E-05
3.0E-05
1.8E-03
7.26-06
1.0E-05
6.1E-04
2.4E-06
3.Of - 06
Churchrocfc
1,500
1.2E-02
4.1E-05
6.0E-05
3.6E-03
1.2E-05
2.0E-05
1.26-03
4.16-06
6.06-06
Bluewater
3,500
1.1E-02
4.4E-05
6.0E-05
3.3E-03
1.3E-05
2.0E-05
1.16-03
4.46-06
6.06-36
Ambrosia Lake
7,500
2.3E-03
1.26-05
2.0E-05
6.9E-03
3.56-06
5.06-06
2.36-04
1.26-06
2.06 06
Homestake
1,500
2.9E-02
9.5E-05
1.0E-04
8.5E-03
2.8E-05
4.06-05
2,76-03
9.56-06
1.06-05
South Dakota
Edgemorst
3,500
2.6E-03
1.0E-05
1.0E-05
7.96-04
3.2E-06
4.06-06
2.66-04
1.06-06
1.06 06
Texas
Parma Maria
750
7.1E-02
2.16-04
3.06-04,
2.1E-02
6.3E-05
9.0E-05
7.1E-03
2.1E-05
3.06-05
Conquista
1,500
1.26-02
3.9E-05
5.0E-05
3.5E-03
1.16-05
2.0E-05
1.26-05
3.96-06
5.06-06
Ray Point
2,500
3.1E-Q3
1.1E-05
2,06-05
9.2E-04
3.46-06
5.06-06
3.1E-04
1.16-06
2.06-06
Utah
White Nesa
25,000
1.96-04
1.3E-06
2.0E-06
1.6E-04
1.16-06
1.0E-06
5.1E-05
3.&E-07
5.06-07
Rio Algom
4,500
1.3E-03
5.7E-06
8.06-06
3.9E-04
1.7E-06
2.0E-06
1.3E-04
5.7E-07
8.06 0?
Moab
2,500
1.6E-Q2
5.96-05
8.0E-05
4.7E-03
1.7E-05
2.06-05
1.6E-03
5.96-06
8.06-06
Shootaring
4,500
2.66-04
1.1E-06
2.06-06
7.86-05
3.36-07
5.06-07
2.6E-05
1.1E-07
2.06-07
Washington
Dawn
750
1.2E-02
3.7E-05
5.0E-05
7.6E-03
2.36-05
3.0E-05
2.66-03
7.6E-Q6
1.06-05
Sherwood
3,500
1.91-03
7.4E-0A
1.06-05
5.76-04
2.3E-06
3.06-06
1.9E-04
7.4E-07
1.06-06
Wyoming
Lucky Mc
25,000
6.36-04
4.4E-06
6.0E-06
1.9E-04
1.JE-06
2.0E-06
6.3E-05
4.4E-07
6.06-07
Split Rock
2,500
8.46-03
3.1E-05
4.0E-05
2.5E-03
9.3E-06
1.0E-05
8.4E-04
3.1E-06
4.Of-06
timet co
25,000
6.9E-04
4.76-06
6.06-06
2.1E-04
1.4E-06
2.06-06
6.BE-05
4.7E-07
6.06-0?
Bear Creek
15,000
2.86-04
1.86-06
2.0E-06
8.4E-05
5.5E-07
7.06-07
2.86-05
1.86-07
2.06 07
Shirley Basin
25,000
1.1E-03
7.8E-06
1.06-05
3.3E-04
2.3E-06
3.0E-06
1.16-04
7.86-07
1.06-06
Sweetwater
25,000
2.66-04
1.86-06
2.0E-06
7.76-05
5.4E-07
7.0E-07
2.66-05
1.86-07
2.06-07
Highland
15,000
7.9E-04
5.1E-06
7.0E-06
2.36-04
1.5E-06
2.0E-06
7.96-05
5.16-07
7.06-0/
FAP
15,000
4.16-04
2.7E-06
4.06-06
1.2E-04
8.16:07
1.06-06
4.16-05
2.71-07
4.06-07
Petrotomics
3,500
3.9E-03
1.66-05
2.0E-05
1.26-03
4.9E-06
7.06-06
3.96-04
1.66-06
2.06-06
{«) Exposures and risks calculated based on lower of the given flux limit and the design flu*.
(b) Distance front center of a homogenous circular equivalent impoundment to the point where the exposures and risks were estimated.
-------
Table 4-33. Estimated Fatal Cancers per Year in the Regional (0-80 km) Populations
Assuming Alternative Radon Flux Rates (a).
Design flux
6 pCi/m2/s
2 pC1/m2/s
State/Site
fatal Cancers
per Year
Fatal Cancers
per Tear
Fatal Cancers
per Year
Colorado
Carson City
Uravan
New Mexico
l-Bar
Churchrock
6luewater
Ambrosia lake
Homestake
South Dakota
Edgemont
Texas
Panna Maria
Conquista
Ray Point
Utah
Whi te Mesa
Rio Algoro
Moab
Shootari ng
Washington
Dawn
Sherwood
Wyoming
lucky He
Split Rock
Umetco
Sear Creek
Shirley Basin
Sweetwater
Highland
f AP
Pet rotomi cs
4.3E-Q4
4.2E-05
4.2E-Q3
1.5E-03
4.3E-03
2.7E-03
3.8E-03
3.7E-04
1.06-02
1.7E-02
5.2E-04
9.1E-05
2.5E-04
1.3E-03
6.5E-06
1.3E-03
1 .IE-03
3.1E-04
3.2E-04
3.3E-04
2.8E-04
9.2E-04
5.3E-05
6.8E-04
1.9E-04
4.5E-04
4.3E-04
4.2E-05
1.2E-03
4.4E-04
1.3E-03
8.0E-04
1.1E-03
1.1E-04
3.0E-03
4.9E-03
1.7E-04
7.6E-05
7.6E-05
3.8E-04
2.0E-06
8.16-04
3.5E-04
1.06-04
9.7E-Q5
1.0E-04
8.41-OS
2.8E-04
1.6E-05
2.0E-04
5.8E-05
1,46-04
4.3E-04
4.2E-05
4.2E-04
1.56-04
4.3E-Q4
2.7E-04
3.8E-04
3.7E-05
1.0E-03
1.7E-03
5.2E-05
2.5E-05
2.5E-05
1.3E-04
6.5E-07
2.7E-04
1.1E-04
3.1E-05
3.2E-05
3.3E-05
2.8E-05
9.2E-05
5.3E-05
6.8E-05
1.9E-05
4.5E-05
Total
5.2E-02
1.6E-02
5.8E-03
(a) Fatal cancers per year art calculated based on the loner of the given flux limit
and the design flux.
4-61
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Table 4-33. Estimated Fatal Cancers per Year in the Regional (0-80 km) Populations
Assuming Alternative Radon Flux Rates {ah
Design flux
6 pCi/m2/s
2 pCi/m2/s
State/Si te
Fatal Cancers
per Year
Fatal Cancers
per Year
Fatal Cancers
per Year
Colorado
Canon City
Uravan
New Mexico
L-Bar
Churchrock
Bluewater
Ambrosia Lake
Horaestake
South Dakota
Edgemont
Texas
Par.na Maria
Conquista
Ray Point
Utah
White Mesa
Rio Algom
Hoab
Shootaring
Washington
Dawn
Sherwood
Wyoming
lucky He
Split Rock
Umetco
Bear Creek
Shirley Basin
Sweetwater
H i ghland
FAR
Petrotomics
4.3E-04
4.2E-05
4.21-03
1.5E-03
4.36-03
2.76-03
3.8E-03
3.76-04
1.0E-02
1.7E-02
5.2E-04
9.16-05
2.5E-04
1.3E-03
6.5E-06
1.36-03
1.IE-03
3,16-04
3.2E-04
3.3E-04
2.8E-Q4
9.2E-04
5.36-05
6.8E. - 04
1.96-04
4.56-04
4.3E-04
4.2E-05
1.2E-03
4.4E-04
1,31-03
8.0E-04
1.1E-03
1.16-04
3.0E-03
4.9E-03
1.7E-04
7.6E-0S
7.6E-05
3.8E-04
2.06-06
8.1E-04
3.5E-04
1.06-04
9.7E-05
1.0E-04
8.4E-05
2.8E-04
1,61-05
2.06-04
S.86-05
1.4E-04
4.3E-04
4.2E-05
4.2E-04
1.5E-04
4.36-04
2.76-04
3.8E-04
3.76-05
1.0E-03
1.7E-03
5.2E-05
2.5E-05
2.5E-05
1.3E-04
6.5E-07
2.7E-04
1.1E-04
3.11-05
3.2E-05
3.3E-05
2.8E-05
9.2E-05
5.3E-05
6.8E-05
1.96-05
4.56-05
Total
5.26-02
1.6E-02
5.8E-03
(a) Fatal cancers per year are calculated based on the lower of the given flux limit
and the design flux.
4-61
-------
The estimates show that for nearby individuals the maximum lifetime fatal cancer risk will range
from 3E-4 to 9E-7 once disposal activities are completed. The number of deaths/year that will
occur in the regional populations around these 26 sites is estimated to be 5E-2 assuming the design
flux.
Exposures and Risks under Alternative Disposal Standards
As shown in Tables 4-32 through 4-34, at 6 pCi/mz/s the maximum individual lifetime fatal cancer
risk is 9E-05 at the Panna Maria site, a reduction from 3E-04 under the UMTRCA disposal
standard. The estimated deaths per year are reduced from 5E-02 to 2E-02. Similarly, at 2 pCi/m2/s,
the maximum individual risk is reduced by a factor of three to 3E-05, and the deaths/year from all
26 sites is reduced to 6E-3.
4.3.2 Technologies for Long-term Post-disposai Emission Control
Previous studies have examined the feasibility, effectiveness, and cost associated with various options
for controlling releases of radioactive materials from uranium mill tailings [NRC80, EPA82, EPA83,
EPA86], These studies have concluded that long-term stabilization and control is required to protect
the public from the hazards associated with these tailings. The standards for long term disposal
established for these sites under UMTRCA, require controls that prevent misuse of the tailings,
protect water resources, and limit releases of radon-222 to the air. The UMTRCA standard
established a design standard to limit long-term radon releases to an average flux no greater than 20
pCi/m2/sec.
Both active and passive controls are available to reduce radon-222 emissions from tailings. Active
controls require that some institution, usually a government agency, bear the responsibility for
continuing oversight of the piles, and making repairs to the control system when needed. Fencing,
warning signs, periodic inspections and repairs, and restrictions on land use are measures that may
be used by the oversight agency. Passive controls, on the other hand, are measures of sufficient
permanence to require little or no active intervention. Passive controls include measures such as
thick earth or rock covers, barriers (dikes) to protect against floods, burial below grade, and moving
piles out of flood prone areas, or away from population centers. Of the two methods, active or
institutional controls are not preferred for long term stabilization of radon-222 emissions, since
institutional performance of oversight duties over a substantial period of time is not reliable.
4-63
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Previous studies (see above) have identified a number of options to provide long-term control of
radon-222 emissions from the tailings. These include earthen or synthetic covers, extraction of
radium from the tailings, chemical fixation, and sintering. These long-term control options are
discussed in detail in Volume 2 of this Environmental Impact Statement.
In comparison to other control technologies earth covers have been shown to be cost-effective
[NRC80J. Apart from cost considerations, there are other benefits that accrue by using earth covers
as a method to control radon-222 emissions. For example, synthetic covers, such as plastic sheets,
do not reduce gamma radiations. However, earth covers that are thick enough to reduce radon-222
emissions will reduce gamma radiation to insignificant levels. Further, chemical and physical stresses
over a substantial period of time destabilize synthetic covers, while earthen covers are stable over the
long run provided the erosion caused by rain and wind is contained with vegetation and rock covers,
and appropriate precautions are taken against natural catastrophes, e.g., floods and earthquakes.
Earthen covers also reduce the likelihood of contaminating ground water that result from either
storing radioactive materials in underground mines, (underground mines are typically located under
the water table) or by using the leaching process to extract radioactive and non-radioactive
contaminants from mill tailings. Moreover, although underground mine disposal is an effective
method to protect against degradation and intrusion by man, it nevertheless incurs a social cost. For
example, storing tailings in underground mines eliminates the future development of the mines'
residual resources. Again, earthen covers with proper vegetation and rock covers can protect against
human intrusion, without incurring such social costs.
Finally, earth covers provide more effective long term stabilization than either water or soil cement
covers. Albeit, soil cement covers are comparable to earthen covers in terms of cost effectiveness,
their long term performance is as yet unknown. Water covers, on the other hand, do not provide the
long term stability required for the time periods required, which are at least 1000 years. Moreover,
earth covers are more effective stabilizers than water spraying control technology in arid regions.
Covering the dried tailings with dirt is an effective method for reducing radon-222 emissions and
is already in use at inactive tailings impoundments. The depth of soil required for a given amount
of control varies with the type of earth and radon-222 exhalation rate.
4-64
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Earth covers decrease radon-222 emissions by retaining radon-222 released from the tailings long
enough so that a significant portion will decay in the cover, A rapid decrease in radon-222 emissions
is initially achieved by applying almost any type of earth. The high-moisture content earths provide
greater radon-222 emission reduction because of their smaller diffusion coefficient.
In practice, earthen cover designs must take into account uncertainties in the measured values of the
specific cover materials used, the tailings to be covered, and predicted long-term values of
equilibrium moisture content for the specific location. The uncertainty in predicting reductions in
radon-222 flux increases rapidly as the required radon-222 emission limit is reduced.
The cost of adding earth covers varies widely with location of the tailings impoundment, its layout,
availability of earth, the topography of the disposal site, its surroundings, and hauling distance.
Another factor affecting costs of cover material is its ease of excavation. In general, the more
difficult the excavation, the more elaborate and expensive the equipment and the higher the cost.
The availability of materials such as gravel, dirt, and clay will also affect costs. If the necessary
materials are not available locally they must be purchased and/or hauled and costs could increase
significantly.
4.4 Analysis of Benefits and Costs
This section presents the benefits and costs of three separate decisions that may be addressed in
promulgating the new Clean Air Act standards for release of radionuclides from licensed uranium
mill tailings piles. The first decision concerns the limit on allowable radon-222 emissions after
closure. Options that are evaluated include reducing radon-222 emissions from the 20 pCi/m2/sec
limit established under UMTRCA to 6 pCi/m2/sec and 2 pCi/m2/'sec.
The second decision investigates the means by which the emissions from active mills can be reduced
to the 20 pCi/m2/sec limit established under UMTRCA while operations continue. This can be
accomplished through the application of earth and water covers to portions of the dry areas of the
piles in order to reduce average emissions for the entire site to the 20 pCi/m2/sec limit.
While the first two decisions are focused on existing piles, the third is concerned with future tailings
impoundments. Here alternative work practices for the control of radon emissions from operating
4-65
-------
mills in the future are evaluated. Options that are investigated include the replacement of the
traditional single cell impoundment with phased and continuous disposal impoundments.
This analysis assumes that UMTRCA is in place and that all controls required under UMTRCA will
be met regardless of any provisions resulting from this reconsideration of the CAA standards, The
beginning point of this analysis (i.e. the baseline) therefore assumes that all controls required by
UMTRCA are met, specifically that radon emission levels will be limited to 20 pCi/m2/sec and that
measures will be undertaken to achieve the long-run stability required by the UMTRCA rules.
Benefits are measured as reductions in the estimates of committed cancers resulting from lower
allowable emissions. Results are presented in terms of both total benefits and average annual
benefits. For the calculation of total benefits a 100-year time period is assumed.
All costs are measured in 1988 dollars and represent the cost of both the disposal and long-term
stabilization of the tailings. Cost estimates are calculated assuming no remedial actions have taken
place. The costs of meeting the alternative standards are the incremental costs from the baseline (20
p •)
pCi/m /sec) to the 6 or 2 pCi./m /sec alternative. Results are presented in net present value and
annualized cost, and are estimated using real interest rates of zero, one percent, five percent and ten
percent. As with benefits, a 100-year time period is assumed.
4,4.1 Benefits and Costs of Reducing Post Closure Emissions from 20 nCi/m^/sec
This section presents the benefits and costs of reducing the allowable radon-222 emissions from the
maximum limit of 20 pCi/m2/sec established under the UMTRCA standard. Options which are
evaluated include lowering allowable radon emissions to a maximum of 6 pCi/m2/sec or a maximum
of 2 pCi/m2/sec.
Although existing impoundments may be in use or on standby with additional available capacity, the
control options evaluated in this analysis are based on the simplifying assumption that operations
have ceased, that the tailings are sufficiently dry to allow the use of heavy equipment, and that the
piles have their current dimensions.
4.4.1.1 Benefits of Reducing the Allowable Limits
It is assumed that reductions in the radon flux rate provided by increasing the depth of cover will
4-66
-------
yield proportional reductions in committed cancers. The resulting estimates of committed cancers
per year on a pile-by-pile basis are presented above for the 20, 6 and 2 pCi/m2/sec options in Table
4-35.
Table 4-35 summarizes the estimates of risk and reduction of risk (committed cancers) for the
various regulatory options. The table presents these estimates for the 100 year period as well as
annual averages. Over the 100 year time frame the 6 pCi/m2/sec option lowers local and regional
risks by 3.6 committed cancers. The incremental benefit of lowering the allowable flux rate from
6 pCi/m2/sec to 2 pCi/m2/sec is estimated as 1,0 committed cancer.
4.4.1.2 Costs of Reducing the Allowable Limits
For reasons described above, the supplemental control selected for long-term radon-222 control at
existing tailings impoundments is the earth cover control option. The thickness of cover required to
achieve a given radon flux is a function of the initial radon flux from the pile. Five basic steps or
operations are required to implement the supplemental controls for existing tailings piles. These
include regrading slopes, procurement and placing of the dirt cover, placing gravel on the pile tops,
placing of rip-rap on the pile sides, and reclamation of the borrow pits. The estimation of earth
cover thicknesses and the costs for the five operations are described in detail in Appendix B of
Volume 2 of this Environmental Impact Statement.
In order to properly reflect general industry overhead and costs, an overhead cost factor of 1.07 is
used to adjust the cost of earth cover described above, (see Appendix B, Volume 2 for a discussion
of cost factors). Estimates of costs, with and without the overhead cost factor, are presented for
each pile for the 20, 6 and 2 pC,i/m2/sec options in Tables 4-36, 4-37, and 4-38, respectively.
Achieving the 20 pCi/m2/sec option is estimated to cost between $560 to $599 million. In contrast,
reaching the 6 pCi/m2/sec option is estimated to cost from $728 to $779 million while compliance
with the 2 pCi/m2/sec option would entail costs estimated to reach between $882 to $943 million.
Table 4-39 provides the incremental present value costs for the two radon fluxes and added costs
for lowering the allowable flux. Estimates for each of the four real interest rates are included
assuming an overhead cost factor of 1.07, Reducing the allowable flux rate to 6 pCi/m2/sec will
entail added present value costs of between $113 and $180 million depending on assumptions as to
real interest rates, while attainment of a 2 pCi/m2/sec flux rate would entail added costs of $216 to
4-67
-------
Tabic 4-35; Total and Annualiied Risk and Reduction of Risk (Commltted Cancers over 100 years)
of Lowering the Allowable Flux limit to 6 and 2 pCi/m2/sec,
!=====
Risk
20 pdCi/m2/sec
Baseline
Risk
6 pCi/m2/sec
Opt i on
Risk
Reduction from
Risk 20 pCi/m2/sec
Baseline
2 pCi/m2/sec
Opt i on
5.20
1.60
Risk
0.S8
Risk Risk
Reduction from Reduction from
20 pCi/m2/sec 6 pCi/m2/sec
Baseline Baseline
Cancers avoided
over 100 years;
3,60
4.62
1.02
Risk
0.052
0.016
0.0058
Annual cancers
avoi ded:
0.036
0.046
0.010
;;s;:s:5=sss = s:: = s2s== ==ss3;:::ssas2s;=s;=ss;sssrs = s22sssssisa
4-68
-------
Table 4-36: Costs of Achieving the 20 pCi/mZ/sec Option for lieeiTsed Hills (1988 $, Hi 11 ions)
-------
Table 4-39: Incremental Present Value Costs of lowering the Allowable
Limit to 6 pCi/ni2/sec and 2 pCi/m2/sec at Licensed Hills.
(1988 S, Millions)
0 % Real Interest Rate
1 X Real Interest Rate
5 % Real Interest Rate
10 % Real Interest Rate
6 pCi/m2/sec
Opt i on
2 pCi/ufi/set
Option
Incremental Incremental Incremental
Cost From Cost From Cost From
20 pCi/m2/sec 20 pCi/m2/sec 6 pCi/m2/sec
Baseline Baseline Option
$180.28
$171.55
$141.59
$112.96
$344.79
$328.09
$270.80
$216.04
$164.51
$156.54
$129.20
$103.08
4-72
-------
Table 4-38: Costs of Achieving the 2 pCi/m2/sec Option for Licensed Hills (1988 S, Millions} (a).
Excavate
Regrade
Dirt
Apply
Apply
Reclaim
Total Inc.
Mi tl/Pile
Evap. Ponds
SI opes
Cover
R i prap
Gravel
Borrow Pits
Total
O&P S 7%
Canon City
Primary
0.00
0.78
16.31
1.69
0.83
0.80
20.40
21.82
Secondary
0.00
0.23
7.25
0.75
0.37
0.35
8.95
9.58
Uravan
0.00
0.53
13
12
1.31
0.65
0.64
16.25
17.39
L Bar
0.00
1.31
24
17
2.40
1.18
1.18
30.24
32.36
Churchrock
0.00
0.91
17.02
1.87
0.92
0.83
21.55
23.06
Bluewater
0.00
4.84
54
45
5.71
2.82
2.66
70.47
75.41
Ambrosia Lake
Primary
0.00
3.52
46
69
4.63
2.28
2.28
59.40
63.56
Secondary
0.00
1.21
19
76
2.27
1.12
0.96
25.32
27.09
Lined Ponds
8.90
0.00
0
00
0.00
0.00
0.00
8.90
9.53
Untined Pone
4.20
0.00
0
00
0.00
o.oo
0.00
4.20
4.49
Homestake
Primary
0.00
2,01
29
13
3.18
1.57
1.42
37.32
39.93
Secondary
0.00
0.23
6
85
0.75
0.37
0.33
8.54
9.13
Edgemont
0.00
1.24
23
70
2.30
1.14
1.16
29.54
31.60
Panna Maria
0.00
1.84
25
14
3.00
1.48
1.23
32.68
34.97
Conqui sta
0.00
3.38
38
73
4.50
2.22
1.89
50.71
54.25
Ray Point
0.00
0.29
8
94
0.88
0.43
0.44
10.98
11.75
White Mesa
0,00
1.35
27
54
2.43
1.20
1.34
33.87
36.24
Rio Algorn
Upper
0.00
0.28
8
41
0.86
0.43
0.41
10.39
11.12
Lower
0.00
0.29
8
59
0.88
0.43
0.42
10.62
11.36
Moab
0.00
1.62
28
14
2.75
1.36
1.37
35.25
37.71
Shootari ng
0.00
0.02
1
18
0.13
0.06
0.06
1.45
1.56
Dawn
0.00
1.31
20
96
2.40
1.18
1.02
26.87
28.76
Sherwood
0.00
0.65
12
60
1.50
0.74
0.61
16.10
17.23
Lucky Mc
Piles 1-3
0.00
2.63
32
63
3.80
1.88
1.59
42.53
45.50
Evap. Ponds
3.31
0.00
0
00
0.00
0.00
0.00
3.31
3.54
Split Rock
0.00
1.77
20
87
2.92
1.44
1.02
28.02
29.98
UMETCO GH
0.00
2.92
38
80
4.08
2.02
1.89
49,71
53.19
Bear Creek
0.00
0.78
11
54
1.69
0.83
0.56
15.40
16.47
Shirley Basin
0.00
4.14
43
68
5.15
2.54
2.13
57.64
61.68
Sweetwater
0.00
0.20
6
25
0.69
0.34
0.30
7.80
8.34
Highland
0.00
2.57
37
04
3.75
1.85
1.81
47.01
50.30
FAP
0.00
1.15
21
39
2.19
1.08
1.04
26.86
28.74
Petrotomics
0.00
1.50
27
06
2.62
1.29
1.32
33.80
36.17
TotaIs
16.41
45.49
677.94
73.09
36.09
33.07
882.07
943.82
(a) Costs are calculated for the lower of the given flux rate or the design flux.
4-71
-------
$345 million. The added costs of reducing the allowable limit from 6 pCi/m2/sec to 2 pCi/m2/sec
ranges between $103 million and $165 million.
Table 4-40 provides similar estimates to those given in Table 4-39 except the values in 4-40 are
presented on an annualized cost basis. For the 6 pCi/m2/sec option, added costs on an annualized
basis range from $9 to $13 million depending on discount rate assumptions. For the 2 pCi/m2/sec
option, added costs vary from $17 to $25 million. The added annualized cost of reducing the
allowable limit from 6 pCi/m2/sec to 2 pCi/m2/sec ranges between $8 to $12 million.
4.4.2 Benefits and Costs of Reducing Allowable Emissions During Operation
This section presents the benefits and costs of reducing radon-222 emissions to the 20 pCi/m2/sec
UMTRCA limit without curtailing the operation of the tailings impoundments. As in the preceding
analysis, benefits are measured in terms of maximum exposure and maximum lifetime fatal cancer
risks both to nearby and regional (0-S0km) populations.
Costs are measured in nominal 1988 dollars, and represent the incremental change in costs associated
with the cost of water and earth cover needed to achieve the 20 pCi/m2/sec standard. Results are
given using net present values, and are also annualized using real rates of interest of 0, 1,5 and 10
percent. A 100-year time period is also used in generating these estimates.
4.4.2.1 Methods of Reducing Average Emissions to 20 pCi/m2/sec
In this analysis, it is assumed that average radon emissions can be reduced through the saturation of
some portion of the dry areas of the tailings piles without interfering with the operation of the mills.
The area that must be saturated depends upon the proportion of the pile that is currently dry, and
thus currently emitting radon, and the average radium content of the pile. In cases where the tailings
pile is unlined, it is assumed that a dirt cover is applied before the area is saturated, to protect
groundwater from contamination. A dirt cover that would reduce emissions to 20 pCi/m /sec is
considered sufficient to prevent the contamination of ground water once the area is saturated. In
instances where piles are lined, the application of earth cover is not necessary as the liner will protect
the ground water from contamination.
4-73
-------
Table 4-40; incremental Annualized Costs of Lowering the Allowable
Limit to 6 pCi/m2/sec and 2 p€i/m2/sec at Licensed Hills
<1988 t, Millions)
6 pCi/m2/sec 2 pCi/m2/sec
Option Option
Incremental Incremental Incremental
Cost From Cost From Cost From
20 pCi/m2/sec 20 pCi/m2/sec 6 pci/m2/sec
Baseline Baseline Option
0 % Real Interest Rate $9.01 $17.24 $8.23
1 % Real Interest Rate $9.51 $18.18 $8.67
5 % Real Interest Rate $11.36 $21.73 $10.37
10 % Real Interest Rate $13.27 $25.38 $12.11
4-74
-------
In this analysis, no emissions are assumed for the ponded and wet areas of the piles, while the dry
areas are assumed emit radon-222 at the rate of i pCi/m2/sec for a concentration of 1 pCi/g of Ra-
226 found in the tailings. All covered areas are assumed to emit radon at the rate of 20 pCi/m2/sec.
Table 4-42A, on page 4-78, reproduces the summary of operable tailings impoundment areas
presented in Table 4-25, along with the average flux rates of the piles, and the areas of the piles that
must be covered and/or saturated in order to reduce average emissions to the 20 pCi/m /sec limit.
4.4.2.2 Benefits of Reducing Allowable Flux Limit to 20 pCi/mz/sec
The benefits of reducing allowable emissions during operations to 20 pCi/m /sec are presented, both
in terms of reductions in maximum individual risk and in cancer deaths per year, for each site in
Table 4-41. The risks for the 20 pCi/m2/sec are the risks presented for the post-closure option
adjusted to represent the fifteen year operating or standby phase. The largest reduction in cancer
deaths was for the White Mesa plant in Utah at 1.1E-02 and 1.6E-1 cancer deaths per year and for
the 15 year operating period, respectively. Because design factors at the Panna Maria, Canon City,
and La Sal mills allow the tailing to be kept totally wet, risks remain negligible for the entire
operating and standby phase.
4.4.2.3 Costs of Reducing Allowable Flux Limit to 20 pCi/m2/sec
Costs resulting from the reduction of allowable emissions to meet the UMTRCA standard are of two
basic types. First, where the dry areas of the pile are unlined, an earth cover must be applied before
the area can be saturated. This is primarily to prevent contamination of underground water resulting
from absorption into the earth beneath the tailings, and is incurred only in the first year of the
operation. The second cost, the cost of the water used in the saturation process, is incurred annually
over the active life of the mill site. These costs are discussed in detail below.
Water Cost
In order to effectively attenuate the release of radon from the saturated areas, a constant moisture
level must be maintained on the tailings surfaces. Thus, water must be added to the piles to
compensate for evaporation, with the amount required dependent upon the area to be kept moist and
regional evaporation rates. An estimate of the amount of water needed has been calculated for each
site and is presented in Appendix A to this chapter.
4-75
-------
Table 4-41. Risks and Reduction of Risks for Continued Operations at 20 pCi/m2/sec (a).
State/Mi iI
L i fet ime
Fatal Cancer
Risk to
Individuals
(Current)
Lifet ime
Fatal Cancer
Risk to
Individuals
(20 pCi/m2/sec)
Fatal Cancers
Per Year
(Current)
Fatal Cancers
Per tear
(20 pCi/m2/sec)
Seductions in
Fatal Cancer
Risk to
Individuals
Reductions in
Fatal Cancers
Per Year
Reductions in
Fatal Cancers
Over 15 Tears
Colorado
Canon City*
New Mexico
Ambrosia Lake
Homestske
Texas
Parma Maria*
Utah
Uhi te Mesa
Rio Algora*
Shootaring
Washington
Sherwood
Wyomi ng
Luck He
Shirley Basin
Sweetwater
O.OE+OO
9.0E-06
3.0E-05
0.0E+00
2.0E-06
0.0E+00
3.0E-06
1.0E-05
3.0E-06
5.0E-G6
1.0E-06
O.OE+OO
4.3E-06
2.1E-05
O.OE+OO
4.3E-07
O.OE+OO
4.3E-07
2.1E-06
1.3E-06
2.1E-06
4.3E-07
O.OE+OO
1.5E-03
8.3E-04
0.0E+00
1 . 1E-02
0.0E+00
1.1E-05
1.2E-03
1.6E-04
4.5E-04
3.0E-05
O.OE+OO
1.5E-03
8.3E-04
0.0E+00
9.1E-05
O.OE+OO
6.5E-06
1.1E-03
1.66-04
4.5E-04
3.0E-05
O.OE+OO
4.7E-06
8.6E-06
O.OE+OO
1.6E-06
O.OE+OO
2.6E-06
7.9E-06
1.7E-06
2.9E-06
5.7E-07
0.0E+00
0.0E+00
O.OE+OO
O.OE+OO
1.1E-02
0.0E+00
4.5E-06
1.0E-04
O.OE+OO
O.OE+OO
O.OE+OO
O.OE+OO
O.OE+OO
O.OE+OO
O.OE+OO
1.6E-01
O.OE+OO
6.8E-G5
1.5E-03
O.OE+OO
O.OE+OO
O.OE+OO
Total
6.3E-05
3.3E-05
1.5E-02
4.2E-03
3.0E-05
1.1E-02
1.7E-01
(a) Risks and reduction of risks are calculated for 15 year operation and standby phase only.
* Design of mill allows for tailings to be kept totally wet during operations.
-------
Generally, water can be pumped by the mill companies from underwater sources or from nearby
rivers to which the mills have access and water rights. Hence, the cost of the water to the mills is
the cost of the energy needed to operate the pumping facility. These costs are based on the area to
be saturated, evaporation rates, the vertical distance water must be lifted, and local industrial rates
for electric power. These data and the calculations of the costs are also presented in Appendix A to
this chapter. The annual cost of water is presented for each plant in Table 42B.
Earth Cost
In cases where the dry areas of the piles are unlined, an earth cover must be applied prior to
saturation to prevent ground water contamination. The amount of earth cover required depends
upon the size of the area to be saturated and whether the area to be saturated is protected by a liner.
The cost of earth cover is estimated in the same manner as in the section dealing with the cost of
achieving the post-closure 20 pCi/m2/sec option (Table 4-36), with the exception that only the cost
of regrading slopes, applying dirt cover, and reclaiming borrow pits are considered. The cost of
earth cover is presented for each plant in Table 42B. In addition, Table 42B contains the present
value total cost (earth and water), and annualized present value total cost for each mill and for all
mills combined.
4-4.3 Analysis of Benefits and Costs of Promulgating Future Work Practice Standards
This section presents the benefits and costs of using alternative control technologies for future
tailings piles. The alternative methods of disposal of radioactive tailings are compared to the base
case control technology of the single cell design. Benefits are measured in terms of the incremental
change in committed fatal cancers, presented in terms of both total and annual averages. A 100 year
time frame is used to calculate total benefits.
Costs are measured in nominal 1988 dollars, and represent the incremental change in costs associated
with the disposal and stabilization of mill tailings. Results are given using net present values, and
are also annualized using real rates of interest of 0, 1, 5 and 10 percent. A 100-year time period is
also used in generating these estimates.
4-77
-------
Table 4-42A Earth and Water Cover Required to Achieve Emissions of 20 p€i/m2/sec.
Surface Area (acres)
State/Mi t I
Liner
Average
Total Area
Area to be
Type (a)
Wet
Covered
Ponded
Dry
Total
Flux Rate
To be
Covered and
Area
Flux(b)
All Areas
Saturated (c)
Saturated
(pCi/m2/sec)
(pCi/m2/sec)
(Acres)
(Acres)
Colorado
Cannon Ci ty
SL
2
0
128
0
0
130
0
0
0
Primary
2
0
88
0
90
Secondary
0
0
40
0
40
New Mexico
Ambrosia Lake
UL
0
13
162
226
87
401
49.03
146.82
15.82
Secondary
0
13
121
108
242
Evap. Ponds
0
0
162
118
280
Homestake
UL
0
40
100
70
300
210
100.00
96.00
56
Primary
0
0
100
70
170
Secondary
0
40
0
0
40
Texas
Panna Maria
UC
40
80
40
0
0
160
<20
0
0
Utah
Wbito Nets
SL
70
0
55
5
981
130
37.73
2.35
0
Rio Atgorn
MC
29
0
18
0
0
47
0
0
0
Shootaring
UL
1
0
2
4
280
7
160.00
3.50
3.5
Washington
Sherwood
SL
40
0
0
40
200
80
100.00
32.00
0
Wyoming
Lucky Mac
0
108
139
60.
153
307
29.90
127.87
19.87
?ile 1-3
UL
0
108
35
60
203
Evap. Ponds
0
0
104
0
104
Shirley Basin
UL
36
0
179
60
208
275
45.38
33.56
33,56
Sweetwater
SL
0
0
30
7
280
37
52.97
4.36
0
Total
218
241
853
472
1,784
446.45
128.75
(a) SL « Synthetic Liner, NC a Clay Liner, UL « Unlined.
(b) Average radon emission rates for uncoverd dry areas,
(c) Where piles contain dry ponds, lined ponds are saturated before unlined areas are considered for treatment.
-------
Table 4-42B Cost of Earth Cover and Water Required to Achieve Average Emissions of 20 pCi/m2/sec-
State/Mi11
Liner
Type (a)
Total Area
To be
Saturated
(Acres)
Area to be
Covered and
Saturated
(Acres)
Cost Annual
of Earth Water Cost
Cover(b)
C$1,000) ($1,000)
Present Value Cost
(15 Tear Period)
Annual!zed Cost
(15 Tear Period)
0%
1X 5%
($1,000)
10%
0%
1% 5%
($1,000)
10%
Colorado
Cannon City SI
New Mexico
Ambrosia lake UL
Homes take UL
Texas
Panna Maria MC
Utah
White Mesa si
Rio Atgom NC
Shootaring UL
Washington
Sherwood SL
Wyoming
Lucky Mac UL
Shirley Basin UL
Sweetwater SL
0.0
146.8
96.0
0.0
2.3
0.0
3.5
32.0
127.9
33.6
4.4
0.0
15.8
56.0
0.0
0.0
0.0
3.5
0.0
19.9
33.6
0.0
$1,737
$6,035
$0
$0
$0
$9
$0
$1
$3,323
NA
$22
$55
$0
$1
$0
$1
$0
$45
$12
$2
$0
$0
$0
$0
$0.0 $0.0 $0.0 $0.0
$2,061 $2,020 $1,879 $1,744 $137.4 $145.7 $181.0 $229.2
$6,866 $6,743 $6,323 $5,908 $457.7 $486.4 $609.1 $776.7
$0
$14
$26
$0
$676
$0
$13
$24
$0
$625
$0
$9
$20
$0
$468
$0
$7
$16
$0
$343
$0.0 $0,0 $0.0 $0.0
$0.9 $0.9 $0.9 $0.9
$1.7
$1.8 $1.9
$2.2
$0.0 $0.0 $0.0 $0.0
$45.1 $45.1 $45.1 $45.2
$3,500 $3,454 $3,287 $3,111 $233.3 $249.1 $316.7 $409.0
$23
$21
$16
$12
$1.5 $1.5 $1.5 $1.5
Total
446.4
128.8
$11,105
$137
$13,166 $12,900 $12,002 $11,141 $878 $930 $1,156 $1,465
(A) SL = Synthetic liner, MC = Clay Liner, UL * Unlined.
(b) Total cost of regrading slopes, applying dirt cover and reclaiming borrow pits for portion of site requiring dirt cover.
-------
4.4.3.1 Work Practices for New Tailings Impoundments
Tailings impoundments constructed in the future must, at minimum, meet current Federal standards
for prevention of groundwater contamination and airborne particulate emissions (20 pCi/m2/sec).
The baseline tailings impoundment will have synthetic liners, be built partially below grade and have
earthen dams or embankments to facilitate decommissioning. A means for dewatering the tailings
after the area is filled should also be incorporated. This conventional design allows the maintenance
of a water cover during the milling and standby periods thus maintaining a very low level of
radon-222 emissions. Dewatering of the tailings can be accelerated using wells and/or built-ins.
A synthetic liner is placed along the sides and bottom. Cover material may be added after the
impoundment has reached capacity or is not going to be used further and the tailings have dried.
Two alternatives to the work practices assumed in this baseline model of new tailings impoundments
are evaluated in this analysis. These alternatives are discussed in the following sections.
Phased Disposal
The first alternative work practice which is evaluated for model new tailings impoundments is
phased disposal. In phased or multiple cell disposal, the tailings impoundment area is partitioned
into cells which are used independently of other cells. After a cell has been filled, it can be
dewatered and covered, and another cell used. Tailings are pumped to one initial cell until it is full.
Tailings are then pumped to a newly constructed second cell and the former cell is dewatered and
then left to dry. After the first cell drys, it is covered with earth obtained from the construction of
a third cell. This process is continued sequentially. This system minimizes emissions at any given
time since a cell can be covered after use without interfering with operations as opposed to the case
of a single cell.
Phased disposal is effective in reducing radon-222 emissions since tailings are initially covered with
water and finally with earth. Only during a drying-out period of about 5 years for each cell are
there any radon-222 emissions from a relatively small area. During mill standby periods, a water
cover could be maintained on the operational cell. For extended standby periods, the cell could be
dewatered and a dirt cover applied.
Continuous Disposal
The second alternative work practice, continuous disposal, is based on the fact that water can be
4-80
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removed from the tailings slurry prior to disposal. The relatively dry dewatered (25 to 30% moisture)
tailings can then be dumped and covered with soil almost immediately. No extended drying phase
is required, and therefore very little additional work would be required during final closure.
Additionally, ground water problems are minimized.
To implement a dewatering system would introduce complications in terms of planning, design, and
modification of current designs. Acid-based leaching processes do not generally recycle water, and
additional holding ponds with ancillary piping and pumping systems would be required to handle the
liquid removed from the tailings. Using trucks or conveyor systems to transport the tailings to
disposal areas might also be more costly than slurry pumping. Thus, although tailings are more easily
managed after dewatering, this practice would have to be carefully considered on a site-specific
basis.
Various filtering systems such as rotary vacuum and belt filters are available and could be adapted
to a tailings dewatering system. Experimental studies would probably be required for a specific ore
to determine the filter media and dewatering properties of the sand and slime fractions.
Modifications to the typical mill ore grinding circuit may be required to allow efficient dewatering
and to prevent filter plugging or blinding. Corrosion-resistant materials would be required in any
tailings dewatering system due to the highly corrosive solutions which must be handled. Continuous
covering of dewatered tailings is not practiced at any uranium mills in the United States, but it has
been proposed at several sites in the Southwestern and Eastern United States [MA 83], Tailings
dewatering systems have been used successfully at nonferrous ore beneficiation mills in the United
States and Canada [RO 78],
4-4,3.2 Comparison of Control Technologies for New Tailings Impoundments
To meet current Federal radon-222 emission standards, new tailings areas will have synthetic liners
with either earthen dams or embankments, and also incorporate a means of dewatering the tailings
at final closure. These new tailings can either be stored below or partially above grade. Although,
below grade storage provides the maximum protection from windblown emissions, water erosion, and
eliminates the potential for dam failure, it nevertheless is not cost effective in comparison to partially
above grade disposal technology.
4-81
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Previous analysis of work practices for new model tailings have estimated costs for a range of
alternative control technologies [EPA 86]. These estimated costs,in millions of 1985 dollars, are listed
in Table 4-43. These cost estimates suggest that storage of tailings partially above grade is cost
effective in comparison to fully below grade designs. Completely below grade designs are estimated,
on average, to increase costs by twenty percent.
Partially below grade piles have been shown to be cost effective compared to above grade
impoundments. Excavation costs for the final dirt cover are incurred in both cases. Using the
excavated pit, from which the earth cover is taken, to store tailings provides benefits in terms of
windblown emissions, water erosion, and dam failure at no cost. In addition, dam construction cost
is minimized because the sides of the excavation pit replace part of the dam.
The twenty percent increase in costs over partially above grade disposal are not justified by the
benefits gained from completely below grade disposal. As prior excavation has provided all the dirt
required for cover, the increase in costs associated with further excavation to fully below grade are
not believed to justify the associated benefits. The cost of additional excavation is greater than the
benefit as the bulk of the benefits to be derived from reducing windblown emissions, water erosion,
and dam failure have already been captured. For our purposes, therefore, only designs that are
partially above grade are considered.
Also dropped from consideration is the. continuous trench pile design. This technology has little
operational advantage over the continuous single cell design, and is more costly.
4.4.3.3 Benefits of Promulgating Future Work Practice Standards
A number of alternative control technologies are available to reduce radon-222 emissions and
subsequent risks from tailings disposal. Both timing and disposal method affect the rate of emissions
from tailings piles. The control alternatives, their emissions, and their potential benefits are
reviewed here.
Emissions From New Model Impoundments
The single cell impoundment is the most prominent control technology used to dispose of radioactive
tailings, and as such is used as a yardstick with which to compare the performance of the alternative
4-82
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impoundments. The single cell impoundment or baseline, usually 47 ha (116 acres), has a 15-year
active life and a surface area which is 80 percent wet or ponded during its active life. Final disposal,
using earthen covers, is assumed to occur five years after closure. Radon-222 emissions from this
impoundment in kCi per year are gives in 5 year intervals for the first 20 years, in total for the last
75 years, and for the entire 100 year period in Table 4-44. Emissions from this impoundment are
shown graphically by year in Figure 4-3. Radon-222 emissions remain fairly constant for the first
fifteen years, at 0.8 kCi/y, increase during the drying phase to about 3.8 kCi/y, and decline to about
.3 kCi/y once final cover, assumed to be 3-meters of earth, is applied.
Radon-222 emissions from both phased disposal and continuous single cell control technologies are
also presented in Table 4-44. The phased disposal impoundment has six cells each with a surface
area of 21.3 acres. Each ceil holds one-sixth of the mill tailings generated during the 15-year
operational period (roughly 2.5 years worth of tailings). Final cover, similar to the single cell
impoundment, is applied after a five year drying period. Emissions from a single cell of the phased
disposal impoundment during operation are zero because the cell is covered with water. After the
first cell reaches capacity it is dewatered and begins a 5-year drying period during which time
radon-222 emissions increase to a rate of approximately .7 kCi/y. Once the cell is dry a final earthen
cover is applied. In other words, the final earthen cover is not started until 7.5 years after the cell
began being filled. Meanwhile, a second cell is constructed, filled, and dewatered so that it too
contributes to the level of emissions from the tailings. Emissions thus increase at 2.5 year intervals,
as another cell reaches capacity and begins its drying out period. The emissions occurring after 3-
meters of earth cover have been applied to dry cells are also shown in Table 4-44. The results show
that when all six cells are covered emissions are constant at .31 kCi/y. Total emissions during the
operating life of this impoundment are 8.94 kCi/y. While, the average emissions during this period
are .60 kCi/y. This level of emission is lower than average emissions for the single cell of .834
kCi/y. Further, over a 100 year time period, the average emissions of .379 kCi/y is lower than the
average emission rate of .48 kCi/y from the single cell impoundment. In the post-operational period,
from 21-100 years, emissions of 24.42 kCi/y from phased disposal impoundments are higher than
those from the single cell impoundments of 23.38 kCi/y. This difference is caused by differences
in total surface area of the piles.
The other control technology considered is the continuous disposal of uranium mill tailings in a
single large impoundment. Its surface area is analogous to the single cell impoundment. Emissions
4-83
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Table 4-43, Estimated total cost for new tailings control technology.5®5
(to Millions of 1985 Dollars)
Below Grade Partially Below Grade
SINGLE CELL
Total Cost 41.33 29.71
PHASED DISPOSAL
One Cell 7.97 6.93
All (6) Cells 47.78 41.54
CONTINUOUS DISPOSAL
Trench Design 54.18 47.75
Single Cell Design N/A 37.44
Notes: (a) [PEI 86]; Based on comparable dimensions for cells.
4-84
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Table 4-44. Radon-222 Emissions and Emissions Reductions Resulting fro*
Alternative Work Practices CkCi),
Single Continuous
Celt Phased Single
Baseline Disposal Cell
j SSSSSKSSSS ls5S = S2SSgS3SSSSSSSasStKBaSSS:BSaaSSSSes«S3 l^SSSS^S^SSSSSSStffSSSSX^tSSSS^SCX
Emissions Emissions Emissions Emissions
Reduction Reduction Retfjctien Reduction
Time from from from from
Period Emissions Emissions Baseline Continuous Emissions Baseline Phased
Operational Phase
0-5 4.16 0.48 3.68 1.11 1,58 2.5? -1.lt
6-10 4.16 3.96 0.20 -1.88 2.08 2.08 1.88
11-15 4.16 4.50 -0.34 -1.93 2.57 1.59 1.93
16-20 12.47 4.57 7.91 -3.09 1.48 10.99 3.09
Total 24.95 13.51 11.45 -5.79 7.71 17.23 5.79
Post Operational Phase
21-100 23.38 24.42 -1.04 -2.52 21.9 1.48 2.52
All Phases
0-100 48.33 37,93 10.41 -8.31 29.61 18.71 8.31
srsrssr=s's;==r=arr4rs:ss:s:s:sjs:sras:=:ssar2:ss:s:s;js=a:srasn=»=e5:
Annual
Average 0.483 0.379 0.104 -0.083 0.296 0.187 0.083
4-8S
-------
Figur® 4—3: Mod®! lmpou«dim»rit Eir»lm»Ior»»
CfeCl/Y «ssr>
2-
i-
o.s-
aST" 3,'t 2h> zb 2!* 2B
O SINGLE + PHASED 0- COWBTOODS
4-86
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from this impoundment are estimated assuming that 1/15 of the surface area consists of de ware red
tailings that are uncovered at any time over the 15-year operational life. The final 1/15 surface area
is assumed to be covered at the end of the operational period. Emissions from this impoundment
during operation are low, since the tailings which are dried by a vacuum filter prior to disposal can
be covered immediately. Elimination of the drying period substantially reduces radon-222 emissions.
The emissions from this impoundment are given in Table 4-44, and suggest that during the
operational phase of the impoundment, on average, approximately .416 kCi/y of radon-222
contaminates the biosphere. These emissions are lower than either the baseline or the phased
disposal technologies. Over the entire 100 year period, in comparison to the other control
technologies, this impoundment on average discharges .296 kCi/y, the lowest level of radon-222.
Committed Fatal Cancers From New Model Impoundments
The risks associated with each type of impoundment are measured in terms of committed fatal
cancers. Benefits of the phased and continuous impoundments are measured as the incremental
reduction in committed fatal cancers. The risks are estimated from the following equation assuming
that the model impoundment has an impact in proportion to that of the current licensed mills:
x = (y/z)(w) (1)
where:
x = committed fatal cancers from model impoundments
y = total committed fatal cancers attributed to existing impoundments
z = emissions from existing impoundments
w = emission from model impoundment
Risks for a 100-year period, shown in Table 4-45, are estimated from equation (1) based on the rate
of .0113 fatal cancers per kCi/y, and the emission rate from each impoundment. The continuous
single cell approach always produces the lowest risk level. The phased disposal approach produces
slightly higher risks than the single cell baseline during the post-operational phase, although it
produces lower risks during the operational phase and over all phases.
The summary details of risk reductions that demonstrate this pattern are as follows: During the
operational period the risk of cancer is reduced, relative to the single cell baseline, by 0.129 if
4-87
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Table 4-45. Radon-222 Kikt and RUk Reductions Resulting fro*
Alternative Work Practices (coaaritted cancer*).
Single Continuous
Cell Phased Single
Baaeline Oisposal Cell
1 =
Risk Risk Risk Risk
Seduction Reduction Reduction Seduction
Tiae fro* fro* froa fro*
Period Risk Risk Baseline Continuous Risk Baseline Phased
Operational Phase
0-5 0.047 0.005 0.042 0.012 0.018 0.029 -0.012
6-10 0.047 0.045 0.002 -0.021 0.023 0.024 0.021
11-15 0.047 0.051 -0.004 -0.022 0.Q29 0.018 0.022
16-20 0.141 0.052 0.089 -0.035 0.017 0.124 0.035
Total 0.282 0.153 0.129 -0,066 0.087 0.195 0.066
Post Operational Phase
21-100 0.264 0.276 -0.012 -0.028 0.247 0.017 0.028
All Phases
0-100 0.546 0.429 0.117 -0.094 0.334 0.212 0.094
Annual
Average 0.005 0.004 0.001 -0.001 0.003 0.002 0.001
4-88
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phased disposal is adopted and by 0.195 if the continuous single cell method is used. The risk
reduction associated with using the continuous single cell relative to the phased approach is 0.066.
In the post-operational phase, phased disposal raises the risk by 0.012 while the continuous single cell
approach lowers it by 0.01? relative to the baseline and by 0.028 relative to phased disposal.
4.4.3.4 Costs of Promulgating Future Work Practice Standards
Estimated Cost of New Model Tailings Impoundments
Costs for partially above-grade single cell, phased disposal, and continuous single cell disposal
tailings impoundments are developed in Volume 2 of this Environmental Impact Statement.
Total costs for each design are shown in Tables 4-46 through 4-48, which indicate that the phased
partially above grade disposal impoundment is the most expensive design ($ 54.02 million), while the
single cell partially above grade impoundment ($36.55 million) is the least expensive. Costs for the
continuous single cell design ($ 40.82 million) are only slightly more than those of the single cell
impoundment, although the uncertainties surrounding the technology used in this design are the
largest. The volumes or surface areas and the unit costs that were used in calculating the cost figures
are also provided in Tables 4-46 through 4-48. The equations used to calculate volumes and surface
areas are discussed in detail in the Volume 2 of this Environmental Impact Statement as are the
sources and methods used to calculate unit costs.
This section reviews the costs associated with each of the control technologies discussed above.
Present values of the costs for each impoundment are shown in Table 4-49. These costs are
discounted over a 100-year period at the real rate of interest of 0, 1, 5, and 10 percent. The
annualized costs discounted using the same real rates of interest are given in Table 4-50. The results
suggest that the most costly technology is the phased disposal impoundment and the least costly is the
single cell.
When these costs are annualized using the same real rate of interest, phased disposal technology is
again found to be the most costly in comparison to not only the baseline but also to the continuous
single cell impoundment when the real rate of interest is below 10 percent. When the real rate of
interest is 10 percent, the continuous single cell approach becomes most expensive.
4-89
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Table 4-46. Coats for 8 Single Cell Partially below
Grade New Model Tailing® lapoundaent ($» 1988),
Voluee
or Ares Unit Unit
(cu. at. Cost Cost Cost
Itca or aq. at.) CS/C.Y.) (1/C.K.) {$,ail.>
Excavation 2,527,494 3.76 4.92 12.42
Grading 469,225 1.36 1.78 0.83
Cover
Grade 1.36
Coapact 1.14
Total 1,432,479 2.50 3.27 4.68
Gravel Cap 251,341 7.55 9.87 2.48
Riprap 138,408 23.00 30.07 4.16
Daa Const.
Srade 1.36
Coapact 1.14
Total 1,010,232 2.50 3.27 3.30
Synthetic Liner 442,405 11.16 13.35 5,91
ttrainage Systeas 641,089 0.50 0.60 0.38
Subtotal: ftireet Cost 34.16
Indirect Cost a 7 Percent 2.39
Total Cost 36.55
4-00
-------
Table 4-47, Costs for a Phased Design Partially below Grade
Men Model Tailings Impoundment (S, 1988).
Volume
or Area Unit Unit
(eu, mt. Cost Cost Cost
Item or sq. rat.) <$/C.Y.) (S/C.N.) (S,miI.)
Excavation 2,392,462 3.76 4.92 11.76
Grading 517,558 1.36 1.78 0.92
Cover
Grade 1.36
Compact 1.14
Total 1,616,978 2.50 3.27 5.28
Gravel Cap 442,835 7.55 9.87 4.37
Riprap 181,013 23.00 30.07 5.44
Dam Const.
Grade 1.36
Compact 1.14
Total 4,382,475 2.50 3.27 14.32
Synthetic Liner 451,901 11.16 13.35 6.03
Drainage Systems 1,066,682 0.50 0.60 0.64
Evaporation Pond
Excavate 3.76
Syn. Liner 11.16
Total 88,387 14.92 19.50 1.72
Subtotal: Direct Cost 50.49
Indirect Cost S 7 Percent 3.53
Total Cost 54.02
5s:====s:=======s==ssscs::=:=sssss=::==s=sss:5ss=sss3ssssssssss
4-91
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Table 4-48, Costs for a Continuous Design Partially below
Grade Mew Model Tailings Impoundment ($, 1988).
Ite
Volume
or Area
(cu. it.
or eq. at.)
Unit Unit
Cost Cost Cost
(S/C.Y.) <«/C.K.> (S,kU.)
Excavation
Grading
Cover
Grade
Compact
Total
BraveI Cap
Riprap
Dam Const.
Grade
Compact
Total
Synthetic Liner
Evaporation Pond
Excavate
Syn. Liner
Total
Vacuus Filter
2,527,494
469,225
1,432,479
251,341
138,408
1,010,232
442, 405
176,775
N/A
3.76 4.92 12.42
1.36 1.78 0.83
1.36
1.14
2.50 3.27
7.55 9.87
23.00 30.07
1.36
1.14
2.50 3.27
11.16 13.35
3.76
11.16
14.% 19.50
N/A H/A
4.68
2.48
4.16
3.30
5.91
3.45
0.%
Subtotal: Direct Cost 38.15
Indirect Cost a 7 Percent 2.67
Total Cost 40.82
4-92
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Table 4-49. Sunwary of Net Present Values of Alternative Work Practices
(1988 nominal dollars. Millions}
Itork Practice
Phased Disposal Continuous single Cell
Real
Interest Rate
Single Cell
Baseline
I—
Phased
Disposal
Incremental Cost
from Baseline
Incremental Cost
from Continuous
Single Cell
=l
Continuous
Single Cell
Incremental Cost
froa Baseline
Incremental Cost
from Phased Disposal
0 %
182.8
260.4
77.6
56.3
204.1
21.3
-56.3
1 %
167.7
234.4
66.8
41.9
192.5
24,8
-41.9
5 %
129.0
160.5
31.4
1.9
158.5
29.5
-1.9
10 %
105.3
108.4
3.1
-24.2
132.6
27.3
24.2
-------
Table 4-50, Suwnry of Annualized Cost# of Alternative Work Practices
(1988 rarinat dollars, nU 11 oris)
Uork Practice
Phased Disposal
Continuous Single Cell
Incremental Cost
Real Single Cell Phased Incremental Cost froa Continuous Continuous Increaental Cost Incremental Cost
Interest Rate Baseline Disposal frma Baseline Single Cell Single Cell froe Baseline fro* Phased Disposal
0 X
1 X
5 X
10 X
1.8
2.7
6.5
10.5
2.6
3.7
8.1
10.8
0.8
1.1
1.6
0.3
0.6
0.7
0.1
-2.4
2.0
3.1
8.0
13.3
0.2
0.4
1.5
2.7
-0.6
-0.7
-0.1
2.4
-------
4.5 Economic Impacts
Any regulatory alternative will increase the cost of domestically produced U3Og. The amount of this
impact will depend on the regulation selected. The impact of consumers and investors is evaluated
assuming that the present value of the additional cost for future and existing piles was $250 million
at a 10 percent real rate of interest. This figure is roughly equal to the incremental costs associated
with a work practice for active plants that limits allowable emissions to an average of 20 pCi/m2/sec
while in operation, a post-closure flux rate of no more than 2 pCi/m2/sec, and assuming new
impoundments utilize the phased disposal control presented in sections 4,4. In this section, the
effects of such regulatory costs are evaluated. The impact of any of the alternative regulations from
section 4.4 will be smaller and can be scaled from the impacts calculated here. If the U.S. uranium
industry created an annuity payment to cover the added cost of this regulation, the payments
required per year would be $66 million in each year for 5 years, or $41 million for each year for
10 years. The impact of these cost increases on investors in this industry or purchasers of electricity
is also analyzed.
4.5.1 Increased Production Cost
The added production cost resulting from the regulation may, or may not, be passed on to the
consumers of U3Oe (electric utilities). If the added cost is translated into higher prices for U308
ceteris paribus, then the consumers of electric power will ultimately be charged higher rates,
depending on the rulings of state and local public utility commissions. Customers of utilities with
a high reliance on nuclear generating capacity would face the highest increases. If the U.S. uranium
milling industry is unable to pass on the disposal costs internalized by this regulation as a result of
market competition from foreign producers or other factors, then the added cost will be ultimately
paid by investors in the industry.
No attempt is made to quantify these impacts, instead a qualitative evaluation based on two extreme
situations is made. The first case is based on the assumption that the uranium mills are unable to
pass on the costs of regulation in the form of higher U3Os prices. The second case assumes that the
producers are able to recover all the costs associated with the disposal of tailings through increased
U3Oa prices. The results generated under these assumptions then will provide the lower and upper
bound, respectively, of the likely impacts. In fact, some of these costs will surely find their way into
the rate base of utilities with nuclear generating capacity. In addition, since some owners of these
4-95
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existing impoundments are no longer operating nor do they have any intention of ever operating in
this industry in the future, their cost of disposal must be borne by the investors in these firms.
It is assumed in the first case that no portion of the cost of the regulation can be passed on to the
purchaser of U3Oa. Selected average financial statistics for 1982-1986 from the domestic uranium
industry (presented in Section 4.4) are given in Table 4-51. These data are compared to the present
value cost impacts of the regulation and to the required annuity payment to amortize these costs over
five or ten years. The 1982-1986 period is one in which the industry had been contracting and
experiencing substantial losses due to excess capacity in production. The present value cost of the
regulation would be about five times the industry losses over this period. It is equal to about 10
percent of the book value of industry assets and about 15 percent of industry liabilities.
In the second case it is assumed that the uranium industry is able to recover the entire increase in the
tailings disposal cost be charging higher U3Oa prices. This increased input cost to electric utilities
will ultimately be added to the rates paid by electric power consumers.
The revenue earned by the industry for generating 2.4 trillion kilowatt hours of electricity in 1986
was 121.40 billion dollars. The 1987 present value of the regulation (estimated to be $250 million)
is less than 1 percent (.06%) of the U.S. total electric power revenue for the same year. Table 4-52
presents the relationship of the regulatory cost to power generation.
The increased cost of total generation reflects a change in the average cost per unit for the nation.
The regional impacts will vary from this mean, based in part, on the dependence on nuclear power
by region as shown in Table 4-53. The ERCOT region, for example, with no nuclear generating
capacity would probably feel no effect from the cost of the regulation in higher electricity prices,
and other regions, like MAIN and SERC would suffer the greatest effects. As for a specific
customer or community, the level of impact is dependent upon the percent of generation from
nuclear power that their particular electrical utility utilizes. For example, Commonwealth Edison of
Illinois and Duke Power of North Carolina have two of the highest percentage of power from nuclear
sources, so their customers would be more severely impacted than customers in other utilities.
4-96
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Table 4-51. Comparison of the Present Value of the Estimated Cost of Impacts with Seclected Financial
Statistics of the Domestic Uranium Industry: 1982-1986
Balance Sheet
Accounts
Domestic Uranium
Industry
Present Value
Cost as a
Each Industry
Statistic
Annual five
Tear Annuity
Payment as a
Percent of Each
Industry Statistic
Annual Ten
Year Annuity
Payment as a
Percent of Each
Industry Statistic
Operating Revenue 712,5
Net income (Loss) (139,2)
Total Sources of Funds 265.1
Capital Expenditures 55.5
Total uses of Funds 449.2
Current Assets 478.6
Total Assets 2,696.6
Total Uablilities 1,689.4
35.1% 9.3% 5.8%
-179.6% -47.4% -29.5%
94.3% 24.9% 15.51
450.5% 118.9% 73.9%
55.7% 14.7* 9.1%
52.2% 13.8% 8.6%
9.3% 2.4% 1.5%
14.8% 3,9% 2.4%
Note; Assume $250 million NPV cost, $66 million for 5 year annuity and $41 million for 10 year annuity.
4-97
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4.5.2 Regulatory Flexibility Analysis
The Regulatory Flexibility Act (RFA) requires regulators to determine whether proposed regulations
would have significant economic impact on a substantial number of small businesses or other small
entities. If such an impact exits, they are required to consider specific alternative regulatory
structures to minimize the small entity impacts without compromising the objective of the statute
under which the rule is enacted. Alternatives specified for consideration by the RFA are tiering
regulations, performance rather than design standards, and small firms exemptions. Most firms that
own uranium mills are divisions or subsidiaries of major U.S. and international corporations. Many
of these uranium milling operations are parts of larger diversified mining firms which are engaged
in many raw materials industries and uranium represents only a small portion of their operations.
Others are owned by major oil companies or by electric utilities who were engaged in horizontal and
vertical integration, respectively, during the 1960s and 70s. In 1977, there were 26 companies
operating uranium mills and at the start of 1986 only two were operating. The future of this
industry suggests that only a limited number of these existing facilities will ever operate again. It
is also expected that the high level of financial risk and capital requirements will continue to attract
only large diversified firms and electric utilities to this industry. Thus, no significant impact on
small businesses is expected.
4-98
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Table 4-52. impacts of Regulation on Electrical Power Industry.
Total Electric
Power Industry
Nuclear Electric
Power Industry
Only
198? Hi I lion KilLouatt-
Hours Generation
2,572,12?
414,038
Present Value of Added
Costs for Disposal per
Million Kilowatt-Hours
97.2
603,8
Annual Cost of 5 Year
Annuity per Million
Ki Uowat -Hours
25.7
159.4
Annual Cost of 10 Year
Annuity per Million
KiIlowat-Hours
15.9
99.0
Note: Assume $250 NPV cost, $173 per Year for 5 Year Annuity, S97 for 10 Year Annuity.
4-99
-------
Table 4-53. Electrical Separation by MOC Region, 1W
Total ftmt
Hue Imp Power
Region
Generated
Nuclear Power
•• s Percent
(6VN)
Senerated (6MH)
of Total Power
ECAR
441,995
28,766
6.5X
ERCOT
172,610
•
-
KMC
191,621
£0,885
31.8*
mm
185,405
67,659
36.51
KAPHU.S.)
125,383
22,795
18.22
NPCC(U.S.)
205,808
52,182
25.4X
SERC
543,452
131,207
24.1%
SPP
237,132
37,881
16.0*
VSCCCU.S.)
457,404
53,895
11.8*
Source: DOE87*
KEYi
W«»um SjrwM
Cowtfiiuting Ceuncd
*•*» C mkJ
7
IACOT
Monteui fo*„
CoortiiMtinj Cobncil
C«a Ciauil Am
Afrtemet
httd-ewtmm Am
Povitfast
Mi# Amtna
httrpoo) N.noft
tUark blubl* SovAvtfi
Ctwieil «f Tims
i* Cltfuie
4-100
-------
REFERENCES
AR86 The annual reports of all uranium-producing companies were examined for the years
1976-1986, The reference, AR, is followed by a date. The specific company
reference is to be found in the text.
BC84 Bureau of the Census Population Projections
C085 Industry and State of Colorado information
DOE85b Department of Energy, Uranium Industry Annual 1984, DOE/EIA-0478(84),
October 1985.
DOEESc Department of Energy, Commercial Nuclear Power; Prospects for the United States
and the World, DOE/EIA-0438(85), September 1985.
DOE87a Department of Energy, Domestic Uranium Mining and Milling Industry: 1986
Viability Assessment, DOE/EIA-0477(86), November 23, 1987,
DOE87b Department of Energy, Uranium Industry Annual 1986, DOE/EIA-0478{86)»
October 9, 1987.
DOE87c Department of Energy, Commercial Nuclear Power 1987; Prospects for the United
States and the World, DOE/EIA-0438(87), July 31, 1987.
EPA82 U.S. Environmental Protection Agency, "Final Environmental Impact Statement for
Remedial Action Standards for Inactive Uranium Processing Sites (40 CFR 192)," Vol,
I, EPA 520/4-82-013-1, Office of Radiation Programs, Washington, D.C., October,
1982.
EPA83 U.S. Environmental Protection Agency, "Final Environmental Impact Statement for
Standards for the Control of By-Product Materials from Uranium Ore Processing
(40 CFR 192),'* Vol. I, EPA 520/1-83-008-1, Office of Radiation Programs,
Washington, D.C., 1983.
EPA86 U.S. Environmental Protection Agency, "Final Rule for Radon-222 Emissions from
Licensed Uranium Mill Tailings," EPA 520/1-86-009, Office of Radiation Programs,
Washington, D.C., August, 1986.
EPA89 Risk Assessments, Volume 2.
JFA85a Jack Faucett Associates, Economic Profile of the Uranium Mining Industry. Prepared
for U.S. Environmental Protection Agency, January 1985.
J FA 8 5b Jack Faucett Associates, communications with uranium mill operators and parent
companies, June-October 1985.
MA83 Marline Uranium Corp. and Union Carbide Corp., "An Evaluation of Uranium
Development in Pittsylvania County, Virginia," October 15, 1983.
4-101
-------
MSHA Health and Safety Analysis Center, Mine Safety and Health Administration (MSHA),
Department of Labor, "1987 Uranium Mines Address Listing with Workers and
Employee Hours," Fourth Quarter, 9 February 1988.
NM85 Personal communication, Energy and Minerals Department, Mine Inspection Bureau,
State of New Mexico, December 1985.
NRC80 U.S. Nuclear Regulatory Commission, "Final Generic Environmental Impact Statement
on Uranium Milling," NUREG-0706, Washington, D.C., September, 1980.
NugentSO Nugent, J.W., A Summary of Mineral Industry Activities in Colorado, 1980: Part II,
Metal-Nonmetal," Colorado Department of Natural Resources, Division of Mines.
NUEXCO88 NUEXCO, NUEXCO Monthly Report, #233, February, 1988.
NUC088J NUEXCO, NUEXCO Monthly Report, January, 1988.
OECD83 Organization for Economic Cooperation and Development, Uranium; Resources,
Production, and Demand, Paris, December 1983.
PEI85a PEI Associates, oral communication, August-October 1985.
PNL84 Battelle Pacific Northwest Laboratories, U.S. Uranium Mining Industry; Background
Information on Economics and Emissions, PNL-5035, March 1984.
Ro78 Robinsky, E.I., "Tailing Disposal by the Thickened Discharge Method for Improved
Economy and Environmental Control," in Volume 2, Proceedings of the Second
International Tailings Symposium, Denver, CO, May 1978.
Ro84 Rogers, V.C., K. K. Neilson and D, R. Kalkwarf, Radon Attenuation Handbook for
Uranium Mill Tailings Cover Design, NUREG/CR-3533, prepared for the U. S.
Nuclear Regulatory Commission, Washington, D.C., April, 1984.
TX85 Personal communication, Texas Railroad Commission, State of Texas, December 1985.
WY80 Wyoming State Inspector of Mines, 1980, 1981, and 1984 annual reports.
WA85 Personal communication, Department of Natural Resources, Division of Geology and
Earth Resources, State of Washington, December 1985.
Zi79 Zimmerman, Charles F., Uranium Resources on Federal Lands, Lexington, MA:
Lexington Books, 1979.
4-102
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APPENDIX A
CALCULATION OF WATER COSTS
4-103
-------
To maintain a constant moisture level on the tailing surfaces, sufficient water must be added to the
piles to compensate for evaporation. This water can be pumped by the mill companies from
groundwater sources or from rivers to which the mills have access and water rights. Hence, the cost
of the water to the mills is the cost of the energy needed to pump it. These costs are based on the
area to be saturated, evaporation rates, the vertical distance water must be lifted, and industrial
electric rates. These data and the calculations of the costs are presented in tables 4A-I.
The amount of water required to compensate for evaporation depends on the area to be kept moist
and on evaporation rates. Areas to be kept saturated range from 2.4 acres at White Mesa Mill to
146.8 acres at Ambrosia Lake Mill. Evaporation rates were obtained from the NOAA Evaporation
Atlas for the Contiguous 48 United Slates J The free water surface evaporation (FWS) map was used.
According to the atlas, FWS "...closely represents the potential evaporation from adequately watered
natural surfaces such as vegetation and soil."8 Evaporation rates ranged from 33 inches per year at
the Sherwood Mill in the State of Washington to 50 inches per year at the Ambrosia Lake Mill in
New Mexico. Converting inches per year to feet per year and multiplying by the acreage to be kept
saturated yields the number of acre-feet of water that must be replaced each year.
Since the mines and mills own rights to groundwater or river water, the cost of water is the cost of
pumping it. Table 4A-1 converts the volume of annual water loss to evaporation measured in acre-
feet per year to the weight of water pumped in pounds per year. The weight of water to be lifted
ranges from 24 million pounds per year at White Mesa Mill to 1.6 billion pounds per year at
Ambrosia Lake Mill. Table 4A-1 also shows the estimated vertical lift at each mill. Sherwood Mill
has no need to pump water for the purpose of saturating tailings because it has surplus water from
other operations. Homestake Mill must lift water 800 feet.
The work done pumping the water equals the product of the weight of water in pounds pumped
times the vertical distance it is lifted. These computations are also performed in Table 4A-1. This
product times two is the foot-pounds of work done in a normal year, assuming that the pumps used
have 50 percent efficiency. This value is converted into kilowatt hours which is then multiplied by
7 U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National
Weather Service, NOAA Technical Report NWS 33, "Map 3 of 4: Annual FWS Evaporation",
Evaporation Atlas of the Contiguous 48 United States, Washington D.C., June 1982.
8 Atlas, p. 4.
4-104
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Table 4A-1. Calculation of Cost of Water Required to Reduce Allowable Emissions to 20 pCi/ra2/sec During Operations.
Mi I l/Site
Area to be
Saturated
Annual
Evaporation
Rate
Annual Hater
loss to
Evaporation
Quantiy of Water Pumped
Estimated
Vertical
Lift
Total Work Done per Year
50% Efficient Punp
Unit Total
Energy Cost Energy Cost
(acres)
(in/yr) (acre ft/yr) (cu-ft/yr) (gallons/yr)
(pounds/yr)
(ft-lb)
(kw-hr>
(S/kw-hr)
(S/yr)
Hew Mexico
Ambrosia Lake
Homestake
Utah
White Mesa
Shootaring
Washington
Sherwood
146.8
96
2.4
3.5
32
50
49
47
40
33
612
392
9
12
88
26,647,830
17,075,520
400,934
508,200
,999,310,621 1,594,484,966
127,715,183 1,021,721,466
2,998,755
3,801,047
3,833,280 28,670,755
23,990,037
30,408,377
229,336,043
200
800
500
500
6.4E+11
1.6E+12
2.4E+10
3.01+10
O.OE+OO
240,300
615,923
9,039
11,457
SO.09
$0.09
to.10
SO.10
$0.10
821,627
555,433
$1«146
Wyoming
Lucky Mc
Shirley Basin
Sweetwater
Totals
127.9
33.6
4.4
446.6
43
43
43
458
120
16
1,707
19,959,228
5,238,380
680,552
149,283,682
39,180,108
5,090,145
1,194,269,457
313,440,862
40,721,161
500
500
500
74,343,924 2,356,050,296 4,448,372,369
1.2E+12
3.1E+11
4.1E+10
3.9E+12
449,962
118,094
15,342
1,460,117
SO.10
SO. 10
$0.10
$44,996
$11,809
6137,449
Source: JFA Calculations
-------
the cost of electricity per kilowatt hour to give the annual cost of water. Because Sherwood Mill
does not have to pump water, its cost is zero. The highest pumping cost is for Homestake Mill in
New Mexico. The annual cost of pumping one billion gallons of water per year 800 vertical feet is
$55,000. The total cost for all mills is $137,000.
If the mills had to buy surface water rights the cost would be higher. For example, in New Mexico,
surface water rights sold for $750 to $3000 per acre foot in 1988-89. At the lower price Ambrosia
Lake Mill would have to pay $459,000 annually for water to compensate for evaporation. At the
higher price, the cost would be $1.8 million annually. Water right prices do not account for the cost
of transporting the water.
4-106
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CHAPTER 5
HIGH-LEVEL WASTE DISPOSAL FACILITIES
-------
5. HIGH-LEVEL WASTE DISPOSAL
5.1 Introduction and Summary
The facilities planned for the ultimate disposal of high-level nuclear waste have been designed to
result in negligible releases of radionuclides to the environment. The benefits of further reductions
of emissions are expected to be low and the costs per unit of benefit are expected to be high. No cost
study has been conducted and no economic impact analysis can be performed.
5.2 Industry Profile
5.2,1 Introduction
This chapter addresses the ultimate disposal of high-level nuclear waste generated by the commercial
nuclear power industry and by the Department of Defense. Although no facilities for this purpose
currently exist, the federal government has taken responsibility for finding suitable permanent
storage facilities. These facilities will be operated by the Department of Energy. The facility for
the disposal of high-level waste from the nuclear power industry will be licensed by the Nuclear
Regulatory Commission. Although the facilities will not be privately owned, it is expected that
private contractors will be selected to operate them.
Two facilities devoted to the ultimate disposition of high-level nuclear waste are currently being
planned. A third facility, a monitored retrievable storage facility (MRS) is also being planned.
However, since the MRS facility is not to be used as a final disposal site, it is not considered in this
report. The facilities under consideration are [EPA89]:
1) The Waste Isolation Pilot Plant (WIPP) -- under construction in Carlsbad, New
Mexico.
2) The Yucca Mountain Geologic Repository -- not yet under construction, but to be
located in Yucca Mountain, Nevada.
These facilities will be devoted to three types of waste [EPA89).
1) Spent nuclear fuel where there is no intent to reprocess;
2) High-level waste from the reprocessing of spent nuclear fuel; and
3) Transuranic wastes
5-1
-------
The role played by each facility is discussed below,
5.2.2 Facilities for the Ultimate Pisoosai of Hieh-tevei Waste
The design features and operations of the two facilities under consideration are discussed below;
5.2.2.1 The Waste Isolation Pilot Plant fWIFPTi
The WIPP is for the disposal of defense radioactive wastes, primarily transuranic wastes. The facility,
currently being constructed in Carlsbad, New Mexico, performs the two main phases of waste
disposal--first, the receipt and final packaging of the waste and, second, its permanent underground
storage--at a single location. The packages it receives are of two types, contact-handled and remote-
handled waste. Damaged casks are decontaminated, overpacked or repaired. They are then
transported underground into a mined repository in a salt formation.
5.2.2.2 Yucca Mountain Geologic Repository
This facility, planned for construction in Yucca Mountain, Nevada, will first receive and package
and then permanently store high-level wastes produced by commercial activities.
5.2.3 Demand for Hieh-Levei Waste Management
One of the major issues of the nuclear age is what to do with the high-level waste generated by
nuclear power reactors and weapons production facilities. Spent fuel and other high-level wastes
have accumulated on-site at nuclear power plants and weapons plants, and at interim storage sites.
The projected generation of spent fuel by the year 2000 f EPA89] will be 95,000 metric tons of heavy
metal. The absence of a permanent storage site to handle spent fuel complicates the planning process
for power companies and involves an interim storage cost for companies that operate reactors. High
level waste management costs include both the cost of disposal and the cost of potential liability in
the event of an accident. Thus, there is a very real demand for the services of high-level waste
disposal facilities.
5-2
-------
5.2.4 Sunnlv of High-Level Waste Management
No facility for the management of high-level waste currently exists. However, two facilities are
envisioned, one is in the planning stages, and one is under construction. The projected quantity of
high-level and transuranic waste to be disposed of by the turn of the century is about 70,000 metric
tons of uranium (MTU) or equivalent. Sixty-two thousand MTU of this will be spent fuel from
civilian reactors and 8,000 MTU will be defense waste. The projected supply of high-level waste
disposal falls short of the 95,000 MTU required to meet the needs of firms and agencies operating
nuclear reactors (EPA89]. The difference will be made up by at-reactor storage and interim off-
site storage. Thus, the projected services of the high-level waste facilities fall slightly short of the
projected demand.
5.3 Current Emissions. Risk Levels, and Feasible Control Methods
5.3.1 Introduction
Since all facilities for high-level waste disposal are still in the planning or construction stages, there
are no current emissions of radionuclides from the sites. However, estimates of the emissions have
been made as part of the planning process. Most of the atmospheric emissions are expected to come
from routine receiving, unpacking and decontamination of shipping casks, or from accidental
droppage of casks during handling. All handling of the materials is to be done in "hot cells" which
are equipped with multiple stage high-efficiency particulate air (HEPA) filters to remove most of
the airborne contaminates before air from the hot cells is released to the atmosphere.
For most of the wastes, the casks in which they are shipped or stored are the major emission control
devices. The HEPA filters are considered to be backup protection.
5-3.2 Current Emissions and Estimated Risk
Table 5-1 gives the total estimated quantities of radioactive emissions and the estimated risk for each
facility under normal operation [EPA89].
5-3
-------
Table 5-1: Emissions and Risks From Normal Operations at HLW Disposal Facilities.
Release Rates
Facility Radionuclide (Ci/y)
Nearby Individuals
Lifetime Fatal
Cancer Risk
Regional (0-80 km)
Population
Deaths/year
Yucca
Ii-3
C-14
Kr-85
1-129
2.8E+2
1.1E+1
1.4E+4
2.8E-2
7E-8
4E-6
W1PP
Pu-238
Pu-239
Pu-240
Pu-241
Am-241
Cm-244
6.6E-8
4.6E-8
1.0E-8
2.8E-6
1.6E-7
2.4E-8
3E-10
2E-9
5.3.3 Control Technologies
Because the planned high-level waste management facilities are to be equipped with state-of-the-
art control equipment, the cancer risk associated with release from these facilities is no greater than
1E-6. Accordingly, technologies for further reductions of these emissions were not evaluated nor
were costs computed for reductions in emissions.
5.4 Analysis of Benefits and Costs
5.4.1 Introduction
The following sections discuss the costs and benefits of control technologies for high-level waste
facilities.
5.4.2 Least-Cost Control Technologies
Radioactive emissions from the three high-level waste management facilities are entrained by the
air flowing through a series of HEPA filters. Assuming that HEPA filters remove 99 percent of the
particulates passing through them, 1 percent of the original emissions will be left. Assuming the costs
of installing and operating an additional HEPA filter is the same as the cost of installing and
operating the HEPA filter ahead of it, the cost per Ci/y removal by the last filter in line would be
5-4
-------
one hundred times as much, because the previous filter has removed 99 percent of the particulates
entering it and leaves the next filter with just one percent as much input to filter.
5.4.3 Health and Other Benefits
The health benefits of adding another HEPA filter would be to reduce the incidence of cancer
attributable to a facility to one percent of the original amount. Nationwide, the number of cancers
attributable to these facilities would drop from 1E-6 per year to 1E-8 per year, a reduction of 9E-
7.
5.5 Industry Cost and Economic Impact Analysis
Since this rulemaking does not involve a proposal for emission control for high-level waste
management facilities beyond the levels in the proposed designs, it will have no economic impact.
If there were proposals for further emission controls, they would affect an industry that has yet to
be born and which would be in a position to pass on the associated costs to the federal government.
The government could pass on some of the costs to the commercial nuclear power industry in fees
collected in exchange for storage. The nuclear power industry is likely to benefit from the overall
project, since one of the industry's major operational, planning and political problems is the handling
and interim storage of high-level waste.
5-5
-------
REFERENCES
EPA89 Risk Assessment» Vol, 2.
5-6
-------
CHAPTER 6
DEPARTMENT OF ENERGY FACILITIES
-------
6. DEPARTMENT OF ENERGY FACILITIES
6.1 Introduction and Summary
The Department of Energy (DOE) owns or directs the activities of numerous facilities across the
country that emit radionuclides into the air. Twenty-seven facilities are mentioned in this chapter.
The Feed Materials Production Center (FMPC) at Fernald, Ohio is discussed in chapter Seven.1 The
primary task of many of these facilities is the support of nuclear weapons production and research
for the Department of Defense. Many of the facilities also support research of biomedical studies,
environmental and safety aspects of nuclear energy, nuclear waste processing, advanced nuclear
energy production, fusion research, non-nuclear energy studies, basic research in high energy
physics, and training. The names and locations of these facilities are listed in Table 6-1.
Because each facility is unique, risk assessments were conducted on a facility by facility basis. The
overall risk for all of these DOE facilities is estimated at 3E-1 fatal cancers per year.
6.2 Industry Profile
A wide variety of facilities and of functions that they fulfill are covered in this chapter. Broadly
speaking the functions can be classified into nuclear weapons research and production, basic physics
or energy research, nuclear waste disposal and management, reactor testing and training, medical
applications or health effects of radionuclides, and environmental studies. Over a dozen facilities are
involved partially or solely in nuclear weapons design, testing, and production. Over half a dozen
are involved in the nuclear power production or research fields while at least four laboratories are
conducting basic research in physics. Several facilities are involved in waste disposal and
management activities and over half a dozen in health, biomedical, or environmental research.
The level of activities at these facilities is dependent upon a host of factors including past nuclear
activities and their waste products; current and future military requirements, priorities, and funding
levels; research for advanced nuclear power processes; waste disposal requirements and regulations;
further research into health effects; and biomedical applications of radionuclides. Some of the
facilities or their components are on stand-by status while others are closed down and
decommissioned at this time.
4
DOE recently arrived at an agreement with the State of Ohio to clean up this site.
6-1
-------
Table 6-1; Department of Energy Facilities.
Facility Location
Los Alamos National Laboratory
Oak Ridge Reservation
Savannah River Plant
RMI Company
Feed Materials Production Center
Hanford Reservation
Brookhaven National Laboratory
Mound Facility
Idaho National Engineering Laboratory
Lawrence-Berkeley Laboratory
Padueah Gaseous Diffusion Plant
Lawrence Livermore/Sandia Laboratory
Portsmouth Gaseous Diffusion Plant
Argonne National Laboratory
Pinellas Plant
Nevada Test Site
Knolls Atomic Power Laboratory
Battelle Memorial Institute
Fermi National Accelerator Laboratory
Sandia National Laboratories/Lovelace
Bettis Atomic Power Laboratory
Knolls Atomic Power Laboratory
Rocky Flats Plant
Pantex Plant
Knolls Atomic Power Laboratory
Ames Laboratory
Rockwell International
Los Alamos, New Mexico
Oak Ridge, Tennessee
Aiken, South Carolina
Ashtabula, Ohio
Fernald, Ohio
Richland, Washington
Long Island, New York
Miamisburg, Ohio
Upper Snake River, Idaho
Berkeley, California
Padueah, Kentucky
Livermore, California
Piketon, Ohio
Argonne, Illinois
Pinellas County, Florida
Nye County, Nevada
Kesselring, New York
Columbus, Ohio
Batavia, Illinois
Albuquerque, New Mexico
West Miflin, Pennsylvania
Windsor, Connecticut
Jefferson Co., Colorado
Amarillo, Texas
Schenectady, New York
Ames, Iowa
Santa Susana, California
6-2
-------
63 Current Risk Levels and Feasible Control Methods
6.3.J introduction
The summary findings reported in this section are based upon an assessment of each facility which
determined the emissions, source release point(s), demographic data, meteorological information, etc.
The risk assessment utilizes the AIRDOS-EPA/DARTAB/RADRISK computer codes [EPA89).
Radionuclides that contributed at least 90 percent of the collective contribution are identified in the
supporting documentation cited above. The specific processes and emission controls for some of the
facilities such as the Oak Ridge Y-12 plant are classified.
Table 6-2 presents the risks to the populations living within BO km of DOE facilities and the
maximum estimated risk to nearby individuals for each facility.
6.3.2 Facility Descriptions
Emission characteristics by facility and radionuclide type and resultant risks are presented in the
supporting documentation for each of the facilities [EPA89]. Discussion of the four facilities that
result in effective dose equivalents of over 1 mrem/y follows. Although previously listed, RMI
Company is no longer included in this discussion due to their installation of additional controls in
1988 which has reduced their EDE to below 1 mrem/y.
The Los Alamos National Laboratory has major sources emitting over a dozen radionuclides with no
source contributing more than a small fraction of the emissions. Each of the facilities has its own
control mechanisms which vary in removal or containment efficiency and effectiveness. Not all
radionuclide emissions from Los Alamos National Laboratory are controlled.
6-3
-------
Table 6-2 Summary of Estimated Risks Around DOE Facilities
Estimated Maximum
0-80 Km Deaths Estimated Risk to
Site Population per Year Nearby Individuals
(0-80 Km) (Lifetime)
Los Alamos Laboratory, NM
160,000
4E-
-03
2E-04
Oak Ridge National Lab, TN
160,000
3E-
¦02
8E-05
Savannah River Plant, GA
550,000
2E-
-01
7E-05
RMl Co., OH
1,400,000
8E-
-04
4E-05
Feed Materials Production Ctr, GA
3,300,000
3E-
-03
3E-05
Hanford Reservation, WA
350,000
6E-
-03
3E-05
Brookhaven National Lab., NY
5,200,000
1E-
-03
2E-05
Mound Facility, OH
2,900,000
3E-
-03
1E-06
Idaho National Eng. Lab, ID
100,000
2E-
-05
6E-07
Lawrence Berkeley Lab., CA
5,000,000
3E-
-04
5E-07
Paducah Gaseous Diff. Plant, KY
500,000
1E-
-05
4E-07
Lawrence Livermore Lab./Sandia
5,300,000
1E-
-03
3E-07
Livermore Lab., CA
Portsmouth Gaseous Diff. Plant, OH
620,000
9E-
-05
2E-07
Argonne National Lab., IL
7,900,000
8E-
-05
1E-07
Pinellas Plant, FL
1,900,000
2E-
-04
1E-07
Nevada Test Site, NV
3,500
3E-
-06
IE-07
Knolls Lab-Kesslring, NY
1,200,000
3E-
-05
1E-07
Battelle Memorial Inst., OH
1,900,000
3E-
-06
2E-08
Fermi National Lab, IL
7,700,000
1E-
-06
2E-08
Sandia National Lab./Lovelace, NM
500,000
8E-
-06
1E-08
Bettis Atomic Power Lab, PA
3,100,000
1E-
-06
1E-08
Knolls Lab-Windsor, CT
3,200,000
2E-
-06
8E-09
Rocky Flats Plant, CO
1,900,000
9E-
-06
1E-08
Pantex Plant. TX
260,000
7E-
-08
4E-09
Knolls Lab-Knolls, CT
1,200,000
10E-
-07
3E-09
Ames Laboratory, IA
680,000
9E-
-08
4E-10
Rocketdyne Rockwell, CA
8,800,000
7E-
-08
2E-11
Source: [EPA89]
6-4
-------
Emissions from Oak Ridge Reservation are composed primarily of Xe-133, H-3 and Kt - 85. The
major release point is the central disposal facility source stack composed of three internal sources of
radioactive exhaust, each with its own emission control technology. Practical control technologies
require that the effluents be removed from low flow rate air streams which will require installation
prior to the centralized stack.
The Savannah River Plant is used primarily to produce plutonium and tritium for use in the
production of nuclear weapons. The largest sources of emissions are the fuel reprocessing areas, the
three production reactors, and the heavy water rework plant. Tritium is released from six of
Savannah's facilities while Argon-41 is released exclusively from the operating reactors in roughly
equal proportions. Carbon-14 is released from the three operating reactors and the separation plants
in roughly equal proportions. Tritium is the principal source of radiation dose to the off-site
population.
Current controls at the Savannah River Plant utilize a continuous monitoring system to detect levels
exceeding a specified limit. When emissions exceed the threshold limit the air flow is diverted to a
Hopcalite stripper and zeolite beds for tritium removal. The efficiency level of the controls varies
with operating conditions which cannot be reported for security reasons. Emission from the
production reactors consists of a system of prefilters to remove particulates from the incoming air,
moisture separators, HEPA filters, and charcoal filters for iodine removal.
Feed Materials Production Center produces uranium metal and other materials for DOE facilities.
Raw materials are dissolved in nitric acid and separated by liquid organic extraction. The recovered
uranium is reconverted to uranyl nitrate and processed further to become uranium tetraflouride.
Purified metal is made by reacting the uranium tetraflouride with metallic magnesium in a
refractory-lined vessel. These processes result in estimated lifetime fatal cancer risks to nearby
individuals of 3E-5. Risks of fatal cancers to the population residing within 80 km is 3E-3 deaths
per year. The number of persons living within 80 km of Feed Materials Production Center is 3.3
million.
The estimated risk levels for regional populations are shown in Table 6-2 for the baseline conditions,
Only the Savannah River Plant and the Oak Ridge Reservation cause more than 1E-2 fatal cancer
deaths per year. The maximum individual risk of 2E-4 was due to emission released from Los
Alamos Laboratory in New Mexico. The risks for the other facilities are progressively less,
Individual facility dosage levels are estimated and may be found in the supporting documentation
[EPA89].
6-5
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6.3.3 Control Technologies
The Los Alamos National Laboratory has a multiplicity of sources and emissions which are subject
to further controls. The Meson Physics Facility which utilizes a linear proton accelerator could
reduce its emissions by about 95 percent by using a holding tank approach at a cost of about $1.6
million in capital and $90,000 per year for operations.
The Oak Ridge Reservation has several components which are technically subject to supplementary
controls including the Central Radioactive Gas Disposal Facility (CRGDF), various processes of the
Y-12 plant, and the diffusion plant's purge cascade. Controls for tritium emitted in water vapors
from CRGDF are feasible and can achieve 90 percent efficiency, at a capital cost of $1.66 million.
Uranium-234 and -238 emissions can be further controlled by a second stage of HEP A filters which
retain a 99 percent efficiency rate in series mode or can achieve a 99.95 percent efficiency in a
primary control mode. The capital cost of adding HEPA filters to the fabrication facility is estimated
to be $2.65 million. The increased power requirements and the cost of HEPA filter replacement will
increase operating costs by about $92,000 per year. Significant additional costs may be incurred if
there are additional structural requirements.
The Savannah River Plant could improve the collection efficiency of a number of elements of its
operations. The 200-H area tritium facilities could reduce their normal emissions by 25 percent
through the use of a palladium catalyst and the recycling of effluent gases through the stripper in
combination with hydrogen swapping. The cost of these enhancements would be about $65 million
with an expected system life of 15 years. A procedure that could reduce tritium emissions from
production reactor area stacks by up to 90 percent after an extended period of steady state operations
(about six years) is the use of vapor phase catalytic exchange with cryogenic distillation. Gross costs
estimates for this process range from $20 to 40 million plus annual operating costs of $1.5 to 2 million
with a 30 year system life. Emissions from the separation plants which are quite small could be
subject to further controls. Carbon-14 can be captured by an absorber system based on flaked
barium hydroxide octahydrate. The noble gases (particularly Kr-85) could be captured by one of
several processes using cryogenic distillation, fluorocarbon absorption, or absorption on mordenite
beds, all of which have a decontamination factors of about 100. Such off-gas treatment systems are
estimated to cost $50 million per plant plus $3 million for operation annually.
The Feed Materials Production Center is discussed in chapter seven. Improvements to the current
controls can be made by using Goretex bags instead of wool bags in its dust collection system coupled
6-6
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with continuous stack monitoring and administrative controls. HEPA filters could also be used as a
supplementary control for particulates.
6.4 Analysis of Benefits and Costs
6.4.1 Introduction
Four alternatives for controlling radionuclide emissions were evaluated. The first two had no effect
on either costs or benefits. The third alternative is to require controls on any facility from which
the emissions exceed 3 mrern/y EDE (effective dose equivalent). Oak Ridge National Laboratory and
Los Alamos National Laboratory would both have to install controls to meet alternative 3. Alternative
4 is to require controls on all facilities from which emissions exceed 1 mrem/y EDE. Savannah River
and FMPC would have to install controls to meet alternative 4, So would Oak Ridge and Los
Alamos, since alternative 4 is more stringent than alternative 3. Controls that would reduce emissions
below 1 mrem/y at all four facilities are considered in the following.
Emissions estimates were made for all the facilities, both with and without the supplementary
controls, where appropriate. Estimated dose equivalents and associated fatal cancer risks were also
estimated. Some of these control technologies are not well demonstrated for these source types and
may require further developmental efforts. Other supplementary controls are well established and
not costly, but may provide only minor additional benefits. Some controls are not strictly speaking
controls, but avoidance or minimization of initial contamination or activation and improved
administrative or engineering procedures. Table 6-3 provides the risks to the 80 km population and
to the most exposed individual both before and after installation of supplementary controls. Table
6-4 shows which controls are included in the analysis, the net present value (NPV) of their cost
stream, and the decrease in risk to both the 80 km population and the most exposed individual.
6.4.2 Cost of Control Technologies
The control evaluated at Los Alamos National Laboratory was an atmospheric pressure storage system
that delays the release of emissions until some products can break down. The estimated capital cost
is $1,600,000 and the operating cost is $90,000. The NPY of these costs over a 25 year period, with
a discount rate of 5 percent, is $2,792,000.
At Oak ridge the controls evaluated were combinations of HEPA filters and high-energy venturi
scrubbers at three emission sources with capital costs of $800,000, $400,000 and $1,450,000 and
6-7
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Table 6-3: DOE Facilities Fatal Cancer Risks With and Without Supplementary Alternative 4
Controls
Annual Risk to
BO km Population
Maximum Individual Risk
Without
Controls
With
Controls
Without
Controls
With
Controls
Los Alamos Natl. Lab.
4E-3
2E-3
2E-4
2E-5
Oak Ridge Reservation
3E-2
7E-3
8E-5
2E-5
Savannah River Plant
2E-1
8E-2
7E-5
2E-5
FMPC
8E-4
9E-4
3E-5
1E-5
TOTALS:
2E-1
9E-2
MAX: 2E-4
2E-5
6-8
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Table 6-4; Controls, Risk Reduction, and Costs Associated With Meeting Alternative 4, by Facility
Facility
Decrease in
Regional
Population
Risk
Decrease in
Maximum
Individual
Risk
Estimated Control Cost in Thousands
Supplemental
Control
Capital
Operating
NPV
Discount Rate = 5%
25 Years
Los Alamos 2E-3
National
Laboratory
Oak Ridge 2E-2
Savannah 1E-1
River
FMPC IE-4
TOTAL; 9E-2
2E-4 Atmospheric
Pressure Air
Storage System
6E-5 HEPA Filter,
Venturi Scrubber,
Tritiated Water
Sieve Dryer
5E-5 Vapor Phase
Catalatic Exchange
with Cryogenic
Distillation,
Integrated Off-Gas
Treatment System
2E-5 HEPA Filter
$1,600
$4,310
$130,000
$4,200
$240,110
$90
$92
,000
$111
$8,293
$2,792
$5,401
$236,561
$5,564
$250,319
6-9
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operating costs of $29,000, $13,000, and $50,000 per year respectively. At a fourth emission source
a tritiated water/ sieve dryer system would be installed with a capital cost of $1,600,000 and no
operating cost. Capital costs for supplementary controls at Oak Ridge total $4,310,000 and operating
costs total $92,000 annually. The NPV for supplementary controls at Oak Ridge is $5,401,000.
Supplementary controls evaluated at Savannah River include a vapor phase catalytic exchange with
cryogenic distillation and an integrated off-gas treatment system. The first has an estimated capital
cost of $20 to 40 million, taken here to be $30,000,000, and operating costs of approximately
$2,000,000 per year. The second supplementary control has a capital cost of $50,000,000 per plant
and an operating cost of $3,000,000 per year per plant. Two plants would be fitted with this control
for a total capital cost of $100,000,000 and a total operating cost of $6,000,000 per year. The total
for all supplementary controls required to meet alternative 4 at the Savannah River Plant is
$130,000,000 for capital cost and $8,000,000 annually for operating costs. The NPV of the
supplementary controls required by Savannah River to meet alternative 4 is $236,561,000.
To meet the requirements of alternative 4, FMPC will require installation of HEPA filters at a capital
cost of $4,200,000 and an operating cost of $111,000 per year. The NPV of these costs is $5,564,000.
These estimates do not consider structural modifications that might be needed in order to install the
filters.
For all four plants the total capital cost of meeting the requirements of alternative 4 is estimated to
be $140,110,000 and the yearly operating cost to be $8,293,000. The aggregated NPV of these costs
evaluated with a five percent discount rate over a twenty-five year assumed life expectancy is
$250,319,000, The NPV is somewhat insensitive to the choice of discount rates, varying from
$347,435,000 when the rate is zero to $202,649,000 when the rate is ten percent.
6.4.3 Health and Other Benefits
The health benefits of supplementary controls are estimated through the application of computer
models of emission dispersion and the resulting inhalation and ingestion of various radioactive
constituents and their effect on the body. Table 6-3 presents summary information on both the 80
km population and the maximum individual risk of fatal cancer due to the four facilities analyzed
here with and without supplementary controls required to meet alternative 4. In preparing these
estimates, detailed organ exposures are calculated for each facility. The risk to nearby individuals
and to regional populations of fatal cancer is also documented (EPA89], The level of maximum
6-10
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individual risk ranges from a high of 2E-4 at Los Alamos to a low of 3E-5 at FMPC. With
supplementary controls, the greatest maximum individual risk drops to 2E-5. The aggregated risk
for 80 km populations drops to from 2E-1 to 9E-2 when alternative 4 is implemented.
6,5 Industry Cost and Economic Impacts
Since the costs of these control actions will be borne by the Federal government there is no assignable
direct private industry cost. If controls were implemented at any of these facilities, the major burden
would be in the form of higher taxes, increased government debt, or reduction in other government
services.
6-11
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REFERENCES
EPA89 Risk Assessment, Vol. 2.
6-12
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CHAPTER 7
DEPARTMENT OF ENERGY RADON FACILITIES
-------
7. DEPARTMENT OF ENERGY RADON SITES
7.1 Introduction and Summary
Five Federal facility sources of potential radon exposure are reviewed. Four of the five
facilities are no longer active, but are repositories of previously discarded radioactive residues
from uranium mining, mills, uranium metal production, assaying and storage of uranium
materials. The fifth facility, the Feed Materials Production Center near Fernald, Ohio,
continues to produce purified uranium metal and components for DOE facilities.
Estimates of radon emissions and flux rates are indicated as are the associated risks to the
population from these emissions. The costs of further control of these emissions are estimated
and the associated benefits are evaluated.
Seven fatal cancers every century are attributable to the operation of these facilities. Over
half of these cancers can be traced to the Middlesex Sampling Plant.
7.2 Industry Profile
The Department of Energy (DOE) Radon source category consists of five sites owned or
controlled by the Federal government and operated or maintained under the authority of
DOE. These five sites are described in [EPA84], They contain significant quantities of
radium-bearing wastes and are:
o Feed Materials Production Center (FMPC),
o Niagara Falls Storage Site (NFSS),
o Weldon Spring Site (WSS),
o Middlesex Sampling Plant (MSP), and
o Monticello Uranium Mill Tailings Pile (MUMT).
7-1
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7.2.1 Feed Materials Production Center (FMPO
The FMPC is located near Fernald, Ohio, and is currently operated under contract by
Westinghouse Materials Company of Ohio for the DOE. The facility produces purified
uranium metal and components for use at other DOE facilities. The feed materials include
ore concentrates, recycled uranium from spent reactor fuel, and various uranium compounds.
Thorium can also be processed at the site. The primary source of radon emissions at the
FMPC is pitchblende residues stored in two concrete storage tanks referred to as silos. The
residues resulted from the recovery of uranium from pitchblende ores during World War II.
7.2.2 Niagara Falls Storage Site CNFSS>
The NFSS, located in Lewiston, New York, is a DOE surplus facility operated by Bechtel
National, Inc. The 77 ha site is part of the former Lake Ontario Ordnance Works and is
used solely for storage of uranium and pitchblende residues. The residues were formerly
stored in six buildings that were originally part of the facility's water treatment plant and in
a pile nearby. Subsequently, by the end of 1986, the residues were consolidated in the Interim
Waste Containment Facility (IWCF).
Descriptions of the consolidation process can be found in the annual environmental reports
[BEC87], The IWCF structure comprises the short-term closure system for the wastes until
the long-term management plan is completed. The selected long-term plan calls for in-place
management as described in the final environmental impact statement [DOE86]. The IWCF
occupies 4 ha of the site and measures 274 m by 137 m. The structure's outer perimeter is
composed of a dike and cutoff wall, both of which are constructed of compacted clay which
forms a finished structure with an engineered compacted clay cover that sits directly over the
wastes and extends beyond the perimeter dike. This cover is the principal barrier against
moisture intrusion and radon emanation. The 0.9 m of clay is covered with 0.3 m of general
soil and 0.15 m of top soil.
7.2.3 Weldon Spring Site fWSS)
The WSS, located near Weldon Spring, Missouri, is a surplus DOE facility that also stores
uranium and thorium wastes. The site was operated by Bechtel National, Inc. in a caretaker
status until 1986 when M-K. Ferguson Company assumed control as Project Management
7-2
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Contractor for the WSS Remedial Action Project. The site consists of two separate properties:
the 89 ha Weidon Spring Chemical Plant together with the Weidon Spring Raffinate Pits
form one (WSCP), and the other is the 3.6 ha Weidon Spring Quarry (WSQ) area, which is
about six kilometers southwest of the raffinate pits.
The raffinate pits area is a remnant of the Weidon Spring Chemical Plant. The pits received
residues and waste streams from uranium mining operations and washed slag residues from
uranium metal production. Pits one and two contain neutralized raffinates from these sources
while pits three and four contain similar wastes plus thorium-contaminated raffinate solids
from processing thorium recycle products. Surface water covers pits three and four
continuously, but pits one and two may be occasionally exposed due to seasonal evaporation.
The quarry site was initially used to dispose of radioactive thorium in drums, and
subsequently thorium-contaminated building rubble, process equipment, and contaminated
equipment. The Army also subsequently disposed of TNT-contaminated stone and earth to
cover these thorium residues and finally, in 1969, placed contaminated equipment and rubble
from the chemical plant in the pits.
7.2,4 Middlesex Sampling Plant fMSP)
The MSP site of Middlesex, New Jersey, was used by the Manhattan Engineering District
and the Atomic Energy Commission between 1943 and 1967 for sampling, weighing, assaying,
and storing uranium and thorium ores. Upon termination of operations, the site was
decontaminated and released to the U.S. Marine Corps for use as a training center.
Radiological surveys of the site and nearby private residences revealed contamination from
windblown materials and use of materials as fill. DOE took responsibility for the site and its
cleanup, which was completed in 1982.
The Middlesex Municipal Landfill also required remedial action, which was initiated in 1984
and completed in 1986. The contaminated materials were consolidated in storage piles, which
are surrounded by concrete curbing and covered with a hypalon material to prevent the
movement of materials.
7-3
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7.2.5 Monticello Uranium Mill Tailines fMUMH Pile
The MUMT pile is located in Monticello, Utah, and has been inactive since 1960.
Approximately 817,000 tons of uranium mill tailings were impounded in four separate areas.
The Federal government purchased the mill in 1948. It was subsequently operated by the
Atomic Energy Commission until 1960 when it was permanently shut down. The tailings
were stabilized in 1961 by grading, leveling and diking. The tailings were then covered with
0.3 m of grave! and another 0.3 m of soil, which was seeded. Further demolition and
decontamination activities were conducted in 1974 and 1975 to reduce radiation levels and
improve the site's appearance but cover on the site remains poor. The 1986 environmental
monitoring report concludes that the EPA standard for a flux rate of 20 pCi/m2/sec is
exceeded at all of the tailings piles [SE87J.
7.3 Current Emissions, Risk Levels, and Feasible Control Methods
7.3.1 introduction
Current emissions are a function of source types, concentrations of contaminants, and current
control methods. Risk levels are a function of the emission levels, release points,
demographic and meteorological factors, and the pathways for exposure or ingestion.
Estimates of exposure and lifetime fatal cancer risks are given for people living near the
facilities and those within an 80-kilometer radius. These risks are summarized in Tables 7-1
and 7-2. [EPA89] Supplementary control options and costs are also noted.
7.3.2 Current Emissions and Estimated Risk Levels
In the following sections the best available estimates of current emissions and risk levels are
presented for each facility.
7-3.2.1 Feed Materials Production Center
The residues stored at FMPC are estimated to have a radium concentration of 0.2 ppm or
about 200,000 pCi/g radium-226. The estimated 11,200 kg of residues contain about 1,760
Curies of radium. A report determined that the facility is within DOE and EPA guidelines
and regulations for the emission of radon, but additional radon control was recommended to
meet the dose standards in Subpart A of 40 CFR 191 should cracking in the silos occur
7-4
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Table 7-1: Exposures and risks to nearby individuals from
Facility
DOE Radon Sites.
Maximum
Exposure
(WL)
Maximum
Lifetime
Fata!
Cancer
Risk
FMPC
1.5E-6
2E-6
NFSS
1.8E-7
3E-7
WSS-WSCP
1.3E-4
2E-4
WSS-WSQ
5.6E-5
8E-5
MSP
1.0E-4
1E-4
MUMT
9.7E-4
IE-3
Source: [EPA89]
7-5
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Table 7-2:
Estimated Fatal Cancers Per Year In the Regional
(0-80 km) Populations Around DOE Radon Sites.
Fatal
Cancers
Facility Population Per Year
FMPC 3,200,000 6E-4
NFSS 3,800,000 4E-5
WSS-WSCP 2,300,000 7E-3
WSS-WSQ* 2,300,000 3E-3
MSP 16,000,000 5E-2
MUMT 19,000 8E-3
Total " 25,300,000 7E-2
* WSS-WSCP and WSS-WSQ affect the same 80 km population.
Source: [EPA89]
7-6
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[Gr87], Measurements were made of radon flux emissions from the silos in 1984 and 1985,
but subsequent structural improvements have had a significant impact on the emission levels.
Therefore, no current valid emission information is available,
Radon-222 release rates were estimated at 2.5 Ci/yr based upon the radium content of the
residues and a calculated flux rate through the concrete domes and foamed exterior [Na 85).
The estimated radon flux rate is 85 pCi/m2/sec. The cancer risk to the most exposed
individual is about 2E-6.
7.3.2.2 Niagara Falls Storage Site
The NFSS consolidated the wastes on a 4 ha site at the IWCF. Radon measurements at the
site boundary during 1986 range between 0.17 and 0.36 pCi/1, including background. The
background level was monitored at 0.31 pCi/1. Measured flux rates for radon are not
available from the pile. The current estimated releases as stated in the closure/post-closure
plan are 0.25 Ci/yr. The estimated radon flux rate consistent with this annual estimate is 0.06
pCi/m2/sec. The risk for the most exposed individual is about 3E-7.
7.3.2.3 Weldon Spring Site
The WSS's environmental radon monitoring program covers 31 sites. The boundary radon
monitors at WSCP read between 0.18 and 0.49 pCi/1, including background. The readings
from the background location were measured at 0.47 pCi/1, while off-site monitors north of
the pits and closer than the background monitors recorded levels of 0.22 to 0.36 pCi/1. The
on-site monitors at the raffinate pits and the quarry ranged between 0.31 and 0.64 and 0.24
and 1.86 pCi/1, respectively. The estimated release rates of Radon-222 are 29 Ci/y for the
WSCP and 14 Ci/y for the WSQ. The estimated radon flux rates are 2.7 pCi/m2/sec at WSCP
and 3.7 pCi/m2/sec at WSQ. The cancer risk to nearby individuals is estimated at 2E-4 for
WSCP and 8E-5 for WSQ.
7.3.2.4 Middlesex Sampling Plant
Samples of the piles at the MSP show concentration of 40 pCi/g of radium-226.- There are
twenty monitors at the MSP, and one off-site background monitor. The monitoring reports
indicate that the range of readings are 0,3 to 1.2 pCi/1, including background, at MSP, with
the background site registering 2.0 pCi/1. The off-site location is apparently at a higher
7-7
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radiation level than the site itself. The radon flux rates are not available, but are estimated
based on a source strength of 1 pCi/g of radium-226 resulting in 1 pCi/m2/sec of radon-
222, This results in an estimated radon flux rate of 40 pCi/m2/sec. Given the dimensions
of the waste piles, this converts to 25 Ci/yr not accounting for attenuation by the hypalon
cover. The risk level for nearby individuals is 1E-4.
7.3.2.5 Monticello Uranium Mill Tailings Pile
The MUMT was found to exceed the EPA standard for radon flux of 20 pCi/m2/sec at each
of the four tailings piles. Radon emission measurements range from 133 to 765 pCi/m2/sec
for these piles and a portion of the pile has migrated by as much as 500 m off-site. The
average flux rate of the material that has migrated is 40 pCi/m2/sec or 37 Ci/yr. The
estimated radon flux rate averaged over all the piles is 228 pCi/m2/sec. The total radon-222
release is estimated by DOE at 1,595 Ci/yr [SE87], This facility has the highest lifetime fatal
cancer risk for nearby individuals of the five facilities considered in this chapter; 1E-3.
7-3.3 Control Technologies
Each of the five facilities was evaluated for supplementary controls and costs that would be
required to reduce the radon emissions to levels of 20, 6, and 2 pCi/m2/sec. This cost
estimation assumed that all wastes remain at their current sites, that the current storage
configurations would be maintained, and that the wastes would be covered with dirt to
sufficient depth to reduce the radon emissions to the target levels.
The radon emission rate from the two FMPC silos, using the estimated 2.5 Ci/y source term
is calculated to be 85 pCi/m2/sec. The FMPC would require 2.1, 2.3, and 3.3 meters of dirt,
costing $56,000, $79,000, and $83,000, respectively, to meet the target levels of 20, 6, and
2 pCi/m2/sec.
The NFSS's current rate of radon flux of 0.25 Ci/yr is equivalent to 0.06 pCi/m2/sec which
is below the lowest target level; therefore, there are no additional costs to meet these goals.
Currently the pits and quarry at WSS contain water which keeps radon fluxes at the relatively
low levels of 2.7 and 3.7 pCi/m2/sec respectively. Therefore the flux rates meet the target
levels of 2 and 6 pCi/m2/sec without controls. However, before dirt can be applied to the
7-8
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pits, they must be dried out. When this is done, the flux rate increases to 460 pCi/m2/sec at
pits 1, 2, and 3 and to 11 pCi/m2/see at pit 4. The control flux rates were calculated
assuming that the pits and quarry are dry. Earth cover of 1.6, 2.3, and 2.8 meters would be
required to reduce the emission rates to 20, 6, and 2 pCi/m2/sec, respectively for pits 1, 2,
and 3. Pit 4 needs no cover to meet 20 pCi/m2/sec, and .3 and .9 meters to meet 6 and 2
pCi/m2/sec, respectively. The associated costs are $1.73, $2.96, and $4.26 million. Control
techniques have not been devised to achieve alternate radon levels for the quarry site.
The MSP site would require 0.8, 1.4, and 2.1 meters of dirt, with associated costs of $419,000.
$720,000, and $997,000 respectively, to meet the target levels of 20, 6, and 2 pCi/m2/sec.
Covering the MUMT piles exhibited the highest costs, requiring 2.4, 3.4, and 4.4 meters of
earth to meet the target levels of 20, 6, and 2 pCi/m2/sec at costs of $26.8, $39.2, and $50.2
million, respectively.
7.4 Analysis of Benefits and Costs
7.4.1 Costs and Benefits of Meeting Various Radon Flux Rates
The analysis considers only the incremental costs relative to the baseline of supplementary
controls to meet the target emission levels of 20, 6, and 2 pCi/m2/sec. The benefits are
estimated as the number of fatal cancers avoided and the reduction in maximum individual
risk by applying supplementary control measures to meet the three target emission flux rates.
Proportional reductions in the emission rates are converted into proportional reductions in the
risks. The benefits are estimated by calculating the nearby and regional (up to 80 kilometers
distance) population exposure to the radionuclides. The population exposure levels and risks
of fatal cancers are a function not only of the emissions and their controls, but also of the
population distribution in the vicinity of the facility, the meteorology, farming and food
distribution and consumption patterns, atmospheric transport of the contaminants, and the
inhalation or ingestion pathways.
The controls for four of the five facilities are assumed to be completed within one year.
Implementation of controls for the fifth facility, the Niagara Fails Storage Site (NFSS), is
expected to take ten years, but explicit control costs were not provided since the current
emission flux rates are already well below the lowest target levels and, as mention above, the
7-9
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interim remedial actions would temporarily increase the emission levels and the number of
fatal cancers. The following paragraphs present the findings of the analysis for each of the
facilities. Table 7-3 summarizes the benefits and costs of supplemental control measures
needed to meet a flux rate of 20 pCi/m2/sec. Table 7-4 provides the same measures for a
flux rate of 6 pCi/m2/sec and Table 7-5 for one of 2 pCi/m2/sec.
7.4.1.1 Feed Materials Production Center
The FMPC facility is estimated to have an emission flux rate of 85 pCi/m2/sec resulting in
a fatal cancer risk rate of 6E-4 per year [EPA89]. The costs of further reducing the emissions
to a target level of 20 p€i/m2/sec is estimated at approximately $56,000, which would be
expended in a single year to cover the wastes with a greater depth of dirt. On an annualized
basis, given a discount rate of five percent, the cost would be $2,800 per year for one
hundred years.
7.4.1.2 Niagara Fails Storage Site
The NFSS facility, as stated above, is the one facility that is already well below the target
emission rates. The current emission strength of 0.25 Ci/yr translates into an equivalent
radon flux of 0.06 pCi/m2/sec which is three percent of the lowest target level of 2.0 and 0.3
percent of the highest target level of 20 pCi/m2/sec, If the proposed remedial actions were
taken, the emission levels would sharply increase for a period of ten years, thereby increasing
the total numbers of cancers for the first 100 years by a factor of nearly ten, from 6.0E-3 to
4.6E-2. No costs of this remedial action were estimated since the facility already meets the
target emission levels.
7.4J.3 Wcldon Soring Site
The WSS facility is composed of four pits at the WSCP site and a quarry, the WSQ, at another
location with varying emission rates that also fluctuate due to seasonal weather patterns. The
WSCP has an estimated radon flux of 2.7 pCi/m2/sec and WSQ one of 3.7 pCi/m2/sec.
Together they generate a fatal cancer risk of 11-2 per year or approximately 1 fatal cancer
in a century. The WSCP pits are filled with water much of the time. When dry they would
release radon at a flux rate of 460 pCi/m2/sec at pits 1, 2, and 3 and 11 pCi/m2/sec at pit 4.
Dirt depths of up to three meters would be required to reduce the flux rates of the dried out
7-10
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TABLE 7-3:
Costs and reduced Risks Resulting
Flux Rates to 20 pCi/nT2/sec
from Covering
the Sources to
Lower Radon
| Estimated j
| initial Radon |
| Flux Rate |
[ (pCi/m~2/sec) |
i
i
i _
Annual Fatal Cancers in
80 km Population
[
| Maximum Individual
I
Risk |
faciIi ty
i
Control Costs |
Resultant j
Averted
I
[ Resultant |
I
Reduction |
FMPC
1 85 |
i 1
1"
$56,000 j
I
1E-04 |
I
5E-04
1 ------1
| 5E-07 |
I i
I
2E-06 |
NFSS
1 [
| 0.06 [
i i
1
$0 |
1
I
4E-05 |
i
QE+00
1 1
| 3E-07 |
I 1
I
OE+00 |
WSS-USCP*
1 [
| 199.6 |
1 i
1
$1,730,000 )
i
4E-02 |
1
-3E-02
1 1
| 1E-03 J
l i
I
-9E-04 |
WSS-WSQ**
1 [
1 3.7 |
{ |
1
HA |
1
3E-03 |
QE+00
I I
| 8E-05 |
I
0E+Q0 I
MSP
1 [
1 i
1
$419,000 |
1
3E-02 j
26-02
I I
| 8E-05 |
I
26-05 |
HUM!
1 1
I 228 |
I
$26,800,000 |
1
7E-04 |
7E-03
I I
| 1E-04 |
I
9E-04 |
TOTAL: [
$29,005,000 |
TOTAL: |
7E-02 |
TOTAL:
-46-03
| MAXIMUM: |
| 1E-03 |
MAXIMUM: |
9E-04 |
* Based on flux rates with pits dried out. Note that flux rate is currently
2.7 pCi/m*2/sec due to water cover. The risks therefore exceed the initial risks.
** No control has been devised for WSS-WSQ.
[Source: Calculations by JFA]
7-11
-------
TABLE 7-4: Costs and reduced Risks Resulting from Covering the Sources to Lower Radon
Flux Rates to 6 pCi/m~2/sec
Estimated
Initial Radon
Flux Rate
(pCi/m'2/sec)
1
1
Annual Fatal Cancers in |
80 km Population j
Maximum Individual
R i sk |
Feci Iity
Control Costs |
Resultant |
i
Averted |
Resultant j
Reduction |
FMPC
- --
S5
"1"
$79,000 |
I
1
3E-05 |
t
r
6E-Q4 |
1
1
1E-Q7 |
i
2E-06 |
NfSS
0.06
1
$0 j
I
4E-05 |
I
0E+00 1
1
3E-07 |
OE+OO |
WSS-USCP*
199,6
1
$2,960,000 j
1
2E-02 j
I
-9E-03 |
1
4E-04 |
•2E-04 j
WSS-WSQ*
3.7
1
NA |
1
3E-03 |
I
1
0E+00 j
i
1
8E-05 |
1
0E+Q0 |
KSP
40
1
$720,000 |
t
9E-03 |
1
1
4E-02 |
1
2E-05 |
8E-05 |
MUMT
228
1
$39,200,000 i
1
2E-04 t
!
8E-03 |
I
3E-05 |
1
1E-03 )
TOTAL; (
$42,959,000 j
TOTAL: [
3E-02 |
TOTAL; |
4E-02 [
MAXIMUM: |
4E-Q4 |
MAXIMUM: |
16-03 |
* Based on flux rates with pits dried out. Note that flux rate is currently
2.7 pCi/m*2/sec due to water cover. The risks therefore exceed the initial risks.
No control has been devised for WSS-WSO.
[Source: Calculations by J FA]
7-12
-------
[Source: Calculations by JFA3
TABLE 7-5:
Costs and reduced Risks Resulting
Flux Rates to 2 pCi/m~2/sec
from Covering
the Sources to
Lower Radon
j Estimated |
j initial Radon |
| Flux Rate |
|
-------
pits to as low as 2 pCi/m2/sec for pits 1, 2, and 3, Pit 4 would require a cover of up to one
meter to meet this lowest target level. There is insufficient information to develop a cost of
achieving the supplementary control target levels for the quarry site [DGE88]. Once the pits
are dried out and the higher fluxes are occurring, the total cost of supplementary controls
sufficient to meet the target level emission rate of 20 pCi/m2/sec at the pits is $1,730,000,
while the annualized payment is $87,000. This would actually increase emissions and risk
to the population and to the most exposed individual. Reducing the flux to 2 pCi/m /sec
would reduce risks. This would cost $4,260,000.
7.4.1.4 Middlesex Sampling Plant
The MSP facility's emission rate is estimated at 40 pCi/m2/sec, causing an estimated 5E-2
fatal cancers per year. Supplemental controls that meet the target emission rates would
reduce the fatal cancer risks to between 3E-2 and 3E-3 per year. The supplemental control
cost is between $419,000 and $997,000.
7-4.1.5 Montlcello Uranium Mill Tailings Pile
The MUMT piles have an estimated emission rate of 228 pCi/m2/sec, which could result in
an estimated 8E-3 fatal cancers per year. The least stringent of the control levels (20
pCi/m2/sec) would reduce the number of fatal cancers per year to 7E-4, while maintaining
flux levels at 2 pCi/m2/sec would further reduce the number of deaths by a factor of ten.
The supplemental control costs would be $26,800,000.
7-4.2 Sensitivity Analysis
Tables 7-3, 7-4, and 7-5 presented data regarding the costs and benefits of meeting various
flux rate standards at each facility. In the following, the effects of changing the flux rate
standard and the social discount rate are demonstrated.
Tables 7-6 and 7-7 demonstrate that there is a small national benefit of reducing the target
flux rate to 6 pCi/m2/sec or to 2 pCi/m2/sec. The first additional increment would provide
four fewer fatal cancers nationally per century and the second two fewer.
7-14
-------
Table 7-6: Reductions in Emissions and Cancer Rates Attributable to Controls: U.S. Total.
Flux Rate Related Cancers Averted Cancers
(pCi/m2/sec) (per year) (per year)
Baseline 7E-2 —
20 1E-2 -4E-3
6 3E-2 4E-2
2 1E-2 6E-2
(Source; Calculations by J FA}
7-15
-------
Table 7-7: incremental Costs and Risk Reductions for Various Flu* Standards
Flux Standard | Total Control
CpCs/m*2/sec> | Cost
j I Incremental
j Fatal Cancers j Reduction in
Incremental | Averted | Fatal Cancers
Control Cost | (per 100 yr) j (per 100 yr)
Baseline
20
6
2
$0
$29,005,000 | $29,005,000
I
$42,959,000 | $13,954,000
I
$55,540,000 | $12,581,000
01*00 I
1
— |
i
-4E-01 |
1
i
-4E-01 |
I
4E+00 |
1
I
46+00 |
1
61+00 j
I
2E*00 |
[Source: Calculations by JFA3
7-16
-------
The other factor in the costs and benefits analysis of section 7.4.1 was the question of
discounting the costs to compute net present value. Table 7-8 demonstrates that for a 20
pCi/m2/sec flux rate standard, calculation of NPV of the cost of national requirement of
supplementary controls does not vary at all. This is because the costs are all at the beginning
of the 100 year period of analysis, where changes in discount rates have no effect.
7.5 Industry Cost and Economic Impact Analysis
Since the costs of these control actions will be borne by the Federal government, there is no
assignable direct private industry cost. Only the FMPC is currently operating; the other four
facilities are now surplus or storage facilities solely and therefore do not raise on-going
capital or operations and maintenance costs.
7-17
-------
Table 7-8:
Net Present Value of Cost of Supplemental Controls to Meet a Flux
of 20 pCi/m2/see at DOE Radon Facilities: U.S. TOTAL.
NPV
RATE (in millions of dollars)
0% 29.0
1% 29.0
5% 29.0
10% 29.0
Note: Values rounded to one decimal place.
[Source: Calculations by JFA]
7-18
-------
REFERENCES
Bec86 Bechtel National, Inc., Closure/Post-Closure Plan for the Interim Waste
Containment Facility at the Niagara Falls Storage Site, DQE/OR/2G722-
85, Oak Ridge, Tennessee, May 1986.
Bec87 Bechtel National, Inc., Niagara Falls Storage Site, Annual Site
Environmental Report, Calendar year 1986, DOE/OR/20722-150, Oak
Ridge, Tennessee, June 1987.
DOE86 U.S. Department of Energy, Final Environmental Impact Statement, Long-
term Management of the Existing Radioactive Wastes and Residues at the
Niagara Falls Storage Site, DOE/EIS-0109F, April 1986.
DOE87 U.S. Department of Energy, Draft Environmental Impact Statement,
Remedial Action at the Weldon Spring Site, DOE/EIS-0117D, February
1987.
EPA84 U.S. Environmental Protection Agency, Background Information Document
for Final Rules, Volume II, Appendix C, Radon Emissions from Department
of Energy and Nuclear Regulatory Commission-Licensed Facilities, EPA
520/1-84-022-2, Washington, D. C„ October 1984.
EPA89 Risk Assessments, Vol. 2.
Gr87 Grumski, Joseph T., Feasibility Investigation for Control of Radon
Emissions from the K-65 Siios, Feed Materials Production Center,
Westinghouse Materials Company of Ohio, July 30, 1987.
Se87 Sewell, Michael, and Larick Spencer, Environmental Monitoring Report on
Department of Energy Facilities at Grand Junction, Colorado, and
Monticello, Utah, for calendar year 1986, UNC/GJ-HMWP-2, UNC, Grand
Junction, CO, March 1987.
Na85 Nazaroff, W. W., et al., Atmospheric Environment, 19:1:31-46, (1985).
7-19
-------
CHAPTER S
ELEMENTAL PHOSPHORUS
-------
8. ELEMENTAL PHOSPHORUS PLANTS
8.1 Introduction and Summary
The Elemental Phosphorus Plant source category consists of five operating and three standby facilities
that produce elemental phosphorus by the electric furnace method. These plants have been evaluated
in previous EPA assessments under Section 112 of the Clean Air Act and are subject to the NESHAP
(40 CFR 61, Subpart K) promulgated on February 5, 1985. The NESHAP established an emissions
limit of 21 Curies per year (Ci/y) for polonium-210 (Po-210) released from calciners and nodulizing
kilns.
This chapter updates the assessment made during the 1983-1985 radionuclides NESHAPS rulemaking
period (EPA84), Revisions have been made where necessary to reflect the changes in emissions or
control technology as reported to the EPA under provisions of the NESHAP. It also incorporates the
exposure and risk assessments for two idle plants in Florida that were not addressed in the risk
assessment of the 1984 rulemaking.
The five plants currently producing elemental phosphorus are owned by Monsanto Company, FMC
Corporation, Rhone-Poulenc (Stauffer), S.A., and Occidental Petroleum Company, The current
radionuclide emissions at each of these plants have been measured and current emissions control
technologies have been evaluated. The feasibility of various emission control technologies was
evaluated and the performance and cost of these alternatives evaluated.
Current emissions at each of the five operating plants are estimated as listed below:
Units: Ci/y
Facility
FMC
Monsanto
Stauffer, MT
Stauffer, TN
Occidental
Po-210
Pb-210
10.
1.4
0.74
0.28
0.31
0,14
0.35
0.1)
0.058
0.064
8-1
-------
These emissions are estimated to result in a national cancer incidence rate of 8E-02 per year (see
section 8-3). Various alternatives for reducing both radionuclide emissions and risks are evaluated
in the current study. A summary of these alternatives is presented in the table below. For each of
nine different Po-210 emissions levels and for four combinations of control technologies, costs and
benefits - measured in cancers per year - were determined. The first set of alternatives are based
on emission levels ranging from 10 Ci/y of Po-210 to 0.01 Ci/y. In addition, four alternatives were
evaluated that apply different combinations of control technologies to different plants. These are
based on the size (measured in terms of annual elemental phosphorus production capacity) of the five
plants under consideration.
Sumnarv of
Alternateves
I
ncr eisenta I
Total
1nc rement a I
Total
A I ternati ve
t nc i dence
Inc;deuce
I ncidence
Annua t i zed
Annua I'
Codjct ion
Reduction
Cost
Cost
EMISSIONS LEVELS
I .
<10.0
Ci/y)
8E -02
- -
I t .
<2.0
Ci/y >
3E -02
5E-02
5E- 02
2.43
2 .43
! t t .
<1.0
Ci/y)
2E-02
7E-03
6E-02
2.74
5.17
I V .
<0. 75
Ci/y>
2E-02
:'5'i - 03
6E-02
1.30
6.47
V .
<0.60
Ci/y)
1 E - 02
56-03
6E-02
1 .52
7.99
V I ,
<0.20
Ci/y)
4E-03
8E-03
7E-02
4 . 34
12 .33
VII.
<0.10
Ci/y)
3 E - 03
9E-04
7E-02
15,59
27.92
VIII
. <0.06
Ci/y)
1 E - 03
21-03
8E-02
0 .39
28.31
I X .
<0.01
Ci/y)
3E - 04
8E - 04
8E-02
3.28
31.59
CONTROL TECHNOLOGIES
I .
8E-02
X ,
3£ - 02
5E-02
5E-02
2.43
2.43
X I ,
2E - 02
7E-03
5E-02
2.35
4 . 78
XII.
7E -03
16-02
7E - 02
12-70
17.48
XIII
•
8E - 04
6E - 03
8E - 02
12.02
29.50
i .
No Additional Emissions
Control Requ
i r ed
X .
High
Energy
Scrubbers on
Large Plants
X I .
High
Energy
Scrubbers on
All Plants
XII.
fabric filters on Large
Plants; High
Energy Scrubbers on
Others
XIII
HE PA
F i Iters
on Large Plants; 600 SCA Precipitators on Others
This chapter is divided into four sections. The following section, 8.2, is a profile of the elemental
phosphorus (P6) industry. It is followed by a description of current radionuclide emissions, risk levels
8-2
-------
and feasible control methods. Section 8.4 outlines both the reductions in risks and the increases in
costs that could result from the installation and operation of these various control technologies on the
different plants. The final section describes potential economic impacts.
8.2 industry Profile
Production of elemental phosphorus (P4) in the United States utilizes about 10 percent of all
phosphate rock mined annually. Elemental phosphorus is used principally as an intermediate in the
production of high purity phosphoric acids and salts as well as a variety of phosphorus chemicals for
industry and home use. The major derivatives of elemental phosphorus are detergent phosphate
materials, mainiy sodium tripolyphosphate (STPP).
8.2.1 Demand
U.S. production of elemental phosphorus peaked in 1969 at 623 thousand short tons (tons), then
declined steadily to a low of 359 thousand tons in 1985. In 1986, production of elemental phosphorus
totalled about 364 thousand tons, a one percent increase over 1985, but a 42 percent decrease from
1969. Production in 1987, however, was only 343 tons [MCP85]. Plant production and shipments
between 1964 and 1987 are listed in Table 8-1.
The manufacture of thermal or furnace grade phosphoric acid accounts for approximately 85 percent
of domestic elemental phosphorus consumption. Other chemicals, principally phosphorus
pentasulfide, phosphorus pentoxide, and phosphorus trichloride use over 10 percent. Direct uses,
miscellaneous chemicals and alloys consume less than 5 percent [MCP85], A chart of the intermediate
and end products of the elemental phosphorus industry is provided in Table 8-2 below.
Phosphorus is used principally as an intermediate in the production of high purity phosphoric acids
and salts, as well as a variety of phosphorus chemicals for industry and home use. Detergent
phosphate materials, chiefly sodium tripolyphosphate (STPP), are the major commercial derivatives
of elemental phosphorus. Commercial phosphates also include other sodium phosphates, and calcium
and potassium phosphates, used in a variety of detergents, cleaners, personal care products, water
treatment and food. The detergent market is comprised of household detergents (85 to 90 percent)
and industrial detergents (10 to 15 percent). Accounting for over 60 percent of elemental phosphorus
use in 1970, detergent applications have since declined because of environmental concern regarding
the role of phosphorus in eutrophication.
8-3
-------
Table 8-1: Production and Shipment of Elemental Phosphorus -- 1964-1987 (Toas).
Total Shipments
Including
Interplant
Year
Production
Transfers
1987
343,329
-
1986
363,717
324,665
1985
359,196
319,700
1984
386,063
342,155
1983
365,622
326,319
1982
361,189
360,472
1981
426,067
376,262
1980
431,730
429,462
1979
459,541
462,259
1978
441,274
442,619
1977
430,291
423,620
1976
436,655
425,374
1975
449,506
424,305
1974
524,175
497,612
1973
525,523
488,527
1972
540,089
502,197
1971
545,089
502,197
1970
596,555
549,920
1969
622,982
567,997
1968
613,343
567,531
1967
587,006
536,166
1966
565,550
512,583
1965
555,368
512,459
1964
503,880
452,324
Source: Bureau of the Census, U.S. Department of Commerce, Current Industrial Reports:
Inorganic Chemicals, annuals, 1968,-1987, Table 1.
8-4
-------
m
3
o to
CQO
OS
iW
oo
B
8-5
-------
Controls or bans on the use of phosphates in detergents have been in place for some time in New
York, Indiana, Michigan, Wisconsin, Minnesota, Connecticut, and Maine. In the past two years,
the District of Columbia, Virginia, Maryland, and North Carolina have restricted phosphate use,
South Carolina, Oregon and Illinois are considering phosphate bans. Phosphate-containing detergents
are now unavailable to about 30 percent of the U.S. population and to 100 percent of Canada's
[CW88J]. The use of STPP in detergents has dropped from 1.4 billion pounds in 1980 to 1.2 billion
pounds in 1985, and is predicted to fall to 1.1 billion pounds by 1990 {CVV88j].
Metals treating is a second major end use of elemental phosphorus. Valuable in controlling corrosion,
phosphorus is used in aluminum polishing and paint bases. Demand for phosphorus in metals treating
depends heavily on demand for automobiles and durable goods, the major end users of these
products, and thus tends to fluctuate with the business cycle. For example, with a slump in the
automobile and other consuming industries between 1979 and 1980, consumption of elemental
phosphorus products by these industries fell by 25 to 33 percent [CEN84, CEN81].
A third major market for elemental phosphorus is the food and beverage industry. Phosphoric acid
is used in soft drinks, powdered drinks, baby foods, puddings, baking powder, and dentrifices, for
example. Demand for these products has grown slowly in the past decade, but has been below the
industry's forecasts, possibly because of the decline in sales of cakes and cookies as part of the
national trend toward physical fitness, and a reformulation of soft drinks [CEN83, CEN81],
Chemical derivatives of phosphorus, other than phosphoric acid, at 10 percent of consumption, are
equal to the food and beverage industry in importance to the elemental phosphorus market. Current
uses include lubricating oils, insecticides, flame-resistant textile finishes, matches, and
pharmaceuticals. In the last half of the 1970s, these uses were considered the market with the highest
growth potential. Some companies added capacity during the period to produce pentasulfide,
trichloride, and oxychloride phosphorus compounds, which are then used in agricultural chemicals,
lubricating oil additives, and many other products. However, growth in these uses has been impeded
by the longer life of lubricating oils, and competition from substitute products. Furthermore, though
in the early 1980s producers increased investment in R&D. no new significant uses of phosphorus
products have been discovered. Growth in non-acid uses has been about 3 percent per year since the
middle 1970s [CEN81, CEN78],
8-6
-------
The export market is the only other major consumer of U.S.-produced elemental phosphorus. Most
countries that have a continuing requirement for phosphorus produce it domestically, largely because
water transportation requires extensive precautions. However, exports have accounted for some 5 to
7 percent of U.S. elemental phosphorus production since the middle of the 1970s [CEN84, CEN79).
In 1986, most of the 22 thousand short tons (6.1 percent of production) of elemental phosphorus
exports were destined for Japan (42 percent), Brazil (32 percent), Mexico (14 percent), and Taiwan
(7 percent) [MY87],
Annual U.S. consumption of elemental phosphorus appears to have dropped to a plateau in the range
of 325 to 350 thousand tons per year. Some industry observers expect long term domestic demand
to increase at up to 2 percent per year. More pessimistically, U.S. demand will remain essentially
unchanged or decline slightly. Consumption would decline if the ban on phosphate detergents were
accentuated or if organophosphate pesticides were to lose additional market share. Most other
applications, such as use in metal finishing and flame retardants, will probably have relatively static
demand patterns, subject to swings in the overall economy [CEN84],
8.2.2 Supply
In 1988, four corporations operated a total of five elemental phosphorus plants in the United States.
The largest producer is FMC Corporation (1 plant), followed by Rhdne-Poulenc, which purchased
2 Stauffer Chemical plants in 1987, Monsanto (1 plant) and Occidental (1 plant). The corporations,
plants, capacity, and plant employment are listed in Table 8-3.
Elemental phosphorus producers are vertically integrated which means that most of the P4 produced
is used captively downstream in other company operations. All producers operate phosphate rock
mines in the vicinity of their elemental phosphorus plants. After manufacturing the elemental
phosphorus, producers ship it to burning plants, where it is converted to other chemicals for use in
consumer and industrial products. For example, elemental phosphorus produced at FMC's Pocateilo
plant is shipped to five other plants for production of phosphorus-based chemicals [FMC86]. The
mix of chemicals produced varies, depending on the producer's cost and market structure. Table 8-4
presents the location of and phosphorus chemical production capacity at the various downstream
plants of each company.
8-7
-------
Table 1-3: Elemental Phosphorus Producers and Estimated Capacity.
Producer
Plant Location
Capacity
(1987 tons/year)
Employment
(1987, est.)
FMC
Poeatello, ID
137,000
650
Monsanto
Soda Springs, ID
95,000
400
Rhdne-Pouleoc-'
Mt. Pleasant, TN
Silver Bow, MT
45,000
42,000
305
190
Occidental
Columbia, TN
57,000
275
TOTAL
376,000
1,820
-fln September, 1987, Rhdse-Poulenc, a French company, acquired the inorganic chemicals
businesses which had belonged to the Stauffer Chemical Company,
Source: Industry Information
8-8
-------
table 8-4: U.S. Copacltlaa for FfaoBphorun and FteoKpboniB Chemicals - 1915.
(thousands of short: tons)
Company and
Plant Location
Thermal
Phosphoric
Phosphorus Acid
(P4 Basis) (P4 Basis)
Basic Inorganic Intermediates
Sodium
a/
ALBRIGHT & WILSON, IHC._
Charleston, SC
Fernald, OH
FHC
Carteret, HJ
Green River, Wi —
Lawrence, KS
Newark, CA
Hitro, wv
Pocatello, ID 137
MONSANTO
Annieton, AL —
Augusta, GA
Carondelet, MO --
Columbia, IN 78
Kearny, HJ «—
Long Beach, CA
Milwaukee, Ml —
Sauget, m
Soda Springs, ID 95
Trenton, MI --
OCCIDENTAL
Columbia, US
Godwin, TK 57
Jefferson, IS
Miller, TX
Hiagara Falls, SY —
CKBSKBROOGH-POHD'S < STAOFPER)
Chicago, it
Chicago Heights, II.
Cold Creek, AL --
Gallipolis Perry, KV
Morrisville, PA —
Kt. Pleasant, OT 45
Bashville, TO
Richmond, CA
Silver Bow, MT 42
Tarpon Springs, Ft
TOTAi 454
8
15
26
33
51
52
36
36
36
29
3
47
11
21
21
15
26
26
18
9
529
PCI.3 P2S5 p2°5 Hypophosph
(elemental phosphorus (P4) Basis) (P4 Basis
hate
>
12
38
l.l
1.8
32
4.1
1.6
3.4
a/
Albright a Wilson, Ina.'s thermal acid and phosphorus chemicals plants
were purchased by Albright £ Wilson, Ltd. (subsidiary of Tenneco, Inc.)
Mobil Corporation early in 1985.
from
Sourcei (SRIB6]
8-9
-------
With recent flat demand and little future growth expected, capacity for elemental phosphorus has
been reduced. It is unlikely that facilities previously closed in Florida in the early 1980s will be
restarted, since electric power costs, which account for about 20 percent of total production costs,
are significantly higher there than in Tennessee and in the Northwest. Capacity in Tennessee was
also reduced as demand weakened. Most recently, in 1986, Monsanto shut down its plant in
Columbia, TN.
With the various shutdowns and consolidations, the real U.S. capacity for elemental phosphorus has
dropped, from its peak of 686,000 tons in 1969, to about 360,000 tons at the end of 1987 [MCP85].
Capacity in the industry from 1964 to 1987, by producer, is presented in Table 8-5.
All elemental phosphorus producers in the U.S. are major corporations, with the smallest corporation,
Stauffer, ranked in 1985 as number 235 in Fortune's list of the 500 largest U.S. Companies. Since
the acquisition of Stauffer's inorganic chemical operations by Rhone-Poulenc in 1987, FMC, ranked
in 1987 as number 131 in Fortune's list, is the smallest corporation producing in the U.S.
Elemental phosphorus represents a relatively small portion of the total revenues from corporate
production, ranging from an estimated 0.5 percent for Occidental to 5.6 percent for FMC (Table
8-6). Since elemental phosphorus is an intermediate good consumed in other company products,
however, its importance to company operations is more significant than revenues would indicate.
The operating and market characteristics of each producer are described below.
8.2.2.1 Monsanto Company
In 1985, Monsanto, with a total of 168,000 tons per year of operating capacity in two elemental
phosphorus plants, was the largest producer of elemental phosphorus. The Soda Springs, Idaho plant,
with three furnaces, was built in the middle and late 1960s and rated at 90,000 tons per year of
capacity. The Columbia, Tennessee plant, with six furnaces, was constructed in the 1940s and
modernized in the 1960s [SK186]. Originally rated at 134,000 tons per year, operating capacity was
reduced to 78,000 tons [CEN84], This plant was shut down in 1986, leaving Monsanto with only
95,000 tons per year operating capacity.
Monsanto is the most diversified producer of elemental phosphorus, dominating in most of the
nonagricultural markets. The company has been aggressive in developing new markets and upgrading
8-10
-------
Table 8-5: Elemental Phosphorus Production Capacity.
PRODUCER CAPACITY (Thousands of Tons per Year)
1964
1966
1969
1972
1975
1978
1981
1985
1987
i989a/
AAC, Pierce, FlJ^
40
30
22
11
11
20
20
_c/
-
-
FMC, Pocatello, ID
75
100
145
145
145
145
145
137
137
137
Occidental, Columbia, TN
69
69
70
45
57
57
57
57
57
57
Occidental, Niagra Falls, NY
6
-
-
-
-
-
-
-
-
-
Monsanto, Columbia, TN
110
110
135
135
135
120
134
78
-
.
Monsanto, Soda Springs, ID
40
80
110
110
110
110
95
95
95
95
Rhdae-Poulenc, Mt. Pleasant, TN
80
80
63
55
45
45
45
45
45
45
Rh6ne-Poulenc, Silver Bow, MT
30
30
42
42
42
37
37
42
42
42
Rhdne-Poulenc, Tarpon Springs, FL
13
13
23
25
25
23
23
-
-
TVA, Wilson Dam, AL
36
36
40
18
36
-
.
-
-
-
Mobil, Charleston, SC
8
10
8
-
-
-
-
-
-
Mobil, Nichos, FL
6
6
4
5
5
8
-
_
-
-
Mobil, Mt. Pleasant TN
-
20
24
-
-
-
-
-
-
-
TOTAL
513
584
686
591
610
565
556
454
376
376
? .SRI estimate
—^Producer became Continental Oil (1966), Agrieo (1972), Holmes (1975), Electro-Phos (1978), and Mobil (1981).
£ - represents no production.
Sources: [SRI86J, [CMR81] and Industry Information
-------
Table 8-6: Revenues from Elemental Phosphorus Production and Total Corporate Revenues (1986).
Estimated
Elemental
Phosphorus
Revenue-'
(in millions)
Total
Corporate
Revenue
(in millions)
Elemental
Phosphorus
as a Percent of
Total Revenue
FMC
Monsanto
Rhdne-Poulenc
Occidental
$174,7
$121.1
$110.9
$72.7
$3,078.9
$6,879.0
$8,107.8
$15,525.2
5.7%
1.8%
1.4%
0.5%
TOTAL
$479.4
$33,590.9
1.4%
-^Estimated revenue = estimated production x price
Estimated production = 85 percent of capacity
Price = $0.75 per pound or $1,500 per ton
Revenue for Rhdne-Poulenc = 51,642 FF x $0.157/FF
8-12
-------
P4 to high-value specialty products. The company's share of each end use market within the
industry, and the share of each end use within the company's line of phosphorus products, are listed
in Tables 8-7 and 8-8 [SRI80].
The value of production from Monsanto's elemental phosphorus plants in 1983 is estimated to have
amounted to $199,5 million (Table 8-6), or 1,7 percent of total corporate revenues of $6,879.0 million.
8.2.2.2 FMC Corporation
The second largest American producer of elemental phosphorus is FMC Corporation. FMC operates
a single plant, with four furnaces and an operating capacity of J37,000 tons per year, in Pocatello,
Idaho. Furnaces in the plant are maintained on a rotating schedule in which each furnace is
completely refitted or rebuilt every six to eight years [SRI83],
Phosphate rock for FMC's elemental phosphorus plant is obtained from low grade shale at the Gay
mine, a mine operated jointly by FMC and Simplot, The entire FMC share (80 percent) of the Gay
mine's output is used to produce elemental phosphorus. With the Gay mine expected to be depleted
by 1990, FMC will probably shift its mining to land it has leased or subleased from Federal and State
governments in Caribou County, Idaho. The company is believed to hold all the permits required for
this change [SRI86]. Simplot operates the mine and supplies FMC with 1.5-1.6 million tons of 53-54
percent BPL furnace grade rock per year,
FMC's largest market area for its elemental phosphorus products is in builders and water treatment
for detergents, with other market areas small by comparison. Details of FMC's market position are
provided in Tables 8-9 and 8-10 [SRI83J.
In 1986, the value of elemental phosphorus production for FMC was approximately $174.7 million,
or 5.7 percent of total corporate revenues of $3,078.9 million (Table 8-6).
8.2.2.3 Rlione-I'oulenc fStaufferl
The subject of numerous acquisitions in recent years, the Stauffer Chemical Company has changed
completely since 1985, Effective March 15, 1985, Chesebrough-Pond's, Inc., a $3 billion per year
producer of toiletries and food products, acquired Stauffer for approximately $1.3 billion. At the
8-13
-------
Table i-7: Elemental Phosphorus Market Share; Monsanto.
Products
Acid Uses
Builders and
Water Treatment
Foods, Beverages, and
Toothpaste
Metals Treating
Exports, Other
Non-Acid Uses
TOTAL
Share of
Monsanto's
(1982)
(%)
50
14
2
19
15
100
Share of
Industry Market-'
(1982)
(96)
35
34
9
35
35
29
-'in 1982, part of the market for elemental phosphorus was held by wet-process acid producers and
by Mobil, a furnace acid producer who is not currently in the market. Thus, market shares for the
producers discussed here do not sum to 100 percent.
Table §»$ Monsanto's Position in Phosphorus Markets -- 1984.
Thermal Acid and
Derivative Products
Percent
of Total
Company P^
72
Percent of Total
U.S. Market
Basis
32-35
Non-Acid Uses
PCL,
P9S
Sodium Hypophosphate
4
5
30
34
Export, Other 19 74
TOTAL 100 38s/
-^Estimated company share of total U.S. elemental phosphorus market.
Source: [SR.I86]
8-14
-------
Table 8-9: Elemental Phosphorus Market Share: PMC.
Products
Acid Uses
Builders and
Water Treatment
Foods, Beverages, and
Toothpaste
Metals Treating
Exports, Other
Non-Acid Uses
TOTAL
Share of
FMC's Phosphorus Product
(1982)
<%)
62
8
4
20
6
100
Share of
Industry Market ¦
(1982)
38
16
14
9
12
28
Table 8-10: FMC's Position in Phosphorus Markets -- 1984.
Percent
of Total
Company P4
Thermal Acid and
Derivative Products
90
Percent of Total
U.S. Market
P^ Basis
35
Non-Acid Uses
PCL-i
P->S
p24
Sodium Hypophosphate
3
4
18
24-26
Export, Other
TOTAL
3
100
10
32^
-^Estimated company share of total U.S. elemental phosphorus market.
Source: [SRI86]
8-15
-------
end of 1986, Chesebrough-Pond's was acquired by Unilever, Ltd., a $24 billion per year
Dutch-British conglomerate. In July 1987, Imperial Chemical Industries, PLC, bought Stauffer
Chemical from Unilever for $1,69 billion in cash. Finally, in September, 1987, Rhone-Poulenc, S.A.
of France, acquired Stauffer's inorganic chemicals businesses, which had sales of $540 million and
employed 3,600 people in 1986, from Imperial Chemical Industries for $522 million. This acquisition
made Rhone-Poulenc the biggest producer of specialty phosphates and regenerated sulfuric acids in
the world.
The most recent publicly available information on Rhone-Poulenc's P4 operations was published by
SRI International in February 1986. At that time, these operations belonged to Stauffer, Therefore,
the following presentation of company data is presented using Stauffer's name. It is worth noting
that Rhone-Poulenc also purchased the name Stauffer. Both plants continue to use the Stauffer name.
The third largest American producer of elemental phosphorus is Stauffer Chemical Company, with
two plants and an annual capacity of 87,000 tons. Stauffer's Mt. Pleasant, Tennessee plant has five
furnaces and capacity of 45,000 tons per year. The Silver bow, Montana plant has two furnaces and
capacity of 42,000 tons per year.
The source of phosphate rock for Stauffer's Tennessee plant is the company's Globe mine in Mt,
Pleasant, which is operated at about 0.4 to 0.5 million metric tons per year of ore and, in 1985, had
reserves for 10-15 years of elemental phosphorus production. The sources of rock for the Montana
plant are mines in Woo ley Valley, Idaho, Wyoming, and Utah. The first is the primary source, with
45 million metric tons of reserves in 1980. All rock mined by Stauffer in Tennessee is used to
produce elemental phosphorus. A portion of the rock mined in the western states is sold to other
users, possibly to phosphate producers in Canada [SRI86].
Stauffer is considered the second most diverse producer of elemental phosphorus. In the early 1970s
when environmental concerns were mounting, Stauffer turned its focus away from the laundry
detergent market to produce phosphorus compounds for end-use areas that at the time were more
highly valued. One such product is chlorinated trisodium phosphate, a cleanser and bacteriocide used
in dishwashing compounds and metal cleaners. The company is expected to continue its focus on
these areas, plus food uses and miscellaneous phosphorus chemicals. The market position of Stauffer
in each end-use area is indicated in Table 8-SI and 8-12 [SRI83]. In 1986, the value of production
8-16
-------
Table 8-11: Elemental Phosphorus Market Share: Stauffer.
Products
Acid Uses
Builders and
Water Treatment
Foods, Beverages, and
Toothpaste
Metals Treating
Exports, Other
Non-Acid Uses
Share of
Stauffer's Phosphorus Product
(1982)
(%)
Neg.
35
3
31
31
Share of
Industry Market
(1982)
(%)
Neg.
50
8
25
29
TOTAL
100
16
Table 8-12: Stauffer's Position in Phosphorus Markets -- 1984.
Thermal Acid and
Derivative Products
Percent
of Total
Company P^
74
Percent of Total
U.S. Market
P4 Basts
17
Non-Acid Uses
PCL,
P,S
rk
Sodium Hypophosphate
7-8
8-9
2
24
27
28-30
50-52
35-40
Export, Other
TOTAL
6
100
12
18a/
-'Estimated company share of total U.S. elemental phosphorus market.
Source: [SRI86]
8-17
-------
from Stauffer's elemental phosphorus plants was estimated to equal $109.4 million. This represents
1.3 percent of Rhone-Poulenc's total revenues of $8,107.8 million (Table 8-6).
8.2.2.4 Occidental Petroleum Corporation
The smallest producer of elemental phosphorus is Occidental Petroleum, with one three-furnace plant
in Columbia, Tennessee. The annual capacity of the plant is 57,000 tons.
Occidental uses captive washed rock (61-62 percent BPL) obtained from a local mine where the
company owns 2,300 acres of reserves. In 1980, the reserves were estimated at 8 to 10 million metric
tons, with about 12 to 14 years of remaining life [SRI86].
Occidental's market has been dominated by builder phosphates manufactured at facilities in Texas
and Indiana. Little change is expected in the next few years, though some decline in the company's
position in phosphorus pentasulfide (P2Ss) products has occurred due to the entry of FMC into this
market. As of 1985, Occidental had ceased production of P2S5, but was tolling P4 through another
P2Sj producer to supply its customers. As these contracts expire, Occidental will phase out its P2S5
business. The position of Occidental in each end-use market is detailed in Tables 8-13 and 8-14
[SRI86],
In 1983, elemental phosphorus is estimated to have contributed $71.7 million to Occidental's total
corporate revenues of $15,525.2 million, or 0.5 percent (Table 8-6). The company is known to have
attempted to sell its industrial phosphate operations in the early 1980s, but has since renewed its
power contract through 1993 [SRI86],
8.2.3 Competitive Products and Processes
Consumption of elemental phosphorus in detergents, the major end use of elemental phosphorus,
has been affected significantly by the availability of substitutes. With the controls or bans on
phosphates recently imposed in some states, and threat of regulation by others, detergent
manufacturers have reformulated their products, replacing phosphorus with carbonates, silicates,
citrates, zeolites, NT A and nitrilotriacetic acid. Sodium carbonate (soda ash) is used in markets that
have completely banned phosphorus. Though relatively inexpensive, sodium carbonate is less effective
in cleaning than sodium tripolyphosphate (STPP), sometimes leaving residues on fabrics and being
8-18
-------
Table 1-13: Elemental Phosphorus Market Share: Occidental.
Share of Share of
Occidental's Industry Market
Products (1982) (1982)
(%) (%)
Acid Uses
Builders and
Water Treatment 60 15
Foods, Beverages, and
Toothpaste Neg. Neg.
Metals Treating 5 8
Exports, Other 23 14
Noa-Acid Uses 12 10
TOTAL 100 14
Table 8-14: Occidental's Position in Phosphorus Markets -- 1984,
Percent Percent of Total
of Total U.S. Market
Company P^ P4 Basis
Thermal Acid and
Derivative Products 77-80 10-11
Noa-Acid Uses
PCL3 4 8
P2Ss 6 12
P2CJ5 2 20-22
Sodium Hypophosphate 2 40-45
Export, Other 8 4
TOTAL 100 11*'
-¦'Estimated company share of total U.S, elemental phosphorus market.
Source; [SR186J
8-19
-------
less thorough as a soil deflocculant, (FMC and Stauffer are among the producing firms). Citrates
are another viable alternative. With their high solubility characteristics, citrates have become the
major builder used in heavy-duty liquid laundry detergents. However, citrates may cake when
prepared in powders and thus are not attractive substitutes in powder formulations.
A third product competing with STPP for use in detergents is zeolites, sodium aluminosilicates that
soften water by ion exchange. Alone, zeolites are not as effective as STPP in cleaning, but are often
combined with it to produce a builder system with lower phosphate content. Since 1978, zeolites have
become commercially significant. The fourth challenge to STPP in detergents is NT A. In 1970, use
of NTA as a builder was voluntarily suspended in response to an unpublished government report
suggesting the compound was teratogenic. In 1980, EPA issued a statement that NTA posed no threat
to human health. NTA is now considered among the most attractive alternatives to STPP.
Another source of competition for the elemental phosphorus industry is the phosphoric acid produced
from phosphate rock through wet process methods. Wet process acid has historically been less pure
than acid produced from elemental phosphorus (called thermal process acid). When thermal acid costs
and prices were low, it was not economical for wet process acid producers to purify their product to
compete with the thermal acid. However, the increasingly high costs and prices of thermal acid have
opened some traditional markets to wet process acid manufacturers who can now produce comparably
pure acids at a competitive price. For example, Olin Corporation, a wet acid producer, had a seven
percent share of the market for phosphorus in detergents in 1984.
8.2.4 Economic and Financial Characteristics
The major economic and social factors affecting demand for phosphorus derivatives are population
growth, GNP growth, and to a lesser extent, demand for certain durable goods.
The largest end use for elemental phosphorus, detergents, has historically grown about one percent
per year, approximately equal to population growth. With the controls on phosphates imposed in
some states and subsequent reformulation of detergents, this use declined in the 1970s. By 1981,
demand appeared to have restabilized at a one percent per year growth rate [CEN81J.
Demand for phosphorus in food and beverages has reached maturity and closely follows changes in
GNP. Historically, the use of oil additives has grown at GNP rates or less. Uses in metal treating
8-20
-------
are more cyclical, fluctuating with demand for durable goods, especially automobiles [CEN84,
CEN78J.
8.2.4.1 Prices
Most (approximately 80 percent) elemental phosphorus is used captiveiy to produce phosphoric acid
and derivatives. The meaning of the price data available for elemental phosphorus is, therefore,
somewhat ambiguous. Manufacturer and co-producer transfer values are considerably below the list
price published by the manufacturers of 90 to 100 cents per pound.
Table 8-15 compares the published list price and the actual average trading price for P4 from 1960
to 1984. In 1983 and 1984, the list price is 30 percent higher than the average sales price. Because
it is probably more representative of the real price, the average sales value has been used in the
calculation of corporate elemental phosphorus revenues; an estimate of $0.75 per pound or $1500
per ton was selected.
Because the market for P4 is a slow-growth market, and because most P4 is sold captiveiy within each
company, it is expected that these prices, stable since 1983, will continue within the same range
throughout the 1980s.
8.2.4.2 Employment
In 1987, approximately 1,820 persons were employed directly by the elemental phosphorus industry.
Employment in each state is listed in Table 8-16. Estimated employment in each plant was listed
in Table 8-3. Direct employment in the elemental phosphorus industry represents only a part of
the employment that could be affected by a change in demand for elemental phosphorus. Others
potentially affected would include phosphate rock miners and workers in other phosphorus chemical
manufacturing facilities.
8.2.5 Outlook
Current forecasts for the elemental phosphorus industry indicate low growth and weak prospects for
industry expansion. Major factors leading to the forecast are increasing costs of production,
8-21
-------
Table 8-15: Average Price Range -- Phosphorus -- White.
(Cents per Pound -- FOB Plant)
Price 1960 1965 1970 1975 1980 1982 1983 1984 1985 JJM 1988
Trade List 19 19 19 53 80 80 90 91 91 91 91
Avg. Sales" 16 15 15 45 61 68 70
Average sales values include captive mterplant transfers, no merchant market pricing.
Source: [MPC85]
8-22
-------
Table 8-16: 1987 Employment by Slate fer lie Elemental Pfeegphenis Industry.
Number of
State Employees
Idaho 1,050
Tennesee 580
Montana 190
8-23
-------
competition from substitutes, consumer and social trends, and lack of new uses for elemental
phosphorus and its derivatives.
Changes in the cost of elemental phosphorus in recent years have been largely influenced by
electricity costs, which have been increasing steadily and are expected to continue to increase. The
increased cost of phosphorus and its derivatives has made substitutes more attractive. Substitutes in
detergents, such as zeolites, NTA, and wet process phosphoric acid, are attractive both economically
and because of environmental concerns and. in the case of zeolites and NTA, restrictions on
phosphate use. Other uses of elemental phosphorus are deterred by substitutes and/or social factors.
Phosphate-containing insecticides, a small market for the industry which had been growing at about
JO percent per year, face competition from non-phosphate insecticides. Uses in lubricating oils are
increasing, but the lubricating oils are also lasting longer, offsetting the gains. Detergent uses
resumed a slight upward trend in 1981-1984, but are still threatened by growth in consumer use of
liquid detergents, trends toward lower washing temperatures, and use of zeolite builders in place of
phosphates in formulas. As mentioned previously, bans on phosphates have been imposed, removed,
and re-imposed in some states. Additional states may join New York, Indiana,.Michigan, Wisconsin,
Minnesota, Connecticut, and Maine in banning or controlling phosphates. In the past two years, the
District of Columbia, Virginia, Maryland, and North Carolina have restricted phosphate use. South
Carolina, Oregon and Illinois are considering phosphate bans. On the brighter side for detergent uses
are the continued consumer demand for the new concentrated detergent powders, which have high
concentrations of phosphates, and demand for phosphates in industrial detergents, which has been
growing in the 1980s at 3 percent per year or greater [CEN84, CEN82],
8.3 Current Emissions. Risk Levels, and Feasible Control Methods
The Elemental Phosphorus Plant source category consists of eight facilities that produce elemental
phosphorus by the electric furnace method. In 1988, five of these plants were operating, while three
were not. These plants have been evaluated in previous EPA assessments under Section 112 of the
Clean Air Act, and are subject to the NESHAP (40 CFR 61, Subpart K) promulgated on February
5, 1985. The NESHAP established an emissions limit of 21 Curies per year (Ci/yr.) for polonium-
210 released from calciners and nodulizing kilns. This analysis examines alternative standards for
emissions of radionuclides from calcining operations in the manufacture of elemental phosphorus.
8-24
-------
Radionuclides of the uranium series, including polonium 210 (Po-210), lead (Pb-210), and uranium
238 (U-238), occur naturally in phosphate rock. The exhaust gases from phosphate rock nodulizing
calciners at elemental phosphorus plants are considerably enriched with radionuclides because the Po~
210 and Pb-210 volatize at the elevated temperatures in the calciner. As the exhaust gases cool, the
radionuclides condense on the surface of mineral particulate matter or condense to form new
particles. In the absence of adequate particulate controls, these emissions are vented to stacks for
release to the atmosphere. The EPA conducted emission tests at several elemental phosphorus plants
to characterize and quantify uncontrolled particulate and radionuclide emissions from the calciners
and controlled emissions from the existing control systems.
Emissions of particulate matter and condensed radionuclides from these plants can be reduced by the
application of modern particulate control technology. Presently, low pressure drop scrubbers are
being used to reduce emissions of particulate matter from the nodulizing calciners. Emission control
efficiencies for these low-pressure drop scrubbers are relatively low compared to those for high
pressure drop scrubbers, wet electrostatic precipitators (ESP), or fabric filters (baghouses). These
more efficient devices could potentially be used to control particulate and condensed radionuclide
emissions from calciners at elemental phosphorus plants.
8.3.1 Current Emissions and Estimated Risk Levels
The following section includes a description of the elemental phosphorus production process, of
existing effluent controls and of current radionuclide emissions. In addition, there is a brief
examination of various technologies available for the control of these emissions as well as a
presentation of the cost of purchasing, installing and maintaining them.
8.3.1.1 Process Description
Volume 2 of the Environmental Impact Statement (EPA89] and the supporting report on Airborne
Emission Control Technology for the elemental phosphorus industry [SAI84] provide detailed data on
each plant, including design, operation, source and radionuclide content of phosphate rock processed,
and analyses of particulate and radionuclide emissions from various parts of the processing.
Recently, Midwest Research Institute completed a study entitled, Characterization and Control of
Radionuclide Emissions from Elemental Phosphorus Production, that updates the information
8-25
-------
contained in SAI84. These documents provide a more detailed discussion of the elemental phosphorus
industry and are incorporated by reference.
Crushed and screened phosphate rock is fed into calciners and heated to the melting point, about 1300
degrees C. After calcining, the hot nodules are passed through coolers and into storage bins prior to
being fed into electric furnaces, The furnace feed consists of the nodules, silica and coke.
Phosphorus and carbon monoxide (CO) are driven off as gases and vented near the top of the furnace.
Furnace off-gases pass through dust collectors and then through water spray condensers where the
phosphorus is cooled to the molten state. The mix of phosphorus and water (phossy water) and mud
are then processed to recover the phosphorus. Clean off-gases from the condensers contain a high
concentration of CO and are used as fuel in the calciners.
8.3.1.2 Existing Effluent Controls
Emissions from the calciners are typically controlled by low energy scrubbers. Since the 1984
assessment of this source category, one plant has upgraded its caiciner emission controls by installing
a high energy scrubber system. Emissions from nodule coolers, transfer points and furnace tap holes
are controlled by either fabric filters or wet scrubbers. Screening plant emissions are usually
controlled by fabric filters. Fugitive dust and radon gas emissions are not controlled.
8.3.1.3 Emissions
Through the period 1975 to 1980, EPA measured the radionuclide emission rates from three elemental
phosphorus plants: FMC in Pocatello, Idaho [EPA77], Stauffer1 in Silver Bow, Montana [An8ia],
and Monsanto in Columbia, Tennessee [An81b]. Measurements were made from release points
representative of all major process operations in the production of elemental phosphorus.
All the emitted radionuclides are released as particulates except for radon-222, which is released as
a gas. Essentially all the radon-222 and greater than 95 percent of the lead-210 and Po-210 emitted
from these facilities are released from the caiciner stacks. The high calcining temperatures volatize
1The Stauffer Chemical Company is currently owned by Rhone-Poulenc, S.A. Because Rhone-
Poulenc also acquired the name, Stauffer, the company's elemental phosphorus plants have retained
this name.
8-26
-------
the Pb-210 and Po-210 from the phosphate rock, resulting in release of much greater quantities of
these radionuclides than of the uranium, thorium and radium radionuclides. Analyses of doses and
risks from these emissions show the emissions of Po-210 and, to a lesser degree emission of Pb-210
to be the major contributors to risk from radionuclide emissions from the elemental phosphorus
plants.
In 1983, EPA conducted extensive additional radionuclide testing at the FMC plant in Pocatello
[EPA84c, Ra84a] and at the Stauffer plant in Silver Bow [EPA84d, Ra84b]. In early 1984, limited
emission testing was done at the Monsanto plant in Soda Springs, Idaho [EPA84e, Ra84c]. This
testing was limited to calciner off-gas streams and focused primarily on Pb-210 and Po-210 emissions
in order to obtain additional information on these emissions and to obtain data on particle size
distribution and lung clearance classification of these radionuclides in the calciner off-gases.
Sampling of the calciner at Monsanto's Soda Springs plant was hampered by unavailability of suitable
sampling locations. The major results of the testing are summarized in Table 8-17, which shows the
estimated annual calciner emissions for the three plants studied.
Table 8-18 presents the estimated annual calciner emission rates for each of the eight elemental
phosphorus plants. These values were used to estimate the radiation doses and fatal cancer risks from
the plants.
The lung-clearance classifications and particle size distributions (AMAD) used in this assessment are
the same as were used in the 1984 BID.
Table 8-19 shows the number of people living within 80 kilometers of these sites and the source of
the meteorological data used in the calculations.
Table 8-20 gives estimates of the lifetime risk to the nearby individuals and the number of fatal
cancers to the regional population. These data are taken from Volume 2 of the Environmental Impact
Statement.
The total number of fatal cancers per year in the regional populations around elemental phosphorus
plants is estimated at 0,077. The DARTAB computer code provides the frequency distribution of
lifetime fatal cancer risks for each elemental phosphorus plant. It gives the number of people in each
of a series of lifetime risk intervals and the number of cancer deaths that occur annually within each
interval. This information is summarized in Tables 8-21 and 8-22 for operating and idle plants,
8-27
-------
Table 8-17: Radionuclide Emissions from Calciners at Elemental Phosphorus Plants
(198.1- 1 984 Emission Test Results)
Emissions (Ci/vear)
Plan! Calciners U-238 Pb-210 Po-210
FMC - Pocatello, ID 2 0,004 0.12 8.60
Stauffer - Silver Bow, MT 2 0.0006 0.11 0.74
Monsanto-Soda Springs, ID* I 0.006 5.60 21.00
SOURCE; [EP.A89]
"Sampling at the Monsato - Soda Springs, ID plant was hampered by the unavailability of
suitable sampling locations.
Table 8-18: Estimated Annual Radionuclide Emissions from Elemental Phosphorus Plants.
Emissions (Ci/vear)
Plant U-238 Pb-210 Po-210
OPERATING PLANTS
FMC - Pocatello, ID
0.0032
0.14
10.0
Monsanto - Soda Springs, ID
0.0005
0.35
1.4
Stauffer - Silver Bow, MT
0.0006
0.1 I
0.74
Stauffer - Mt. Pleasant, TN
0.0003
0.058
0.28
Occidental - Columbia, TN
0.0001
0.064
0.31
IDLE PLANTS
Monsanto - Columbia, TN
0.0020
0.41
0.64
Stauffer - FL
0.0035
0.19
0.15
Mobil - Pierce, FL
0.0016
0.012
0.01
SOURCE: [EPA89]
8-28
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Tabic 8-19: Populations and Distances to the Maximum Exposed Individuals Around Elemental
Phosphorus Plants.
Plan!
OPERATING PLANTS
FMC, Idaho
Monsanto, Idaho
Stauffer, Montana
Stauffer, Tennessee
Occidental, Tennessee
Number of
People within
80 km
170,000
100,000
71,000
560,000
920,000
Distance to Source of
Maximum Exposed Meteorological
Individual (m) Data
1,800
4,000
2,500
1,500
1,500
Pocatelio, ID
Soda Springs, ID
Butte, MT
Nashville, TN
Nashville, TN
IDLE PLANTS
Monsanto, Tennessee
Stauffer, Florida
Mobil, Florida
900,000
1,700,000
1,800,000
1,500
2,500
750
Nashville, TN
Tampa, FL
Orlando, FL
SOURCE: [EPA89]
8-29
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Table 8-20: Fatal Cancer Risks from Radionuclide Emissions from Elemental Phosphorus PI an Is
Plan!
OPERATING PLANTS
FMC - Poeatello, ID
Monsanto - Soda Springs, ID
Stauffer - Mt. Pleasant, TN
Stauffer - Silver Bow, MT
Occidental - Columbia, TN
Lifetime Risks to
Nearby Individuals
0,0006
0.00008
0.00003
0.00006
0.00003
Regional Populations
(Fata! Cancers/yr Operatic
0.06
0.003
0.003
0.005
0.006
IDLE PLANTS
Monsanto - Columbia, TN
Stauffer - FL
Mobil - Pierce, FL
0.00009
0.00001
0.00001
0.01
0.02
0.007
SOURCE: [EPA89]
Table 8-21: Distribution of Lifetime Fatal Cancer Risk in the Regional (0-80 km) Populations Around
the Five Operating (1988) Elemental Phosphorus Plants
Risk Interval
1 E+0 -
1 E-l -
1 E-2 -
1 E-3 -
E-4 -
1 E-5 -
<1 E-6
1
1 E-l
1 E-2
1 E-3
1 E-4
1 E-5
1 E-6
TOTAL
SOURCE: [EPA89]
No. of persons
0
5,000
110,000
250,000
1,500,000
1,800,000
Deaths/year
0
0
0
01
04
02
005
0.08
Table 8-22: Distribution of Lifetime Fatal Cancer Risk in the Regional (0-80 km) Populations Around
the Three Idle (1988) Elemental Phosphorus Plants.
Risk Interval
1 E+0
1 E-l
1 E-2
1 E-3
1 E-4
1 E-5
<1 E-(
1 E-l
1 E-2
1 E-3
1 E-4
1 E-5
1 E-6
No. of persons
0
0
0
0
6,800
490,000
3,900,000
Deaths/year
0,0
0.0
0.0
0.0
0.001
0.01
0.02
TOTAL
4,400,000
0.03
SOURCE: [EPA89]
8-30
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respectively. Data on the idle plants are included in unlikely case that a plant recommences
operations. Risks for idle plants presented here will not occur unless one or more of these idle plants
resumes operation. These data reflect the number of deaths expected to occur annually within the
0-80 km populations.
8.3.2 Control Technologies for Elemental Phosphorus Plants
The nodulizing kiln or calciner is by far the most significant source of Po-210 emissions from
elemental phosphorus production. This section, based on information in MRI88, describes and
assesses control technologies that can be used to reduce those emissions. Generally Po-210 and Pb-
210 are volatilized in the kiln or calciner and condense on the fine particles in the calciner particulate
matter emission stream (PM stream). The control systems currently installed in the industry
effectively collect large particles, but are not as effective in controlling fine particle emissions.
Consequently, the technologies examined in this section are those that have been demonstrated to
achieve high control efficiencies on fine particles.
Control of Po-210 and Pb-210 emissions is complicated by two factors. First, because the
temperature of the flue gas leaving the kiln may be 400°C (750°F) or higher, significant
concentrations of Po-210 can remain in the vapor phase. Second, the exhaust contains relatively high
concentrations of SOz and HF' these acid gases can condense in the control system leading to
subsequent corrosion and deterioration of performance. Mechanisms for cooling the exhaust gases
and reducing the acid gas concentration in the gases are discussed in detail in MRI88.
Four fine PM stream control techniques are examined in this study:
o wet electrostatic precipitators (wet KSP's)
o venturi scrubbers
o spray dryers with pulse jet fabric filters (SD/FFs)
o high efficiency particulate air (HEPA) filters
The wet ESP and venturi scrubber are the control systems used at operating elemental phosphorus
plants. The SD/FF and HEPA filters were selected as high-efficiency PM control devices that have
excellent potential for controlling Po-210 and Pb-210 emissions but that have not been applied to
elemental phosphorus plants. The SD/FF systems have been applied successfully to combustion
sources and mineral and metallurgical furnaces and have demonstrated high control efficiencies for
8-31
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conde risible metals and acid gases. The HE PA filter has been demonstrated to achieve high control
efficiencies on radionuclide emissions from uranium industry processes.
Four of the five operating elemental phosphorus facilities currently operate spray towers as either
the primary control system or as a gas conditioning technique. These spray towers will remove coarse
particulate matter as well as acid gases from the gas stream. All of the control techniques, except the
SD/'FF, can benefit from the reduced temperature, gas volume, and acid gas concentration that results
from the installation of a spray tower upstream of the primary fine PM control device. Technical
and engineering details on these control technologies are developed in MRI88.
8.3,3 Cost of Control Technologies
The capital and annualized costs for each of the applicable control devices were determined following
the guidelines established in Capital and Operating Costs of Selected Air Pollution Control Systems
{CARD Manual) [GARD78] and the EAB Cost Control Manual [EAB87], These manuals were
prepared for the U.S. Environmental Protection Agency (EPA) to provide technical assistance to
regulatory agencies in estimating the cost of air pollution control systems. The costs in the GARD
Manual are based on December 1977 costs; those in the EAB Cost Control Manual, on 1986 costs. The
costs were adjusted to mid-1988 dollars using indices provided in Chemical Engineering and by the
Bureau of Labor Statistics. Since the same basic procedure was used to cost each of the control
techniques, a cost program was developed, for use on a microcomputer. The paragraphs below
describe the general cost methodology and key assumptions used to estimate the costs of the various
control options. Detailed assumptions for each operating facility are presented in Appendices A
through E of MR 188.
The costs were calculated assuming that each of the fine PM control measures, with the exception
of the SD/FF, were added to control the exhaust from an existing spray tower. The existing system
removes most of the large particles, quenches and cools the exhaust gas stream (thus, reducing gas
volume and ensuring condensation of gaseous radionuclide emissions) and properly conditions the
stream for treatment by the other options.
Capital costs include the direct and indirect costs to purchase and install the necessary ductwork,
control device, fan systems, and stack. Direct capital costs include instruments, controls, taxes,
freight, foundations, supports, erection and handling, electrical work, piping, insulation, painting,
and site preparation. Indirect capital costs include engineering and supervision, construction and
8-32
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field expenses, construction fees, startup performance test, and contingencies. Table 4-4 in MRI88
presents the assumptions used for direct and indirect cost estimates based on information given in
the CARD Manual, All ductwork was sized based on a gas velocity of 20 meters per second (m/s)
(4,000 ft/min). Site-specific estimates of the length of additional ductwork to connect the existing
control system with the add-on control device were developed for the analyses in Section 5. Stack
diameters were calculated to provide a stack gas velocity of 18 m/s (3,600 ft/min). All stack heights
are assumed to be 15 m (50 ft) for the add-on equipment. With the exception of connecting
ductwork, no special retrofit costs were included in the cost analyses. Based on information collected
during plant visits, MRI determined that no retrofit problems should be expected at the operating
facilities.
Annualized costs include the total utility costs, the total operating labor costs, the total maintenance
costs, the total overhead costs, the capital charges, and the total waste disposal costs. The annualized
costs were based on 8,640 hours per year of operation (360 days)2. The utility costs reflect actual
utility costs in the area of each facility as presented in Appendices A through E of MRI88. The
operating and maintenance labor costs were determined using an average hourly wage of $ 12/hour(h).
The operating labor hours per shift for each control device were 4 h/shift for SD/FF's, 2 h/shift
for scrubbers, and 1 h/shift for ESP's. The maintenance labor was assumed to be 1 h/shift for ESP's
and scrubbers and 2 h/shift for SD/FF's.
The quantity of sludge or dry waste collected by the add-on control devices was determined based
on the efficiency of particulate removal. In the case of the SD/FF, the quantity of lime added to the
system also is considered. The cost to dispose of the waste in a secured landfill was assumed to be
$20/ton. The waste is considered to be hazardous for these calculations because of the concentration
of radioactive material. (For comparison, it should be noted that the cost of disposing of
nonhazardous wastes is approximately $5/ton.)
8.3.3,1 Venturi Scrubber Cost Assumptions
The capital and annualized costs for venturi scrubbers were based on procedures established in the
GaRD manual and on equipment costs established therein. Because of the large airflow encountered
2 The effect of this assumption is probably to overestimate the operating and maintenance costs
vis a vis actual operating time. As was stated in section 8.2, it is assumed that the operating plants
are producing for 7,400 hours (85 percent of capacity).
8-33
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at most kilns, two identical scrubber systems in parallel were assumed on each kiln's exhaust stream.
Radial fans were evaluated because of their ability to operate at high pressures and temperatures in
an abrasive gas stream. The costs of the starter motor, direct and V-belt drives, and dampers are
included in the fan costs. The corrosiveness (fluorides) of the gas stream entering a scrubber from
the rotary kiln calciner requires that fabricated equipment cost estimates be based on the use of a
combination of Hastelloy and Type 316 stainless steel. Plate thickness of the fan housing and
ductwork was determined based on system static pressure. Details on the cost inputs for venturi
scrubber control options for each facility are presented in Appendices A through E of [MR188] for
the individual facilities.
8.3.3.2 Wet ESP Cost Assumptions
Capital and annualized costs for the ESP were based on an EPA cost update. A primary factor that
affects ESP costs is material of construction. The corrosiveness (fluorides) of the gas stream entering
an ESP from the rotary kiln calciner requires that fabricated equipment, ductwork and ESP housing
be constructed of a corrosion-resistant material. Costs for these components were based on the use
of Type 316 stainless steel. Collecting electrodes also were assumed to be constructed from Type 316
stainless steel.
8.3.3.3 SD/FF Cost Assumptions
Spray dryer/fabric filter systems provide efficient collection of both condensible PM and acid gases.
Key design parameters that affect system performance and costs are lime addition, gas temperature
entering the FF, FF air-to-cloth ratio, and pressure drop through the system. Lime addition rates
were calculated under the assumption of a 1.5:1 stoichiometric ratio of lime to HF and S02 combined.
The gas temperature at the FF inlet was assumed to be 150°C (300°F). An air-to-cloth ratio of 1:1.2
m2/m3/min (4:1 ft2/ft3/min) and a system pressure drop of 3.1 kPa (12.5 in. w.c.) were used.
Total direct costs for the SD/FF unit were estimated on the basis of the cost equation:
C = 7.115 Q0*517
where:
C = total direct cost, $xl03 in December 1987
Q = volumetric flow, acfm
8-34
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This cost equation is based on comprehensive information collected by EPA as a part of the municipal
waste combustion study. Vendors contacted during this study indicated that these costs would
provide reasonable ±30 percent estimates.
8.3.3.4 HEPA Filter Cost Assumptions
Calciner gas stream characteristics that affect HE PA filter design and costs are moisture content,
inorganic acid content, and loading in the gas stream to be treated. A spray tower is assumed to exist
upstream of the HEPA filtration system; the high moisture content of the spray tower exit gases
requires treatment of the gases by a de-mister and re-heater of the HEPA system. Because the
exhaust gases are corrosive, Type 304 stainless steel housings and filter frames, acid-corrosion
resistant filter media, and vinyl-clad aluminum separators are included in the cost of the system and
replacement filters to provide the best available corrosion resistance. Because the PM loading in the
gas stream exceeds the recommended maximum of 2.3 mg/m3 (0.001 g/acf), the cost of a pre-
filtration system is included in the total system cost. Estimated costs of the HEPA system, consisting
of the pre-filters, HEPA filters, pre-filter/HEPA filter bank housing, de-mister, re-heater, and
de-mister/reheater housing were obtained from equipment vendors.
A major operating cost for HEPA filters is filter replacement. The operating life of a HEPA depends
on the increase in pressure drop resulting from particle collection within the filter media. A general
guideline used to design filter systems is 4 lb/1,000 ft3/min rated capacity (1.82 kg/1,000 ft3/min).
Filter life was estimated by assuming a HEPA capacity of 7.9 lb/1,000 ft3/min (3.6 kg/1,000 ft3/min)
per filter based on vendor information. The methodology used to estimate filter life consisted of the
following steps:
1. Obtain particle size distribution in spray tower exist gas stream from test data (where
available);
2. Predict the mass of particles removed by pre-filtration using design pre-filter removal
efficiencies for a given particle size;
3. Predict mass of particles removed by HEPA filter using filter design HEPA removal
efficiencies;
8-35
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4. Assume a filter capacity for HEPA filter and calculate HEPA filter operating life with
and without use of a pre-filter;
5. Calculate pre-filter life as two times the HEPA filter life without the use of a pre-
filter; and
6. Calculated HEPA filter life as the HEPA capacity divided by the particulate loading
rate into the HEPA filter.
Estimates of the labor cost to replace pre-filters and HEPA filters as they are exhausted is based on
0.25 hours of labor per filter per replacement cycle. For example, filter replacement for a 36 filter
bank requires 9 hours.
Exhausted filters are expected to exhibit increased concentrations of particulate matter containing
Po-210 and Pb-210. To reduce the risk of inhalation of particles that may become airborne as a
result of filter handling during the replacement process, an automatic bagout containment system is
included in the system cost. Automatic bagout facilitates removal of exhausted filters without direct
operator contact. Heavy duty PVC bags are installed inside the filter housing between the filters and
the housing access door. When the door is opened, the bags form a barrier between the operator and
the contaminated filter. By working through the bag, the operator can remove the filter and draw
it into the bag without direct contact. The cost of replacement bags was included in the estimate of
replacement material cost.
8.3.4 Emissions Control Alternatives
As outlined above, four fine I'M control techniques were identified as having potential for control
of Po-210 and Pb-210 emissions from caiciners--venturi scrubbers, wet electrostatic precipitators
(ESP's), spray dryers with pulse jet fabric filters (SD/FF's) and high energy particulate air (HEPA)
filters. Ten different control alternatives based on these four technologies were examined. Four of
the alternatives are based on venturi scrubbers at different pressure drops ( P's), four are based on
wet ESP's with different specific collecting areas (SCA's), and one each is based on a SD/FF system
and a HEPA filter system. The paragraphs below describe the control alternatives and the
assumptions that were used to assess performance and cost of these systems.
8-36
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Four of the control alternatives comprise venturi scrubbers operated downstream from a spray tower.
Four different pressure drops were examined—2.5 kPa (10 in. w.c.), 6.2 kPa (25 in. w.c.), 10 kPa (40
in. w.c.), and 20 kPa (80 in. w.c.). The values from 2.5 kPa to 10 kPa represent the range of P's for
venturi scrubbers at recently installed control systems on elemental phosphorus plant calcining
operations. The 20 kPa level was selected as a control alternative that is more stringent than the
controls typically used in the industry, but that has been applied to other metallurgical processing
facilities. Two other assumptions were made in evaluating the performance and costs of the venturi
scrubber control alternatives. First, a spray tower was assumed to be used upstream from the venturi
to control acid gases and condition the gas stream for the venturi. All of the operating facilities
except FMC currently have a spray tower as a part of their control system that is assumed to be
useable as the conditioning system for the venturi. Second, for all the venturi scrubber control
alternatives, the L/G ratio was assumed to be 1.3 1/m3 (10 gal/1,000 ft3). This value was selected
because it represents the upper end of the range typically found in venturi scrubber applications.
A cyclonic mist eliminator also was assumed for all venturi scrubber alternatives. Note that although
FMC does not have a spray tower in its systems, no tower was costed for this study. The low energy
scrubber that FMC has in place as assumed to provide coarse PM control and gas conditioning.
The four ESP control alternatives that were considered comprised spray towers for acid gas control
and gas stream conditioning followed by flat-plate wet ESP's. The four SCA levels that were
considered were 39.4 (m/s)"1 (200 ft2/kacfm), 78.8 (m/s)"1 (400 ft2/kacfm), ng (m/s)"1
(600 ft2/kacfm), and 158 (m/s)-1 (800 ft2/kacfm). These four SCA levels are higher than the SCA
at the one wet ESP that is applied to a nodulizing kiln. However, that unit is an older unit with
relatively low PM removal efficiency. The range of 39.4 to 158 (m/s)"1 (220 to 800 ft3/kacfm) is
representative of the SCA levels typically found on metallurgical and mineral processing facilities.
The spray tower upstream from the ESP will remove acid gases from the gas stream and reduce the
temperature to 65° to 70°C (150° to 160°F) to assure that the Po-210 and Pb-210 are condense before
entering the ESP.
The ninth control alternative is the SD/FF control system. For this alternative, the exhaust stream
is vented directly to the spray dryer without pretreatment. No SD/FF systems have been applied to
elemental phosphorus facilities. However, they were selected as a stringent control technique because
they have been demonstrated to control acid gases and condensation PM in other metallurgical and
mineral processing operations such as aluminum reduction and glass manufacturing. Key assumptions
made to estimate performance and cost are that sufficient moisture will be added to reduce gas
temperature to 120°C (250°F) at the inlet to the FF, that lime will be added at a 1.5 stoichiometric
8-37
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ratio for HF and SOz combined, and that a pulse jet fabric filter capable of maintaining an outlet
grain loading of 0.023 g/dscm (0.01 g/dscf) will be installed.
The final control alternative comprises a spray tower scrubber, a reheat system, a prefilter, and a
HE PA filter in sequence. The spray tower is used to reduce the acid content of the gas stream and
to remove larger sized PM. The reheat system is needed to raise the gas stream temperature
sufficiently to prevent condensation of moisture and inorganic acids in the HEPA filter. The
prefilter is used to reduce the PM loading to the HEPA filter and thereby extend its life. The HEPA
filter system has not been applied to elemental phosphorus facilities and generally is not applied to
furnaces that generate gas volumes as large as those generated by elemental phosphorus process
calciners or nodulizing kilns. However, the system was selected for consideration because HEPA
filters have been used successfully to control radionuclide emissions from uranium processing
facilities and they do provide a much greater level of control than is provided by the other control
alternatives.
8.3.5 Performance of Control Alternatives
The performance of each of the 10 control alternatives was calculated based on the reduction from
baseline emissions that could be achieved by application of the control alternative. For each control
alternative and each operating facility, annual emissions of Po-210 and Pb-210 were estimated using
the procedures described in Section 4 of MRI88. The estimates of Po-210 and Pb-210 emission rates
at the scrubber/ESP inlet, based on the assumptions that a spray tower is located upstream from
primary control device are given in Table 8-23.
The estimate for FMC, Monsanto, and Stauffer, Montana, are based on tests conducted by EPA in
1983 and 1988 that measured emissions at the outlet of low-energy scrubbers at those facilities.
Because the control systems at the two Tennessee plants consist of spray tower scrubbers, the emission
estimates for those two facilities are based on the baseline emissions from those facilities. Separate
estimates were developed for moving grate calciners (FMC) and rotary kilns (all other facilities).
8-38
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Table 8-23: Estimated Po-210 and Pb-210 Emissions at the Scrubber/ESP inlet
Facility
Po-210
Pb-210
FMC
10,00
Monsanto
30.00
Stauffer, MT
2.40
Stauffer, TN
o.:.x
0.058
Occidental
II !!lll||!l|l!llll|ll|||
Control efficiencies also were developed for the SD/FF and the HEP A. The resultant efficiencies
are 99.82 percent for rotary kilns and 99.85 percent for grate kilns. For the HEPA filter, the
efficiency was assumed to be 99.998 percent as described above. Nationwide and plant specific
capital and annualized cost summaries for each control alternative are presented in Tables 8-24
through 8-29. The estimated Po-210 removal efficiency of each control technology is also presented
in these tables.
8.4 Analysis of Benefits and Costs
This section examines the benefits and the costs of alternative Po-210 standards for emissions from
elemental phosphorus plants. Although Pb-210 emissions comprise an important part of total
radionuclide emissions, the control of Pb-210 is similar to that of Po-210, therefore the following
section refers only to the control of Po-210 emissions. It is assumed that Pb-210 emissions are
reduced in proportion to Po-210 emissions.
8.4.1 Benefits of Po-210 Emissions Control
The health benefits that accrue to society over time from the control of Po-210 emissions at the
elemental phosphorus plants consist largely of the reduction in expected lung cancers and, to a lesser
8-39
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Table 8-24: Cost of Alternative Control Systems and Efficiency
of Polonium-210 Removal.: Industry Totals
Total
Capital Annualized
Control Costs\a Costs
Alternative <1988 S, mil) (1988 S, mil
Uet Scrubber
P = 2.5 kPa
P = 6.2 kPa
P = 10 kPa
P = 20 kPa
9.42
12.19
16.08
28.50
2.90
4.50
5.20
11.00
ESP
SCA = 39.4 (m/s)-1
SCA = 78.8 (m/s)-1
SCA = 118 (m/s)-1
SCA « 158 (m/s>-1
20.66
29.70
51.80
63.99
5.70
7.70
9.60
12.00
Spray Dryer/
Fabric Filter
51.89
26.00
HEPA Filter
10.32
47.00
NOTES: kPa = kiloPascal
ESP = electrostatic precipitator
SCA = specific collection area
HEPA = high efficiency particulate air
\a Capital costs include primary equipment cost as well as
auxiliary equipment costs, ductwork, fan
systems, stacks, waste disposal, and insta.lation.
SOURCE : [MR188]
8-40
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Table 8-25: Cent of Alternative Control Systems and Efficiency of Poloniua-210 Reaoval
Control
Alternative
at FSC's Pocatello, Idaho, Plant.
Po-210 Capital
Reaoval Cost$\a
Efficiency (1988 i, ait)
Total
tonus lizecf
Costs
(1988 «, ail)
Wet Scrubber
P = 2.5 kPa 20.OX 5.94 1.60
P = 6.2 kPa 60.0% 7.81 2.11
P = 10 kPa 80.0% 8.50 2.43
P = 20 kPa 90.OX 13.28 3.75
ESP
SCA - 39.4 («/i)-1 71.0% 10.64 2.01
SCA = 78,8 lm/s)-1 90.0% 15.50 2.84
SCA = 118 («/s)-1 96.2% 20.28 3.65
SCA = 158 («/s)-1 98.6% 24.79 4.43
Spray Dryer/ 99.6% 17.33 5.70
Fabric Filter
HEPA Filter 99.998% 4.20 10.14
MOTES: kPa « kiloPascai.
ESP = electrostatic precipitator
SCA = specific collection area
HEPA = high efficiency particulate air
\a Capital costs include priaary equipment cost as well as
auxiliary equipment costs, ductwork, fan
systeas, stacks, waste disposal, and installation.
SOURCE: CHRI883
8-41
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Table 8-26i Coat of Alternative Control Systems and Efficiency of Polonium-210 Removal
at Monsanto'b Soda Springs, Idaho, Plant,
Total
Po-210 Capital Annualized
Control Removal Costs\a Costs
Alternative Efficiency (1968 $, nil) (1988 5, mil)
Hat Scrubber
P - 2,5 kPa 20.0% \b \b
P - 6.2 kPa 55.0% \b \b
p - 10 kPa 90.01 \b \b
P - 20 kPa 95.0% \b \b
BSP
SCA - 39.4 (m/6)-1 75.3% \b \b
SCA - 78.8 (m/B)-l 91.01 \b \b
SCA - 118 (m/s)-l 97.2% 12.89 2.33
SCA - 158 (»/s)-l #9.0* 15.72 2.82
Spray Dryer/ 99.5% 10.38 5.43
Fabric Filter
HEPA Filter 99.998% 2.87 15.70
NOTES: kPa *» kiloPascal
ESP «¦ electrostatic precipitator
SCA - specific collection area
HEPA - high efficiency particulate air
\a Capital costs include primary equipment coat as well as
auxiliary equipment costs, ductwork, fan
systems, stacks, waste disposal, and installation.
\b Bo costs are incurred for this alternative because
facility has more efficient control in place.
SOURCE: [HRI88]
8-42
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Table 8-27: Cost of Alternative Control Systems and Efficiency of Polonium-
Removal at the Stauffer Mount Pleasant, Tennessee, Plant.
Control
Alternative
Po-210
Removal
Efficiency
Capital
Costs\a
(1988 $, mil)
Total
Annuali zed
Costs
{1988 %, mil)
Wet Scrubber
P * 2.5 kPa
P s 6.2 kPa
P = 10 kPa
P « 20 kPa
20.0%
55.0%
90.0%
95.0%
1.46
1,8?
2.46
5.23
0.59
0,75
0.93
1.61
ESP
SCA = 39.4 («n/s}-1 75.0%
SCA = 78.8 (m/s3-1 92.9%
SCA = 118 (m/s>-1 96.4%
SCA = 158 (m/s)-1 96.4%
3.14
4.39
5.95
7.39
0.64
0.85
1.12
1.37
Spray Dryer/
Fabric FiIter
99.6%
6.58
3.12
HEPA Filter
99.998%
1.02
7.45
NOTES: kPa = kiloPascal
ESP = electrostatic precipitator
SCA = specific collection area
HEPA = high efficiency particulate air
\a Capital costs include primary equipment cost as well as
auxiliary equipment costs, ductwork, fan
systems, stacks, waste disposal, and installation.
8-43
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Table 8-28: Cost of Alternative Control Systems arid Efficiency of Polonium-210
Removal at the Stauffer Silver Bow, Montana, Plant.
Control
Alternative
Po-210
Removal
Efficiency
::::;=;;ssssss==ss=
Capital
COStS\B
{1988 $, mil)
Total
Annualized
Costs
(1988 $, mil)
Wet Scrubber
P = 2.5 kPa
P = 6.2 kPa
P = 10 kPa
P = 20 kPa
20,0%
55.0%
90.0%
95.0%
\b
\b
1.89
3.87
\b
\b
0.74
1.11
ESP
SCA = 39.4 (ro/s)-1 75.4%
SCA = 78.8 (m/s>-1 92.1%
SCA = 118
-------
fable 8-29: Cost of .Alternative Control Sy»teo* and Efficiency of Poloniua-210 Raaoval
at Occidental'* Columbia, Tennessee, Plant.
Total
Po-210 Capital Annualized
Control Removal Costa\a Costa
Alternative Efficiency (1988 S, ail) (1988 $, ail)
Wet Scrubber
P ¦ 2.5 kPe 20.0% 2.02 0.74
P = 6.2 kpa 55.OX 2.51 0.92
P « 10 kPa 90.05! 3.23 1.15
P = 20 kPa 95.0% 6.12 1.91
ESP
SCA = 39.4 (a/a)-1 74.2% 4.53 0.97
SCA • 78.8 (a/s)-1 93.6% 6.50 1.32
SCA = 118 (a/sj-l 96.8% 8.60 1.67
SCA = 158 (a/s)-1 96.8% 11.34 2.03
Spray Dryer/ 99.4% 10.06 4,63
Fabric Filter
HEPA Filter 99.998% 1.61 10.07
NOTES: kPa = kiloPascal
ESP = electrostatic precipitator
SCA = specific collection area
HEPA » high efficiency particulate air
\a Capital costs include priaary equipment cast as well as
auxiliary equipment costs, ductwork, fan
systeas, stacks, waste disposal, and installation.
SOURCE; CNRI883
8-45
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extent, the reduction in non-hazardous particulate emissions near the site. The health benefits
associated with the reduction of Po-210 emissions are determined to be the major component of the
total health benefits due to any reduction of emissions at these plants. The efficiency of the
particulate control technologies in terms of Po-210 removal and control is, therefore, of great
importance in the calculation of the expected health benefits under alternative control scenarios.
Tables 8-24 through 8-29 presented the estimated efficiencies of Po-210 control of the various
control alternatives. In this section, the expected benefits of the proposed alternate standards are
estimated by applying proportionate reductions to the estimated health risks currently generated in
the population residing within 80 km of the five operating plants. This method assumes a
proportionate reduction in fatal cancers for given statutory reductions in Po-210 emissions. The
proportionate reduction assumption is consistent with A1RDOS computer code procedures for
evaluating population exposures in the affected areas and with the RADRISK. code for translating
exposures into expected fatal cancers, based on the linear dose-response model.
The results of analyses to determine the efficiencies of various alternatives for controlling the
polonium-210 and lead-210 emissions from calciner off-gas systems at the five operating elemental
phosphorus plants are summarized in Table 8-30. As described above, the control alternatives
considered were the installation of wet (Venturi) scrubbers, electrostatic precipitators (ESP), a spray
dryer followed downstream by a fabric filter (SD/FF), and high efficiency particulate air (HEPA)
filters. The table presents the reduction in emissions that would result from the installation of the
ten different control technologies on each of the operating plants. As discussed above, baseline
emissions were estimated for each operating plant under the assumption that low-energy or spray
scrubbers were present at each plant. The emissions reductions are estimated assuming that additional
systems are added to these wet scrubbers. For the Spray Dryer/Fabric Filter system, the estimates
are determined by first removing the low energy wet scrubber (the baseline emissions are divided by
0.35) and adding the SD/FF.
Lifetime risks to nearby individuals and incidences of fatal cancers per year in the regional
populations were presented in Table 8-20. Table 8-31 and Table 8-3la present the benefits of the
installation of the various emission control technologies in terms of fatal cancer risk. Table 8-31
presents total risk figures for each plant and for each control technology. Table 8- 31 a estimates the
8-46
-------
Table 8-30: Estimated Po-210 Emission Levels Achieved by Control Alternatives*
Emission levels (Ci/year)
Control
FMC
Monsanto
Stauffer
Stauffer
Occidental
Alternative
Idaho
Idaho
Montana
Tennessee
T ennessee
Baseline <*)
10.000
30.000
2.400
0.280
0.310
Wet Scrubber
P = 2.5 kPa
8.000
21.000
1.700
0.200
0.220
P = 6.2 kPs
4.000
14.000
1.100
0.130
0.140
P = 10 kPa
2.000
3.000
0.240
0.028
0.031
P = 20 kPa
1.000
1.500
0,120
0.014
0.016
ESP
SCA = 39.4 (m/s)-1
2.900
7.400
0.590
0.070
0.080
SCA = 78.8
-------
Table 8-31: fatal Cancer Risks from Radionuclide Emissions from Elemental Phosphorus Plants
arid Risk Reductions from Alternate Control Technologies
Control
FMC - Idaho
Monsanto - Idaho
Occidental - Tennessee
Stauffer - Montana
Stauffer - Tennessee
TOTAL
4!terfsati ve
lifetime Regional
Risks to Populations
Nearby (Cancers/
Individuals Year)
Lifetime Regional
Risks to Populations
Nearby (Cancers/
Individuals
Year)
Lifetime
Risks to
Nearby
Individuals
Regional
Populations
(Cancers/
Year)
Lifetime
Risks to
Nearby
Individuals
Regional
Populations
(Cancers/
Year)
lifetime Regional
Risks to Populations
Nearby
Individuals
(Cancers/
Year)
Regional
Populas ions
(Cancers/
Year)
Current Risks
6.QE-04
6.0E-02
8.06-05
3.06-03
3.0E-05
6.06-03
6.06-05
5.0E-03
3.0E-Q5
3.0E-Q3
7.76-02
Wet Scrubber
P S 2.5 kPa
P = 6.2 kPa
P = 10 fcPa
P = 20 kPa
4.8E-04
2.4E-04
1.2E-Q4
6.0E-05
4.8E-Q2
2.46-02
1.2E-02
6.0E-03
2.1E-05
1.4E-05
3,0E-Q6
1.5E-06
4.3E-03
2.86-03
6.0E-O4
3.0E-04
a
a
1.9E-05
9.7E-06
a
a
1.6E-03
8.16-04
2.1E-05
1.4E-05
3.QE-06
1.5E-06
2.16-03
1.4E-03
3,06-04
1.5E-04
5.46-02
2.86-02
1.5E-02
7.3E-03
ESP
SCA = 39.4 (m/s)-1 1.76-04 1.7E-02 a a 7.56-06 1.5E-03 4.86-05 4.06-03 7.76-06 7.7E-04
SCA - 78.8 (m/s)-1 6.0E-05 6.0E-03 a a 2.1E-06 4.3E-04 1.5E-05 1.3E-03 1.9E-06 1.96-04
SCA = 118 (m/S)-1 2.3E-05 2.36-03 4.86-05 1.86-03 1.1E-06 2.16-04 5.76-06 4.7E-04 9.7607 9.76-05
SCA - 158 (m/s)-t 8.4E-06 8.46-04 1.76-05 6.2E-04 1.IE - 06 2.1E-04 1.66-06 1.46-04 9.76-07 9.76-05
2.46-02
7.96-03
4.96-03
1.96-03
Spray Dryer/
Fabric Filter
2.66-06
2.66-04
8.6E-06
3.2E-04
1.1E-07
2.16-05
9.7E-07
8.1E-05
1.96-07
1.9E-05
7.06-04
HEPA Filter
6.06-08
6.0E-06
5.7E-08
2.1E-06
1.1E-07
2.16-05
8.16-08
6.86-06
9.7E-08
9.7E-06
4.66-05
MOTES: kPa = kiloPascal
ESP « electrostatic precipitator
SCA = specific collection area
HEPA = high efficiency particulate air
(a) Current Emissions result in risks lower than those obtainable with this control method.
SOURCE: [MR 188]
-------
Table 8-31a: Reduction iri Fatal Cancer Risks to Nearby Individuals and to Regional Populations
for each Alternate Control Technology
Control
AIternative
FMC - Idaho
Lifetime Regional
Risks to Populations
Nearby {Cancers/
Individuals Year)
Monsanto - Idaho
Lifetime Regional
Risks to Populations
Nearby
Individuals
{Cancers/
Year)
Occidental -
lifetime
Risks to
nearby
Individuals
Tennessee
Regional
Populat ions
(Cancers/
Year)
Stauffer
L i f et i me
Risks to
Nearby
Individuals
- Montana
Regional
Populations
(Cancers/
Year)
Stauffer - Tennessee
Lifetime Regional
Risks to Populations
Nearby
Individuals
{Cancers/
Year)
TOTAL
Regional
Populations
(Cancers/
Year)
Baseli ne
6.0E-04
6.0E-02
8.0E-05
3.0E-Q3
.0E-Q5
6.QE-03
6.QE-05
5.0E-03
3.0E-05
3.0E-03
7.7E-G2
Wet Scrubber
P = 2.5 kPa
P = 6.2 kPa
P = 10 kPa
P = 20 kPa
1.2E-04
3.6E-04
4.8E-04
S.4E-04
1.2E-02
3.6E-02
4.8E-02
5.4E-02
8.6E-06
1.6E-05
2.7E-05
2.9E-QS
1.7E-03
3.2E-03
5.4E-03
5.7E-03
4.1E-05
5.0E-0S
a
a
3.4E-03
4.2E-03
8.7E-06
1.6E-05
2.7E-05
2.86-05
8.7E-04
1.6E-03
2.7E-03
2.8E-03
1.5E-02
4.1E-02
5-9E-02
6.7E * 02
ESP
SCA = 39.4 -1 4.3E-04 4.3E-02 a a 2.3E-05 4.5E-03 1.2E-05 1.0E-03 2.2E-05 2.2E-03
SCA = 78.8 -1 5.4E-04 5.4E-02 a a 2.8E-05 5.6E-03 4.5E-05 3.7E-03 2.8E-05 2.8E-03
SCA = 118 (m/s)-1 5.8E-04 5.8E-02 3.2E-05 1.2E-03 2.9E-05 5.8E-03 5.4E-05 4.5E-03 2.9E-05 2.9E-03
SCA = 158 Cm/s)-1 5.9E-04 5.9E-02 6.3E-05 2.4E-03 2.9E-05 5.8E-03 5.8E-0S 4.9E-03 2.9E-05 2.9E-03
5.06-02
6.6E-02
7.2E-02
7.SE-02
Spray Dryer/
fabric fiIter
6.0E-04
6.0E-O2
7.1E-05
2.7E-03
3.0E-0S
6.0E-03
5.9E-05
4.9E-03
3.0E-05
3.0E-03
7.6E-02
HEPA FiIter
6.0E-04
6.0E-02
8.0E-05
3.0E-03
3.0E-05
6.0E-03
6.0E-05
5.0E-03
3.0E-05
3.0E-03
7.7E-Q2
NOTES; kPa = kiloPascal
ESP = electrostatic precipitator
SCA = specific collection area
HEPA = high efficiency particulate air
(a) Current Emissions result in risks lower than those obtainable with this control method.
SOURCE: [MR 188]
-------
total reduction in risk due to each control alternative. The current risks at both the Monsanto plant
and at the Stauffer, Montana, plant are lower than certain control technologies would allow.
As stated previously, both the baseline emissions rates and the risk estimates are discussed in detail
in Volume 2 of the Environmental Impact Statement. The PM removal efficiency of each alternative
control technology was estimated in MRI88.
8.4.2 Costs of Po-210 Emissions Control
The control technologies described above lead to a unique least-cost choice of technology to achieve
a given level of emissions control for each of the five operating plants. These emissions levels and
costs for each plant are presented in Tables 8-32 through 8-36.
The Po-210 removal efficiency of the SD/FF and the ESP's was derived by dividing the emission
levels achieved by each alternative control technology by the baseline emissions for each technology.
Removal efficiency for the scrubbers and for the HEP A filter are taken from MRI88. In Tables 8-
32 through 8-36, the removal efficiency is applied to three Po-210 emissions scenarios: the baseline
emission rate, the baseline rate plus a 10 percent safety margin, and the baseline rate plus a 25
percent safety margin. Emission reductions are then calculated for each control alternative using the
appropriate Po-210 removal efficiency rate. Further sensitivity analysis could be conducted by
allowing for specific measurement error and variability in the stated efficiencies.
Tables 8-32 to 8-36 also present the annualized costs of installing and operating the ten alternative
control systems. The impact of these costs is then estimated both as a cost per ton of elemental
phosphorus produced and as a percentage of the revenues derived from the production and sale of
elemental phosphorus at each plant. As was stated in section 8.2, the cost per ton of P4 is estimated
to be $1,500. Revenues from the sale of this product are derived by assuming that the plants produce
and sell 85 percent of estimated annual P4 capacity at this price. Revenues would change if actual
production varied from this estimate of 85 percent.
The cost of the control technologies varies by plant. For FMC cost ranges from $1.37 to $8.71 per
ton of P4 capacity, and from 0.92 to 5.81 percent of 1987 P4 revenues. For Monsanto, the costs of
those technologies which would improve current Po-210 emissions (1.4 Ci/y) range from $2.89 to
8-50
-------
Table 8-32; Control Technology Cost* and Estimated Po-210 Emission Rates
at FHC's Pocatello, Idaho, Plant.
Estimated Po-210 Emission Rate
Control
Po-210 -
Total
Estimated
Percent of
Alternative
Reooval
No
10 Percent
25 Percent
Annualized
Cost/Ton
Value of
Efficiency
Safety
Safety
Safety
Control
of P4
1987 P4
Margin
Margin
Margin
Syste*
Produced
Revenues
(Ci/y)
(Ci/y)
(Ci/y)
Cost
(1987)
(ail S/yr)
Baseline Po-210 Emission Rate (*)
10.000
11.000
12.500
Uet Scrubber
P = 2.S kPa
20.00%
8.000
8.800
10.000
1.60
$1.37
0.92%
P = 6.2 kPa
60.00%
4.000
4.400
5.000
2.11
$1.81
1.21%
P = 10 kPa
80.00%
2.000
2.200
2.500
2.43
$2.09
1.39%
P = 20 kPa
90.00%
1.000
1.100
1,250
3.75
$3.22
2.15%
ESP
SCA - 39.4 Cb/sJ-1
71.00%
2.900
3.190
3.625
2.01
$1.73
1.15%
SCA = 78.8 <«/s)-1
90.00%
1.000
1.100
1.250
2.84
$2.44
1.63%
SCA - 118 (b/sJ-1
96.20%
0.380
0.418
0.475
3.65
$3.13
2.09%
SCA ¦ 158 C»/8)-1
98.60%
0.140
0.154
0.175
4.43
$3.80
2.54%
Spray Dryer/
99.57X
0.043
0.047
0.054
9.70
$8.33
5.55%
Fabric Filter
HEPA Filter
99.998% 0.0002
0.0002
0.0002
10.14
$8.71
5.81%
NOTES: kPa « kiLoPascal
ESP = electrostatic precipitator
SCA = specific collection area
HEP* » high efficiency particulate air
(•) Emissions with low energy or spray scrubber. Additional systeas
are added to these wet scrubbers except with the Spray Dryer/
Fabric Filter control alternative.
SOURCE: CHRI883
8-51
-------
Table 8-33: Control Technology Cost* and Estimated Po-210 Eaistion Bates
¦t Monsanto's Soda Spring*, Idaho, Plant.
Estimated Po-210 Emission Sate (b)
Control
Alternative
Po-210 -
Reaoval
Efficiency
Ho
Safety
Margin
(Ci/y)
10 Percent
Safety
Margin
(Ci/y)
25 Percent
Safety
Margin
CCi/y)
Total EstiBated Percent of
Annualized
Control
Systea
Cost
(ail $/yr)
Cost/Ton
of P4
Produced
(1987)
Value of
1987 f>4
Revenues
Baseline Po-210 Enissieo tote (*) 30.WO
Met Scrubber
P = 2.5 kPa
P » 6.2 kPa
P = 10 kPa
P - 20 kPa
20.00%
55.00%
90.00%
95.00%
24. OCX)
13.500
3.000
1.500
33.000
26.400
14.850
3.300
1.650
37.500
30.000
16.875
3.750
1.875
ESP
SCA = 39.4 (a/s)-1 75.33% 7.400 8.140 9.250
SCA - 78.8 (a/s)'1 91.00% 2.700 2.970 3.375
SCA * 118 <«/s>-1 97.20% 0.840 0.924 1.050
SCA = 158 (B/S>-1 99.03% 0.290 0.319 0.363
2.33
2.82
a
a
$2.89
$3.49
1.92%
2.33%
Spray Dryer/
Fabric Filter
99.50% 0.150
0.165
0.188
5.43
$6.72
4.48%
HEPA Filter
99.998% 0.0006
0,0007
0.0008
15.70
$19.44
12.96%
MOTES: kPa = kiloPascal
ESP - electrostatic precipitator
SCA * specific collection area
HEPA = high efficiency particulate air
(*) Emissions with low energy or spray scrubber. Additional systeas
are added to these wet scrubbers except with the Spray Dryer/
Fabric Filter control alternative.
(a) No costs are incurred for this alternative, because facility has
¦ore efficient control in place.
(b) Because the eaissions at this facility are currently estimated at 1.4 Ci/y,
higher estimates included in this table are theoretical.
SOURCE: CMR1883
8-52
-------
Table 8-34; Control Technology Costs and Estimated Po-210 Emission Sates
at the Stauffer Mount Pleasant, Tennessee, Plant.
Estimated Po-210 Emission Rate
Control
Po-210
Total
Estimated Percent of
Alternative
Removal
No
10 Percent
25 Percent
Annualized
Cost/Ton
Value of
Efficiency
Safety
Safety
Safety
Control
of P4
1987 P4
Margin
Margin
Margin
System
Produced
Revenues
(Ci/y)
(Ci/y)
(Ci/y)
Cost
(1987}
(mil $/yr>
Baseline Po-210 Emission Rate {*)
0.280
0.308
0.350
Wet Scrubber
P = 2,5 kPa
20.00%
0.224
0.246
0.280
0.59
$1.54
1.03%
P = 6.2 kPa
55.00%
0.126
0.139
0.158
0.75
$1.96
1.31%
P = 10 kPa
90.00%
0.028
0.031
0.035
0.93
$2.43
1.62%
P = 20 kPa
95.00%
0.014
0.015
0.018
1.61
$4.21
2.81%
ESP
SCA = 39.4 (nt/s)-1
75.00%
0.070
0.077
0.088
0.64
$1.67
1.12%
SCA = 78.8 (m/s)-1
92.86%
0.020
0.022
0.025
0.85
$2.22
1.48%
SCA = 118 (ffl/s}-1
96.43%
0.010
0.011
0.013
1.12
$2.93
1.95%
SCA = 158
-------
Table 8-35: Control Technology Costs and Estimated Po-210 Emission Rates
at the Stauffer Silver Bow, Montana, Plant.
Estimated Po-210 Emission Rate (b)
Control Po-210 - Total Estimated Percent of
Alternative
Removal
No
10 Percent
25 Percent
Annua Iized
Cost/Ton
Value of
Efficiency
Safety
Safety
Safety
Control
of P4
1987 P4
Margin
Margin
Margin
System
Produced
Revenues
(Ci/y)
(Ci/y)
(Ci/y)
Cost
(1987)
(mi I $/yr)
Baseline Po-210 Emission Rate (*)
2.400
2.640
3.000
Wet Scrubber
P = 2.5 kPa
20.00%
1.920
2.112
2.400
a
a
a
P = 6.2 kPa
55.00%
1.080
1.188
1.350
a
a
a
P = 10 kPa
90.00%
0.240
0.264
0.300
0.74
$2.07
1.38%
P = 20 kPa
95.00%
0.120
0.132
0.150
1.11
$3.11
2.07%
ESP
SCA = 39.4 (m/s)-1
75.42%
0.590
0.649
0.737
0.79
$2.21
1.48%
SCA = 78.8
-------
Table 8-36: Control Technology Costs and Estisated Po-210 Emission Sates
at Occidental's Columbia, Tennessee, Plant.
Control
Alternative
Po-210
Reaoval
Efficiency
Baseline Po-210 Eaission Rate (*)
Vet Scrubber
t ~ 2.5 kPa 20.00%
P - 6.2 kPa 55.00%
P = 10 kPa 90.00%
P = 20 kPa 95.00%
ESP
SCA = 39.4 (a/s)-1
SCA » 78.8 Emissions with low energy or spray scrubber. Additional syste
are added to these wet scrubbers except with the Spray Dryer/
Fabric Filter control alternative.
SOURCE; CHRISS]
8-55
-------
$19.44 per ion capacity, and from 1.92 to 12.96 percent of P4 revenues. For Rhone-Poulenc, the costs
range from $1.54 to $19.48 per ton capacity in Tennessee and from $2.07 to $8.60 per ton capacity
in Montana. The control technology costs range from 1.03 to 12.98 percent of the Tennessee plant's
1987 P6 revenues and from 1.38 to 5.73 percent of the Montana plant's revenues. The control
technology costs at the Occidental plant in Columbia, Tennessee, demonstrate ranges similar to the
other plants.
8.4.3 Estimates of Benefits and Costs.
Tables 8-37 through 8-41 present summaries of both the benefits and the costs of the control of Po-
210 emissions on the five operating elemental phosphorus plants. For each of the plants, nine
alternative emissions levels were examined, ranging from 10 Ci/y to 0.01 ci/y. A Po-210 emissions
limit of 10 Ci/y represents a "no additional control" limit, as the highest current emissions rate at any
plant is 10 Ci/y. No safety margin is assumed in these tables.
For each plant, the least-cost control method required to meet a given emissions level was chosen for
presentation. The annualized cost for the least-cost technology is presented as is the emission limit
that would be achieved by that technology, assuming no safety margin. Also presented in each table
is the annual risk, in cancers per year, that would result from the installation of the least-cost
technology.
The plant-by-plant analysis presented in Tables 8-37 through 8-41 is summarized, for all plants, in
Tables 8-42 and 8-43. The first of these tables presents the total annualized costs of alternative
emissions levels. Also presented is the increase in cost required to move from a given emissions level
to a lower one. At an emissions rate of 10 Ci/y, there is no cost to the industry, as no additional
emissions control is required. A cost of $2.4 million per year is experienced by the industry to meet
an emissions level of 2 Ci/y. A further reduction to emissions of 1 Ci/y would increase cost to
industry by $2.7 million. An emissions level of 0.01 Ci/y is estimated to cost S31.6 million per year.
Table 8-43 presents the total incidence and the incidence reduction achieved by alternative emissions
levels. At a level of 10 Ci/y of Po-210, the total number of cancers per year remains unchanged, at
an estimated 8E-02 per year (see Table 8-21), At an emissions level of 2.0 Ci/y, the incidence of
cancer falls to 3E-02, a reduction of 5E-02 cancers per year. At 1.0 Ci/y, the annual incidence
8-56
-------
fable 8-37i
Least-Cost Control Alternatives Bequlred to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by Plant
FMC - IDAHO
Emission Least- Total
Standard Cost Annualized
Alter- Cost
native ($mil '88)
10.0 Ci/y
2.0 Ci/y 10 kPa 2.43
1.0 Ci/y 400 SCA 2.84
0.75 Ci/y 600 SCA 3.65
0.6 Ci/y 800 SCA 4.43
0.2 Ci/y 800 SCA 4.43
0.1 Ci/y 800 SCA 4.43
0.06 Ci/y SD/PF 9.70
0.01 Ci/y HEFA 10.14
NOTESs 200 SCA =39.4 (m/s)-l; 40
600 SCA = 118 (m/a)-1; 800
SOURCE: [MRI88]
Annual Lifetime Annual
Emissions Risks to Risk
Estimate Nearby (Cancers/
(Curies) Individuals Year)
10.0 62-04 0.0600
2.0 11-04 0.0120
1.0 61-05 0.0060
0.38 2E-05 0.0023
0.14 8E-06 0.0008
0.14 8E-06 0.0008
0.14 8E-06 0.0008
0.043 3E-06 0.0003
0.0002 6E-08 0,00001
i SCA - 78.8 (m/s)-l;
SCA « 158 (ra/s)-l
8-57
-------
Table 8-38t Least-Cost Control Alternatives Required to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by Plant
MONSANTO - IDAHO
Emission
Standard
10.0 Ci/y
2.0 Ci/y
1.0 Ci/y
0.75 Ci/y
0.6 Ci/y
0.2 Ci/y
0.1 Ci/y
0.06 Ci/y
0.01 Ci/y
Least-
Cost
Alter-
native
600 SCA
800 SCA
800 SCA
SD/FF
HE PA
HEFA
HE PA
Total
Annual
Annualized Emissions
Cost Estimate
($mil '88} (Curies)
1.4
2 • 33
2.82
2.82
5.43
15.7
15.7
15.7
1.4
0.84
0.29
0.29
0.15
0.0006
0.0006
0.0006
Lifetime
Risks to
Nearby
Individuals
8E-05
81-05
5E-05
2E-05
2E-05
9E-06
6E-08
61-08
61-08
Annual
Risk
(Cancers/
Year)
0.003
0.003
0.00180
0.00062
0.00062
0.00032
0.0000021
0.0000021
0.0000021
NOTESi 200 SCA = 39.4 (m/s)-l; 400 SCA - 78.8 {ra/s)-lj
600 SCA « 118 (m/s)-l; 800 SCA » 158 (m/s)-l
SOURCES [MRI88]
8-58
-------
Table 8-39s Least-Cost Control Alternatives Required to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by Plant
OCCIDENTAL - TENNESSEE
Emission
Standard
10.0 Ci/y
2.0 Ci/y
1,0 Ci/y
0.75 Ci/y
0.6 Ci/y
0.2 Ci/y
0.1 Ci/y
0.06 Ci/y
0.01 Ci/y
Least-
Cost
Alter-
native
200 SCA
200 SCA
400 SCA
600 SCA
Total Annual
Annualized Emissions
Cost
(Smil '88)
0.64
0.64
0.85
1.12
Estimate
(Curies)
0.28
0.28
0.28
0.28
0.28
0.0?
0.07
0.02
0.01
Lifetime
Risks to
Nearby
Individuals
3E-05
3E-05
3E-05
3E-05
3E-05
8E-06
8E-06
2E-06
1E-06
Annual
Risk
(Cancers/
Year)
0.006
0.006
0.006
0.006
0.006
0.0015
0.0015
0.00043
0.00021
NOTES: 200 SCA « 39.4 (m/s)-l; 400 SCA « 78.8 (m/s)-l;
600 SCA ¦ 118 (m/s)-l; 800 SCA « 158 (m/s)-l
SOURCE: [MRI88]
8-59
-------
Table 8-40: least-Cost Control Alternatives Required to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by Plant
STAl/FFER - MONTANA
Emission Least-
Standard Cost
Alter-
nat 1" ve
Total Annual
Annualized Emissions
Cost Estimate
($uiil '88) {Curies)
Lifetime Annual
Risks to Risk
Nearby {Cancers/
Indi vidua Is Year)
10.0 Ci/y
2.0 Ci/y
1.0 Ci/y
0.75 Ci/y
0.74
0.74
0.74
0.74
6E-05
6E-05
6E-05
6E-05
0.005
0.005
0.005
0.005
0.6 Ci/y 10 kPa 0.74
0.2 Ci/y 800 SCA 0.91
0.1 Ci/y 800 SCA 0.91
0,06 Ci/y BOO SCA 0.91
0.01 Ci/y HEPA 2.96
NOTES: 200 SCA = 39.4 (m/s>-1; 400
600 SCA - 118 -1
SOURCE: £MR188]
8-60
-------
Table 8-41: least-Cost Control Alternatives Required to Meet Various Emissions
Standards with Subsequent Emissions and Risks, by Plant
STAUFFER - TENNESSEE
Emission Least- Total Annual Lifetime Annual
Standard Cost Annualized Emissions Risks to Risk
Alter- Cost Estimate Nearby {Cancers/
native ($mil '88) (Curies) Individuals Year)
10.0 Ci/y -- -- 0.31 3E-05 0.003
2.0 Ci/y -- -- 0.31 3E-05 0.003
1.0 Ci/y -- -- 0.31 3E-05 0.003
0.75 Ci/y -- -- 0.31 3E-05 0.003
0.6 Ci/y •- -- 0.31 31-05 0.003
0.2 Ci/y 6,2 kPa 0.92 0.14 1E-05 0.0014
0.1 Ci/y 200 SCA 0.97 0.08 8E-06 0.00077
0.06 Ci/y 10 kPa 1.15 0.031 3E-06 0.0003
0.01 Ci/y 600 SCA 1.67 0.01 1E-06 0.000097
NOTES: 200 SCA = 39.4 (m/s)-1; 400 SCA = 78.8 (m/s)-1;
600 SCA = 118 (m/s)-1; 800 SCA = 158 (m/s)-1
SOURCE; [MR 188]
8-61
-------
Table 8-42s Total Annualized Costs of Alternative Emissions standards
Sua of All Operating Plants,
Emission Total Annualized Increase in Annualized
Standard Cost Cost
<$mil '88) ($mil '88)
10.0
Ci/y
0.0
2,0
Ci/y
2.4
2.4
1.0
Ci/y
5-2
2.7
0.7B
Ci/y
6.5
1.3
0.6
Ci/y
8.0
1.5
0.2
Ci/y
12.3
4.3
0.1
Ci/y
27.9
IS.6
0.06
Ci/y
28.3
0.4
0.01 Ci/y
31.6
3.3
8-62
-------
.V.'''V:'T'abl'e.^8-;45 :.;:.V::To t at ¦¦} nc:i'dene eVv'Wt.h M:.t.erpa't.-i've: -£:m i ssions Standards
¦ :v:C:vvv.> :'; AI ^/-'Opera't vhs-.-.p I ^'n;t
\:R educ t i on' -
: O if- R 1 S k ¦
Fr,om:;8asejj:n.e;.
:v:K{-Caneers-"'-y-'¦
:;r.:.:V'pe r yea r:)- i
10.0
C i / y
8 £ 2
¦ ¦ .
;-.:P
c i /y
3 E - 2
5E - 2
¦ 5E - 2
C i /y
2 E - 2
7E-3
6E - 2
0 75
C i /y
2 E - 2
5E - 3
6E - 2
0 . 6
C i / y
1 E - 2
5 E - 3
7E - 2
0 . 2
C i /y
4 £ - 3
8 E - 3
7E - 2
0 . 1
c i / y
3 E - 3
9 E - 4
7E-2
0.06
c i /y
1 E -.3
2 E - 3
8E - 2
:^.-:0Kc
Ci/y
3 yv;;::
8E-4
8 E - 2
:T at a^lJJRiis'k¦v-.V'Rjsl'ctutt.iloini;
(Cancers of Risk
per year (Cancers
per year)
8-63
-------
becomes 2E-02, a reduction from current levels of 6E-02 cancers per year. At a level of 0,0i Ci/y,
the annual incidence falls to 3E-04, a reduction of 8E-02 cancers per year,
8.4,4 Alternatives for Ample Marein of Safety for Elemental Phosphorus Plants.
Table 8-44 presents the same benefit and cost information on an alternative-by-alternative basis
rather than a plant-by-plant basis. For each alternative emission level, the least-cost control system,
its annualized cost, the corresponding incidence and incidence reduction are presented. This
information is shown for all plants as is the total cost and the total incidence. The change in cost
from alternative to alternative is shown at the bottom of each section of the table. As in Tables 8-
37 through 8-41, the emissions levels analyzed range from 10.0 Ci/y to 0.01 Ci/y.
Table 8-44a is a continuation of Table 8-44 involving a shift in emphasis from emissions to control
technologies. Certain control technologies have been selected for analysis. As before, Alternative
I is the "no additional control" alternative. As no new control equipment is required, there are no
additional costs to the industry and no reduction in cancers per year.
Alternative X would require high energy scrubbers on the two largest plants and no further controls
on the smallest plants. A large plant was defined as having a production capacity over 75,000 tons
per year of elemental phosphorus, i.e., Monsanto and FMC. This alternative is identical to alternative
II, which limited emissions to 2.0 Ci/y, with a cost to the industry of $2.43 million per year. The
alternative would reduce incidence by 0.0569 cancers per year.
Alternative XI, requiring high energy scrubbers on all plants, would cost the industry an estimated
$4.78 million per year. The incidence of cancer would be reduced by 0.06 cancers per year. Two
other alternatives were examined, one requiring SD/FF on the two large plants and high energy
scrubbers on small plants, and another requiring HEP A filters on the large plants and 600 SCA
precipitators on the smaller ones. The costs and benefits of each are presented as Alternatives XII
and XIII in Table 8~44a.
The results of the analysis of costs and benefits are summarized in section 8.1, the Introduction and
Summary.
8-64
-------
Table 8-44 i Alternatives for Aaple Margin of Safety for Elemental Phosphorus Plants, According to Various Emissions Levels.
Plant
FMC - ID
Monsanto - ID
Occidental - Sit
Stauffer - MT
Stauffer - TN
TOTAL
Incremental
I.
Ho Control
(10 Ci/y)
Incidence
Control Annual1red Incidence Reduction
System Cost {Cancers (Cancers
Choice ($nil '88) per Tear) per Year)
0.0
6E-02
3B-03
6E-03
51-03
3E-03
81-02
II.
Emissions
(2 Ci/y)
III.
Emissions
(1 Ci/y)
Incidence : Incidence
Control Annualized Incidence Reduction : Control Annualized Incidence Reduction
Systran Cost (Cancers (Cancers ; System Cost (Cancer® (Cancers
Choice ($sil '88) per Year) per Year) s Choice (Sail '88) per Year} per Year}
10 kPa
2.43 1E-02
31-03
61-03
51-03
3E-03
2.43 3E—02
2.43 5B-02
5B-02 : 400 SCA
0 : 600 SCA
:
0 8
:
0 .
0 S
t
5E-02 :
:
2.84 68-03
2.33 2E-03
6E-03
51-03
3B-03
5.17 2E-02
2.74 7E-03
SE-02
1E-03
0
Incremental » the change in annualized coat and in cancer incidence from one alternative to the next.
oo
i
o>
U1
-------
labia 8-44 : Alternatives for Ample Margin of Safety for Elemental Phoaphorus Plants, According to Various Emission Levela.
Plant
PMC - ID
Monsanto - ID
Occidental - XII
Stauffer - MT
Stauffer - TN
TOTAL
Incremental
IV.
Emiaaiona
(0.75 Ci/y)
Incidence
Control Annualized Incidence Reduction
System 'Coat (Cancer* (Cancers
Choice ($nil '88) per Year) per Year)
600 8CA
800 SCA
3.65
2.82
6.47
1.3
2E-03
6E-04
61-03
5E-03
3E-03
2E-02
51-03
6E-02
2B-03
0
6E-02
V. !
Emissions :
(0.6 Ci/y) :
Incidence:
Control Annualized Incidence Reduction: Control
System cost (Cancers (Cancers : System
Choice ($mil '88) per Year) per Year): Choice
:
800 SCA
800 SCA
10 kPa
4.43
2.82
0.74
7.§9
1.52
81-04 6E-02
VI. s
Emissions :
(0.2 Ci/y)
Incidence:
Annualized Incidence Seduction:
Cost (Cancers (Cancers :
($¦11 '88) per Year) per Year)s
800 SCA
SD/FF
6E-04 22—03 :
:
61-03 01+00 : 200 SCA
:
2E-03 3E-03 ; 600 SCA
:
3B-03 0E+00 : 6.2 kPa
:
IE-02 6E-02 8
5B-03 s
4.43
5.43
0.64
0.91
0.92
12.33
4.34
8E-04 SE-02 I
?
3E-04 3B-03 ;
s
2E-03 5B-03 t
:
1E-04 51-03 S
t
11-03 2B-03 I
4E-03 7E-02 s
BE—03 :
Incremental ¦ the change in annualized cost and in cancer incidence fcon one alternative to the next.
-------
Table 8-44 : Alternatives for Ample Margin of Safety for Elemental Phosphorus Plants, According to Various Emissions levels.
VII.
Emissions
(0.1 Cl/y)
VIII.
Emissions
(0.06 Ci/y)
Incidence: Incidence
Control Annualized Incidence Reduction: Control Annualized Incidence Seduction
Slant
FMC - ID
Mcmunto - ID
Occidental - TR
Stauffer - HT
Stauffer - TN
TOTAL
Incremental
System Cost (Cancers (Cancers
Choice ($mil '88) per Year) per Year)
SD/FF
HEPA
200 BCA
800 BCA
200 BCA
9.7
15.7
82-04 6E-02
System Cost (Cancers (Cancers
Choice ($mil '88) per Year) per tear)
SD/FF
21-06 3S-03 t HEPA
E
0.64 21-03 5E-03 t <00 SCA
1
0.91 11-04 51-03 t 800 SCA
t
0.97 81-04 21-03 ! 10 kPa
27.92 31-03 7E-02 I
15.59 91-04 ;
9.7
15.7
0.8$
0.91
1.15
31-04 61-02
21-06 31-03
4E-04 61-03
1E-04 51-03
IX. :
Emissions :
(0.01 Cl/y) i
Incidence:
Control Annualized Incidence Seduction:
System Cost (Cancers (Cancers i
Choice ($mil '88) per Year) per Year)s
HEPA
HEPA
600 SCA
BEBA
20.31
0.39 21-03
31-04 31-03 : 600 SCA
:
11-03 81-02 s
10.14 11-05 61-02 s
I
15.7 2E-06 31-03 1
1.12 21-04 6E-03 J
t
2.96 71-06 5B-03 I
1.67 11-04 31-03 t
31.59 31-04 81-02 s
3.28 61-04 s
Incremental - the change is annualized coat and in cancer incidence from one alternative to the next.
oo
Ov
-------
Sable 8-44a: Alternatives for Ample Margin of Safety for Elemental phosphorus Plants, Using Different Control Technologies.
Plant
FMC - ID
Monsanto - ID
Occidental - TM
Rhona-Pouianc - MT
Rhona-Poulenc ~ TS
TOEM,
Incremental
I. IX. i XI.
Mo Control : High-Energy scrubbers on l>arge Plants s High-Energy Scrubbers on All Plant.®
(10 Cl/yS s Ho Further Controls on Small Plants s
t :
Incidence : Incidence t Incidence
Control Annualized Incidence Seduction s Control Annualized Incidence Deduction : control Annualized Incidence Reduction
System Cost {Cancers (Cancers i System Cost (Cancers (Cancers » System Cost (Cancers (Cancers
choice (Soil '88) par XaarJ par Year) s Choice ($mil '88) per Year) per Year) i Choice (Srail '88} per Tear) per reex)
0.0
SE-02
3E-03
61-03
5E-03
3E-03
81-02
0 : 10 kPa
!
0 :
:
0 j
:
Q ,
0 s
:
0 s
8
2.43 1B-Q2
0 3E-03
0 6E-03
0 5B-03
0 3E-03
2.43 3S-02
2.43 52-02
5E-02 s 10 M?a
:
0 s
:
0 s 6.2 kFs
0 5 6.2 kPa
0 s
5E-02 :
6.2 kPa
2.43 1S-02
3S-03
0.75 38-03
0.S8 2S-03
0.92 1E-03
4.78 28-02
2.35 78-03
5B-02
08*00
3B-03
3E-03
21-03
81-02
Incremental « the* change is annualissd cost and in cancer incidence
from one alternative to the next.
00
-------
Table 6-44a: Alternatives for Ample Margin of Safety for Elemental Phosphorus Plants, Using Different Control Sechnologii
Plant
XII.
SD/FF on Large Plants
6.2 kPa on Small Plants
s XIII. 5
: HEPA filters cm Large Plants :
: 600 SCA on Snail Plants :
: :
Incidence : Incidence:
Control Annualized incidence Reduction s Control Annualized Incidence Seduction:
System Cost (Cancers {Cancers : System Cost (Cancers (Cancers :
Choice ($mil '68) per Year) per Year) s Choice (Smll 'SB) per Year) per Tear):
FMC - ID
SD/FF
SD/FF
Monsanto - ID
Occidental - TO 6.2 kPa
Bhone-Poulenc - MS 6.2 W?a
Hhone-Poulenc - 2H 6.2 kPa
TOTAL
Incremental
9.7
5.43
0.75
0.68
0.92
17.48
12.7
31-04
3B-04
31-03
2E-03
11-03
71-03
1E-02
6E-02
EEPA
31-03 I HBPA
;
3E-03 : 600 SCA
:
3E-03 s 600 SCA
s
2S-03 s 600 SCA
:
7E-02 !
s
10.14
15.7
1.12
0.87
1.67
29.50
12.02
11-05 61-02 :
:
2E-06 32-03 s
:
2E-04 61-03 :
:
51-04 51-03 s
;
1S-04 31-03 :
:
81-04 81-02 :
61-03 I
Incremental - the change in annualized coat and in cancer incidence
from one alternative to the next.
09
-------
8.5 Economic Impact Analysis
Economic impacts occur when regulations alter the costs of production. Changes in the cost of
production may lead to a change in product price and demand, thus altering the structure of the
market in which the product is sold. The impacts on producers, consumers, workers and communities
may be positive or negative, may depend on the overall state of the economy, and may be transitional
or permanent. The impacts may represent losses in economic efficiency or they may be
distributional, indicating shifts among economic entities (e.g., among firms or among groups of
workers).
Government regulations generally occur when the market fails to meet all of the objectives of society.
Regulations are designed to mend the market imperfections by, for example, internalizing to a
polluter the cost of environmental damage caused by that pollution.
As shown in the previous sections of this chapter, limiting the allowable emissions of polonium-210
at various alternative levels below 10 Ci/y would require the five plants operating in 1988 to install
and operate pollution control equipment designed to reduce its particulate emissions. The technology
selected by the affected plant would depend on the level of standards and individual firm
preferences. Varying levels and proportions of capital and operating expenses would be incurred
based on the technology selected. These costs would result in an increase in the unit production cost
of the affected facilities. The sum of these pollution control expenditures is referred to as the private
real resource cost.
When a regulation imposes real resource costs on firms that change the unit cost of production,
manufacturers will attempt to minimize the effect on profitability. This may result in attempts to
reduce input costs including raw materials and wages, or to increase prices. If there is an increase
in price, quantity demanded of the product may be reduced, and demand for competitors' output or
substitute products may increase. These changes can lead to layoffs at the affected plant, reduced
income in the community where the plant is located, and effects on the structure of the market.
These effects on market structure include shifts in the price elasticity for the product, decreases in
overall quantity demanded, and redistribution of market positions for each competitor and producer
of substitute products.
The extent to which a regulated manufacturer may effectively pass on increases in cost will depend
on the competitive environment in which the products are produced and sold and on the elasticity
8-70
-------
of demand. The elasticity of demand is a measure of the sensitivity of the consumers to changes in
price. In some markets, a small change in price could lead to a large reduction in volume sold, while
in other markets large price changes may have only marginal effects on volume. As a regulated
manufacturer increases prices, quantity of the products demanded will usually fall. The rate at which
volume falls will determine the change in total revenues that results from a change in price. If the
market price of the product changes (all manufacturers incur higher costs), consumers use less of the
product and some of the utility associated with consumption of the product will be lost. Consumers
who continue to use the same amount of the product at higher prices will have to allocate a larger
portion of their budgets to this consumption, thus reducing savings or consumption of other goods
and services.
The control of Po-210 emissions through the setting of an emissions standard will result in changes
in the cost of producing elemental phosphorus only if an emission standard lower than 10 Ci/y is
chosen, according to the emissions data gathered during 1988 (see section 8.3). The structure of this
industry and the nature of the market in which the output is utilized adds significant uncertainty to
the measurement and allocation of expected economic impacts. Some of these characteristics include
the following:
o The industry has contracted substantially over the past two decades, closing over
half the plants and reducing capacity enormously.
o Elemental phosphorus is an intermediate product utilized to produce chemical
compounds used in consumer goods that are sold in highly competitive markets
(detergents, soft drinks, etc. - see section 8.2).
o All plants are owned by large, highly integrated Fortune 500 corporations that
consume virtually all the P4 output in company-owned chemical plants.
o The owners of the P4 plants own or have extraction leases for phosphate rock, an
exhaustible resource that is the principle input to production.
o The plant most likely to require new emissions control equipment is the largest
plant, accounting for over one-third of industry capacity.
8-71
-------
o The affected plant has among the lowest production costs due to economies of
scale and regional differences in input prices.
o The long range prospects for current elemental phosphorus markets are uncertain,
and extensive industry research and development efforts over the past fifteen
years have failed to develop any significant new markets.
o Bans or restrictions on phosphate use in detergents have been imposed in some
states.
These and other factors make it difficult to predict the ability or desirability of the regulated plant(s)
to pass on all or part of these pollution control costs to consumers through price increases. In the next
section, the costs of producing elemental phosphorus at the currently operating plants are compared,
A subsequent section presents some methods for bounding the potential economic impacts of the
proposed alternatives.
8.5.1 Production Costs
The primary components of the cost of producing elemental phosphorus are phosphate rock, coke,
electricity and labor. Together, these account for 80 to 88 percent of the cost of producing a ton of
phosphorus. Prices of these materials for each producer and plant vary, with the western plants
having a significant cost advantage compared to Tennessee plants. The components of cost for
elemental phosphorus and estimated costs for each plant are described in the following section.
8.5.1.1 Components of Cost
The inputs to elemental phosphorus production were investigated for a hypothetical Tennessee plant
by Arthur D. Little [ADL73], and for FMC by EPA in 1984 [EPA84e], Additional data on costs are
published in SRI's Chemical Economics Handbook, The ranges in the amounts and prices of each
input needed to produce a ton of phosphorus seen in these studies are provided in Table 8-45. Prices
are indexed to June, 1988, dollars.
8-72
-------
Table 8-45; Cost of Elemental Phosphorous
Cost Item
Units
Units/Ton of Phosphorus
Cost/Unit1
Cost/Ton of Phosphorus
RAW MATERIALS
Phosphate Rock
tons
10-12.5
$12.35-127.80
$123.5-$347.50
Silica
tons
0.79
13.22
10.44
Coke
tons
1.4-1,5
121.56
170.18-182.34
Electrodes
lbs
0.42
.79
.33
UTILITIES
Electricity
kWh
13,000-15,200
0.0168-0.0485
218.4-737.2
Water
Mgal
20.00
.137
2.73
Fuel
MSCF
12.00
1.37
16.38
OTHER
Labor
n.a.
n.a.
n.a.
204.67-275.74
Operating Supplies
B.St.
n.a.
n.a.
13.68
Maintenance
n.a.
ii.a«
n.a.
136.96
Taxes
n.a.
n.a.
n.a.
30,81
Subtotal
928.08-1754,11
GS&A(1G%)
n.a.
n.a.
n.a.
92.81-175.41
TOTAL COSTS
n.a.
n.a.
n.a.
1020.89-1929.52
^Indexed to June, 1988 prices
SOURCE: [EPA84b]
-------
As the table shows, the total cost per ton could range from $1,021 to $1,930; however, it is unlikely
that the variation in costs is this broad. The primary inputs to production and estimates of their cost
for each plant are discussed below,
8.5.1.1.1 Phosphate Rock
Phosphate rock costs from $12.35 to $27.80 per ton, delivered. At the high end of the range is the
beneficiated rock used by plants in Tennessee. When this higher quality rock is used, less rock may
be required (10 tons of rock per ton of phosphorus, compared to 12.5 tons) [ADL73, EPA84e], Lower
grade material is usually less expensive, but the proximity and convenience of transporting the rock
to the plant is the most important cost factor. Idaho rock is relatively low cost, because it is obtained
from captive mines close to elemental phosphorus plants. Rhone-Poulenc's phosphate rock costs for
its Montana plant are relatively high because of greater transportation costs (SRI83). The estimated
costs of phosphate rock for each plant and producer are summarized in Table 8-46.
8.5.1.1.2 Coke
For each ton of phosphorus produced, 1.4 to 1.5 tons of coke are required, depending on quality. The
cost of the coke per ton to the producer depends on its quality, grade, and the value at which it is
transferred when captively produced. The cost of coke per ton of phosphorus is levelled across
producers by this cost and input structure: lower quality coke is lower-priced, but more is required,
while higher quality coke is higher-priced, and less is required [SRI83]. The cost of coke per ton of
phosphorus used in this analysis was estimated to range from $170.18 to $182.34. This cost assumes
1.42 tons of coke are used per ton of phosphorus3 and that the price per ton is $121.56, the national
average market price of coke [SRi83j.
8.5.1.1.3 Electricity
Production of a ton of phosphorus requires 12,000 to 15,000 kWh of electricity. Estimates of the cost
of this electricity range from $0.0168 to 0.0485 per kWh {SRI83J.
'Unpublished EPA data.
8-74
-------
Table 8-46: Costs of Phosphate Rock Used in Phosphorus Production
Unit Cost
Producer Location $/Ton
Monsanto Columbia, TN 27,70
Soda Springs, ID 19.15
FMC Pocatello, ID 19.15
Stauffer c Mt. Pleasant, TN 27,70
Silver Bow, MT 19.50
Occidental Columbia, TN 27,70
'indexed to June, 1988 prices.
SOURCE: [JFA86]
Tons of Phosphate Rock Mined/ Phosphate Rock Cost
Ton of Phosphorus $/Ton
10.00
277.00
12.50
239,36
12.50
239.36
10.00
277.00
12.50
239.36
10.00
277.00
-------
Plants served by TVA have witnessed steadily increasing rates since 1976, as rates have been more
and more dependent on coal purchase commitments. Power rates in Idaho were stable until the last
part of the 1970s, and for Montana until 1980. Rates are expected to continue to grow for FMC and
Monsanto in Idaho because of increasing reliance on coal-fired electricity, Rhdne-Poulenc, which
was previously purchasing power from Bonneville, changed sources to Montana Power and Light in
late 1982 in an effort to control costs [SRI83], The estimated cost of electricity for each plant and
producer is shown in Table 8-47.
8.5.1.1.4 Labor
The fourth major cost of producing phosphorus is labor. Average labor costs in the industry are
estimated to range from $36,001 to $43,201 per year'' per worker and labor costs per ton of
phosphorus from $204.13 to $275.015, Labor costs for each producer and plant are detailed in Table
8-48.
8.5.1.2 Total Costs per Plant
The cost of producing a ton of phosphorus is estimated to range from approximately $1,260 in
Montana and Idaho, to over $1,700 in the Tennessee plants. These estimates are comparable to the
estimates provided by SRI in the Chemical Economics Handbook of $1,070 to $1,180 per ton of
phosphorus in the western states and $1,315 to $1,555 in Tennessee, when indexed to 1988 dollars.
Costs by plant are summarized in Table 8-49.
8.5.2 Measuring Economic Impacts
The degree to which the elemental phosphorus industry will be affected by pollution control costs,
and the ability of producers to mitigate these impacts through price changes will be determined by
the market structure of the industry. As noted in sections 8,2 and 8,5.1, several alternative theories
could be used to describe this market. First, the output of each plant in this industry is almost totally
^Industry information for 1983, updated to 1988 dollars.
5JFA estimates
8-76
-------
Table 8-47: Costs of Electricity Used in Phosphorus Production
Producer
Monsanto
Location
Columbia, TN
Soda Springs, ID
Electricity
Required
KWH/Ton
13,000
13,000
Unit Cost
of Electricity
S/KWH
0.0485
0.0231
Cost of
Electrictity
S/Ton
630.38
300.83
QG
I
--4
^-4
FMC
Stauffer
Pocateiio, ID
Mt. Pleasant, TN
Silver Bow, MT
13,000
13,000
13,000
0.0231
0.0485
0.0231
300.83
630.38
300.83
Occidental
Columbia, TN
13,000
0.0485
630.83
SOURCE: [JFA86]
-------
Table 8-48: Labor Costs.
Plant Location
Monsanto
FMC
Rbdne-Poulenc
Occidental
Columbia, TN
Soda Springs, ID
Pocatello, ID
Mt. Pleasant, TN
Silver Bow, MT
Columbia, TN
Employees
440
397
600
305
185
275
^Production is estimated 1984 production.
SOURCE; [EPA84b]
$/Man Year ((million) Production(tons)1 S/Ton Phosphorus
39,878
43,201
17.55
17.15
63,800
76,500
275.01
224.19
39,878
23.93
106,300
225.09
36,001
39,878
10.97
7.40
42,500
34,000
258.35
216.98
36,001
9.89
48,500
204,13
-------
Table 8-491 Stanary of Coat Mmtimatmm, by Plant:
Phosphate
FrodBcer iocatlon Bock Electricity
Monsanto
SMC
Rh ne-
Poulenc
Occidental
Columbia, TN
$277,
.01
$630,
.80
Soda Springs, ID
$239
.36
$301
.46
Pocatello, id
$239,
,36
$301.
.46
Mt. Pleasant, TH
$277,
,01
$630.
.80
Silver Bow, MT
$239,
,36
$301,
.46
Columbia, TN
$277,
.01
$630.
.80
CO
>4
SO
total
Dotal laelwiiisg
Other Excluding
Ijibor Coke Subtotal Costa 6S&& at 10%
$275.02 $172.62 $1,355.45
$224.19 $172.62 $937.63
$225.09 $172.62 $938.53
$258.35 $172.62 $1,338.78
$216.39 $172.62 $929.83
$204.13 $172.62 $1,284.56
$211.78 $1,567.23 $1,723.§5
$211.78 $1,149.41 $1,264.35
$211.78 $1,150.31 $1,265.34
$211.78 $1,550.56 $1,705.62
$211.78 $1,141.61 $1,255.71
$211.78 $1,496.34 $1,645.57
-------
consumed by other plants owned by the parent corporation. The downstream plants process this
elemental phosphorus into various compounds of phosphorus that are sold as inputs to the production
of highly-competitive goods. Substitute inputs for the phosphorus are available and widely used.
Thus, the demand for elemental phosphorus is derived from the demand for products in highly-
competitive, price-sensitive markets. Therefore, phosphorus producers may face a flat demand
curve, as in a competitive market, even though there are only four producing companies. A flat or
nearly-flat demand curve suggests that the manufacturer would have little opportunity to pass on
increases in unit costs through price increases.
An alternative description of the elemental phosphorus industry is that it is an oligopoly with a strong
price leadership. There are only four manufacturers, and production costs at the western plants are
lower than at plants elsewhere. The low-cost manufacturers have the ability to set the market price
at a profit-maximizing production level. The higher cost manufacturers would thus be price takers,
because, if market price were set at the marginal cost of the low-cost producers, the higher-cost
producers would have to sell their product at this price, even if it meant losing money on each unit
sold, or leave the industry. As seven higher-cost plants have been closed over the past two decades,
it would appear that the cost of closing these plants was less than the cost of selling products below
their individual marginal cost of production.
A collusive oligopoly will attempt to operate as a monopoly, setting industry marginal revenue equal
to industry marginal cost to determine output. The price is then established by the demand curve at
a level above that which would exist in a competitive market. Thus, industry maximizes its profit.
Output and revenue for each manufacturer are determined by the manufacturer's marginal costs and
the price level. While it may not be possible in the absence of collusion for the oligopoly to operate
in this fashion, firms in such an industry would likely be able to maintain price above marginal cost
(the competitive price) and thus earn excess profits.
Firms in any market will determine their level of output based on their marginal cost. By definition,
fixed costs do not vary with the level of output. Therefore, they do not enter into the production
rate decision since firms in general will continue to produce as long as marginal revenue is greater
than or equal to marginal cost. The cost of regulatory compliance presents a special case. While the
expenditures for pollution control capital equipment are clearly fixed costs, operating costs for this
equipment are not so clearly categorized. Usually, operating cost is thought of as a variable cost.
That is, if no production occurs, no operating costs are accrued. However, in the case of these
particular regulations of the elemental phosphorus industry, the capital and operating costs vary
8-80
-------
little with output. The assumption here is that any minimal costs required to meet a standard may
be viewed as fixed costs, suggesting that no changes in output or price would be expected as a result
of the compliance with the standards. In this case, all the impacts will be born by the affected
manufacturer in the form of lower profits. If an emissions limit of 10 Ci/'y is chosen, there would
be no cost and no economic impact.
That phosphate rock is an exhaustible resource owned by the regulated industry requires some special
consideration. The resource stock is an asset held by its owner, the value of which is determined by
the size of the asset and the present value of the difference between market price and extraction cost
in any period. The rate of extraction selected by the owner of the resource will depend on the
structure of the market in which the resource is sold, forecasts of the future prices for the product,
and forecasts of interest rates. If, for example, the resource owner expected the rate of growth in
the net price (market price less extraction cost) to be less than the interest rate, that owner would
extract the resource as quickly as possible and convert it to a new asset that would return at least the
market rate of interest. In general, it would be expected that a monopolist would set prices high
enough that the extraction rate would be slower than that of a producer in a competitive market. In
an oligopoly, the resource would be extracted faster than in the monopoly, but slower than in the
competitive market, either the price and extraction rates approaching the competitive case as the
number of firms in the industry became larger. In this case, several stocks of the exhaustible
resource are available with each plant being fed by a specific mine. The low-cost producer is able
to earn a higher return from its resource than are the other plants. This higher return allows the
low-cost producer to earn an economic rent on its stocks of phosphate rock. By imposing a new
environmental cost that is mostly fixed cost, the available rent that could be earned by the low-cost
producer is reduced by the amount of the pollution abatement costs.
While it is uncertain to what extent product prices and quantity demanded of elemental phosphorus
will be affected by these standards, if an emissions level of 10 Ci/y is chosen, there will be no change
in production levels at the regulated facility. It is assumed that the product price is unchanged.
Therefore, there are no consumer impacts, no change in employment levels and no community
impacts. The entire impact of the standard would be calculated as a reduction in profits for the
affected firms. Table 8-50 presents the estimated value of elemental phosphorus production, the total
revenue of the parent corporation, and the percent of total revenues accounted for by elemental
phosphorus in 1986. In that year, Monsanto and FMC, the two firms potentially affected by the 1984
8-81
-------
Table 8-50: Revenues from Elemental Phosphorus Production and Total Corporate Revenues
(1986).
Estimated
Elemental
Phosphorus
Revenue5'
(in millions)
Total
Corporate
Revenue
(in millions)
Elemental
Phosphorus
as a Percent of
Total Revenue
FMC
Monsanto
Rhdne-PoUlenc
Occidental
$174.7
$121.1
$110.9
$72.7
$3,078.9
$6,879.0
$8,107.8
$15,525.2
5.7%
1.8%
1.4%
0.5%
TOTAL
$479.4
$33,590.9
-'Estimated revenue = estimated production x price
Estimated production « 85 percent of capacity
Price * $0.75 per pound or $1,500 per ton
Revenue for Rhdne-Poulenc = 51,642 FF x $0.157/FF
1.4%
8-82
-------
regulation, had 1,8 and 5.7 percent of their revenues associated with elemental phosphorus
production. In 1987, elemental phosphorus revenues accounted for an estimated 5.7 percent of FMC's
total corporate revenues. Table 8-51 shows the level of capital expenditures normally undertaken
by each firm, required capital expenditures under different regulatory alternatives and the percentage
of total capital expenditures represented by the pollution control capital expenditures.
8.5.3 Regulatory Flexibility Analysis
The Regulatory Flexibility Act (RFA) requires regulators to determine whether proposed regulations
would have a significant economic impact on a substantial number of small businesses or other small
entities. If such impacts exist, regulators are required to consider specific alternative regulatory
structures to minimize the small entity impacts without compromising the objective of the statute
under which the rule is enacted. Alternatives specified for consideration by the RFA are tiering
regulations, performance rather than design standards, and small firm exemptions.
The four firms operating plants in this industry are major diversified corporations, the smallest of
which was ranked 131 on the Fortune list of the 500 largest U.S. companies in 1987. The Pocatello
plant accounts for over one-third of national production and probably enjoys the lowest cost structure
due to economies of scale and regional cost differences. It is unlikely that this situation will change
after the imposition of a Po-210 standard. In light of the fact that the four smallest plants in the
elemental phosphorus industry are expected to incur no compliance costs as a result of any regulatory
alternatives under consideration, no significant small business impact will occur.
8-83
-------
Table 8-51: Impact on Capital Expenditures.
Producer Capital Expenditures, 1986
Costs On millions)
Monsanto1 520.0
FMC 232.8
2
Rhdne-Poulenc
797.3
Standard
Option
(Ci/Year)
Estimated Capital
Costs of Emissions
Control (u millions)
Emissions Costs
as a Percent of
1986 Capital
10.00
2.00
1.00
0.75
0.60
0.20
0.10
0.06
0.01
0.00
0.00
12.89
15.72
15.72
10.38
2.87
2.87
2.87
0.00
0.00
2.48
3.02
3.02
2.00
0.55
0.55
0.55
10.00 0.00 0-00
2.00 8.50 3.65
1,00 15.50 6-66
0.75 20.28 8.71
0.60 24.79 10.65
0.20 24.79 10.65
0.10 17.33 7.44
0.06 17.33 7.44
0.01 4.20 1-80
10.00
2.00
1.00
0.75
0.60
0.20
0.10
0.06
0.01
0.00
0.00
0.00
0.00
1.89
7.89
7.89
9.14
6.57
0.00
0.00
0.00
0.00
0.24
0.99
0.99
1.15
0.82
-------
Table 8-51 (contd): Impact on Capital Expenditures.
Producer
Costs
Capital Expenditures, 1986
pit millions)
Standard
Option
(Ci/Year)
Estimated Capital
Costs of Emissions
Control (in millions)
Emissions Costs
as a Perceal of
1986 Capital
Occidental 804.0 10.00 0.00 0.00
2.00 0.00 0.00
1.00 0.00 0.00
0.75 0.00 0.00
0.60 0.00 0.00
0.20 2.51 0.31
0.10 4.53 0.56
0.06 3.23 0.40
0.01 8.6 1.07
oo
co |fia$ed on 1988 Po-210 emissions and risk data.
4/1 Converted from French Francs using exchange rate of 0.1571 FF per Dollar.
SOURCE: 1986 Annual reports for Monsanto, FMC, Rhdne-Foulenc, and Occidental.
-------
REFERENCES
ADL73 Arthur D. Little, Economic Analysis of Proposed Effluent Guidelines for the Industrial
Phosphate Industry. Prepared for the Environmental Protection Agency, August,
1973.
An81 a: Andrews, V.E., Emissions of Naturally Occurring Radioactivity from Stauffer Elemental
Phosphorous Plant, ORP/LY-81-4, EPA, Office of Radiation Programs, Las Vegas,
Nevada, August 1981.
An81 b: Andrews, V.E., Emissions of Naturally Occurring Radioactivity form Monsanto
Elemental Phosphorous Plant, ORP/LV-81-5, EPA, Office of Radiation Programs, Las
Vegas, Nevada, August 1981.
CEN78 "Key Chemicals: Phosphorus," Chemical Engineering News, April 24, 1978.
CEN79 "Key Chemicals: Phosphorus," Chemical Engineering News, April 24, 1979.
CEN81 "Key Chemicals: Phosphorus," Chemical and Engineering News, March 23, 1981.
CEN83 "Key Chemicals: Phosphorus," Chemical and Engineering News, July 11, J983.
CEN84 "Key Chemicals: Phosphorus," Chemical and Engineering News, July 30, 1984.
CW88j "Soaps and Detergents... More Punch in the Package," Chemical Week, January 20, 1988,
EAB87 U.S. Environmental Protection Agency, EAB Control Cost Manual, Third Edition,
Research Triangle Park, February, 1987.
EPA77: Environmental Protection Agency, Radiological Surveys of Idaho Phosphate Ore
Processing -- The Thermal Plant, ORP/LV-77-3, EPA, Office of Radiation Programs,
Las Vegas, Nevada, 1977.
EPA84a: Environmental Protection Agency, Radionuclides: Background Information Document
for Final Rule, Volume II, EPA 520, Office of Radiation Programs, Washington, D.C.,
EPA 520/1-84-022-2, October 1984.
EPA84a: Environmental Protection Agency, Radionuclides: Background Information Document
for Final Rule, Volume II, EPA 520, Office of Radiation Programs, Washington, D.C.,
EPA 520/1-84-022-2, October 1984.
EPA84b: Environmental Protection Agency, Regulatory Impact Analysis of Emission Standards
for Elemental Phosphorous Plants, EPA, Office of Radiation Programs, Washington, D.C.,
June 1984.
EPA84c: Environmental Protection Agency, Emissions of Lead-210 and Polonium-210 from
Calciners at Elemental Phosphorous Plants: FMC Plant, Pocatello, Idaho, EPA, Office
of Radiation Programs, Washington, D.C., June 1984.
8-86
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EPA84d; Environmental Protection Agency, Emissions of Lead-210 and Polonium-210 from
Calciners at Elemental Phosphorous Plants: Stauffer Plant, Silver Bow, Montana, EPA,
Office of Radiation Programs, Washington, D.C., August 1984.
EPA84e "Preliminary Analysis of Potential Impacts of $20 Million Compliance Cost at FMC
Plant," memorandum from Rod Lorang and Barry Galif, Sobotka, Inc. to Byron Bunger,
EPA, February 6, 1984.
EPA89 Vol. 2., Environmental Impact Statement
FMC86 FMC Corp., Annual Report, 1986.
GARD78 CARD, Inc. Capital and Operating Costs of Selected Air Pollution Control Systems,
prepared for the U. S. Environmental Protection Agency, Research Triangle Park, N.C.,
December, 1978.
MCP85 Mannsville Chemical Products Corp., "Phosphorus," Chemical Products Synopsis,
Cortland, New York, January 1985.
MRI84a; Midwest Research Institute, Analysis of Achievable Po-210 Emission Reductions and
Associated Costs for FMC's Pocatello, Idaho, Plant, For the Office of Radiation
Programs, EPA, under contract number 68-02-3817, August, 1984.
MRI88 Midwest Research Institute, for Office of Air Quality Planning and Standards, U. S.
Environmental Protection Agency, Characterization and Control of Radionuclide
Emissions from Elemental Phosphorus Production, Research Triangle Park, N.C.,
February 19, 1989.
MY87 William Stowasser, "Phosphate Rock," Minerals Yearbook, 1986 pre-print, Volume 1,
1987, p.14.
Ra84a: Radian Corporation, Emission Testing of Calciner Off-gases at FMC Elemental
Phosphorous Plant, Pocatello, Idaho, Volumes I and II, Prepared for the Environmental
Protection Agency under Contract No. 68-02-3174, Work Assignment No. 131, Radian
Corporation, P.O. Box 13000, Research Triangle Park, NC, 1984.
Ra84b: Radian Corporation, Emission Testing of Calciner Off-gases at Monsanto Elemental
Phosphorous Plant, Soda Springs, Idaho, Volumes I and II, Prepared for the
Environmental Protection Agency under Contract No. 68-02-3174, Work Assignment No.
133, Radian Corporation, P.O. Box 13000, Research Triangle Park, NC, 1984,
Ra84c; Radian Corporation, Emission Testing of Calciner Off-gases at Monsanto Elemental
Phosphorous Plant, Soda Springs, Idaho, Volumes I and II, Prepared for the
Environmental Protection Agency under Contract No. 68-02-3174, Work Assignment No.
133, Radian Corporation, P.O. Box 13000, Research Triangle Park, NC, 1984.
SAI84: Science Applications, Inc., Airborne Emission Control Technology for the Elemental
Phosphorous Industry, Final Report to the Environmental Protection Agency, Prepared
under Contract No. 88-01-6429, SAI, P.O. Box 2351, La Jolla, CA, January 1984.
SRI80 SRI, Chemical Economics Handbook, March 1980.
SR183 SRI, Chemical Economics Handbook, January 1983.
8-87
-------
SRIS6 SRI, Chemical Economics Handbook, February 1986,
8-88
-------
CHAPTER 9
PHOSPHOGYPSUM
-------
9. PHOSPHOGYPSUM STACKS
9.1 Introduction and Summary
Phosphogypsum stacks are one of twelve industrial sources of radionuclide emissions for which EPA
is required to consider controls. In the case of phosphogypsum, the emission of concern is radon.
Section 9.2 profiles the phosphate fertilizer industry that generates the phosphogypsum. Section 9.3
describes the controls for radon emissions, their costs, and the reduction of emissions and of the risk
of lung cancer that they would provide. Section 9.4 considers the cost per unit of emission reduction
attributable to the different combinations of control parameters. Section 9.5 assesses the impact radon
control would have on the U.S. economy. Section 9.6 provides an analysis of the regulatory flexibility
of the controls.
The overall conclusions regarding controls on phosphogypsum stacks to reduce the risk of cancer due
to radon emissions are: 1) the controls that will reduce risk the most can be provided to the fourteen
phosphogypsum stacks for which data was available for about $251 million (discounted at 5 percent),
2) the most stringent controls would reduce risk to the 80 km populations by 3E-1, and 3) using the
most expensive version of the controls will add an average of $14 per ton to the cost of producing
phosphoric acid and reduce the export of phosphoric acid from the U.S. by approximately 11 percent
over the next thirty years.
9.2 Industry Profile
Phosphogypsum is a waste product resulting from the production of wet process phosphoric acid used
in the manufacture of fertilizer and animal feed. Phosphate- bearing ore is mined and then processed
to remove clay and other impurities. The purified ore is called phosphate rock. The phosphate rock
is then reacted with sulfuric acid, producing phosphoric acid and the waste product phosphogypsum
(calcium sulfate). Of all the marketable phosphate rock mined in the United States annually, about
90 percent is used in the production of wet-process phosphoric acid (WPPA). Thermal phosphoric
acid is produced with the remaining 10 percent.
Phosphorus, along with potassium and nitrogen, is one of the primary nutrients which plants require.
All living things contain phosphorus, a basic element essential to life. It ensures the transfer and
storage of energy and plays a role in the metabolic process. Phosphorus is not naturally very
abundant in soils, as it is constantly removed by crops and natural losses. Phosphate applications help
produce high crop yields and improve the biological quality of the crop. The phosphate mineral itself
is very insoluble and is therefore a poor source of phosphorus for plants. Thus, the phosphate rock
9-1
-------
is treated with excess sulfuric acid to produce merchant-grade WPPA, containing 52 to 54 percent
P2O5 (phosphorus pentoxide, the unit commonly used to express phosphorus content) [St8S].
The U.S. phosphate industry was the world leader in downstream* fertilizer products after initiating
major expansions in the 1970s. However, in the 80s many foreign rock producers have been investing
in their own downstream product facilities with the result that in the near future all major rock
exporters and producers will have their own phosphoric acid and fertilizer production capability.
The 1980s have been a difficult period for the U.S. phosphate industry. Besides the rapid growth
of foreign production capacity, the domestic industry has suffered from rapid changes in demand for
phosphate fertilizer. As a result, sales of phosphate products have declined, losses have been incurred
throughout the industry and several companies have filed for bankruptcy, closed their phosphate
operations, or sold their phosphate operations. Nevertheless, the U.S. industry continues to dominate
the domestic market and total production and exports have shown promise of improving, though the
value of sales has not improved. Phosphate fertilizer sales were $3.9 billion in 1987, down from $4.5
billion in 1984. Sales in the second quarter of 1988, however, increased 12 percent from levels in
1987 [DOC88a, TFI88b].
However, the outlook for the domestic phosphate industry is complicated by the depletion of major
phosphate rock deposits in central Florida. The Bone Valley of Florida, which contains many of the
lowest cost deposits in the world, is being rapidly depleted. Many nearby deposits are available or
could be developed, but at a higher cost and lower grade. Over the next 20 years, there will be a
high level of mine replacement. Average production costs in Florida will be rising faster than those
in much of the rest of the world, where current mines can continue production for many years
[BSC85a].
Morocco and Florida represent the two sides of the phosphate industry. The Moroccan state-owned
company has aggressively expanded phosphate rock, acid and fertilizer capacity even when the
international market had excess capacity. And while Florida production costs are now the lowest,
Morocco has a variety of cost advantages, including closer proximity to key export markets [BSC85a].
The future of the U.S. phosphate industry depends on its ability to remain competitive against
countries like Morocco,
^Downstream fertilizer products include: diammonium phosphate, and triple super phosphate, as
well as some items manufactured in smaller quantities.
9-2
-------
9.2.1 Characteristics of Phosphoric Acid Production
9-2.1.1 Determinants of Phosphoric Acid Supply
Nearly 9.5 million metric tons of phosphoric acid were produced in the U.S. in 1987. Total U.S.
phosphoric acid production grew steadily during the late 1960s and the 1970s and reached a peak of
nearly 10.3 million tons in 1980 [DOCSI].2 During the 1970s, significant new production capacity
was added in response to sharply higher prices for phosphate fertilizer products. In the early 1980s,
when this capacity became available, however, demand for phosphoric acid declined. As shown in
Table 9-1, production levels declined to 7.5 million tons in 1982, a drop of 25 percent from 1980.
In recent years, production levels have improved but have remained erratic, reaching a new high of
10.3 million tons in 1984. Production of phosphoric acid in the first half of 1988 is 13 percent above
the levels in the first half of 1987,
Also evident in Table 9 -1 is the close link between the production levels of phosphoric acid, WPP A
and phosphate fertilizer. The second column of Table 9-1 shows production levels of wet process
phosphoric acid (WPPA). Almost all phosphoric acid is produced as WPPA and the production levels
of WPAA parallel the levels of total phosphoric acid. Similarly, most WPPA is used in the production
of phosphate fertilizer, shown in the third column of Table 9-1. Production levels for phosphate
fertilizers for the first half of 1988 are 6 percent above the levels in the first half of 1987 and
producer's stocks of phosphate fertilizers have remained essentially unchanged between these periods
[DOC88b],
In addition to changes in total production levels for phosphate products, there have been trends in
the types of phosphate fertilizers that are produced. As shown in Part 2 of Table 9-1, diammonium
phosphate (DAP) has come to dominate the phosphate fertilizer market. DAP's share of total
production has grown from 39 percent in 1974 to 69 percent in 1986. The production levels of
concentrated superphosphates have dropped from 24 percent of total production in 1974 to 16 percent
in 1986. Production levels of normal and enriched superphosphates and monoammonium phosphates
have also declined [DOC80].
1 short ton = 2,000 pounds
1 metric ton = 1,000 kilograms = 2,205 pounds
"Tons" in this document refers to metric tons unless otherwise specified.
9-3
-------
Table 9-1; Production of Phosphoric Acid, Wet Process Phosphoric Acid and Phosphate Fertilizer,
(Part 1 of 2)
Metric Tons
YEAR TOTAL WET PROCESS TOTAL
PHOSPHORIC ACID PHOSPHORIC ACID PHOSPHATE FERTILIZER
PRODUCTION
PERCENT OF
PRODUCTION
PRODUCTION
PERCENT OF
1970 BASE
1970 BASE
1987
9,691,381
184
9,134,164
6,444,234
161
1986
8,686,919
168
8,146,432
5,540,068
133
1985
9,620,478
187
9,076,701
6,941,434
167
1984
10,334,304
200
9,718,541
7,284,941
175
1983
8,858,334
172
8,261,672
6,400,026
154
1982
7,485,244
145
6,933,111
5,084,640
122
1981
9,031,701
175
8,417,517
6,266,839
150
1980
9,921,673
192
H/A
7,563,636
181
1979
9,357,519
181
N/A
6,949,424
167
1978
8,675,364
168
N/A
6,508,518
156
1977
8,124,453
158
H/A
6,075,729
146
1976
6,845,673
133
H/A
5,282,334
127
1975
6,957,597
135
H/A
5,054,855
121
1974
6,465,096
125
H/A
4,867,854
117
1973
6,211,045
120
N/A
5,059,401
121
1972
5,923,345
115
N/A
4,972,537
119
1971
5,414,790
105
N/A
4,527,291
109
1970
5,157,202
100
N/A
4,168,663
100
1969
4,928,638
96
N/A
3,893,207
93
1968
4,779,890
93
N/A
3,763,506
90
1967
4,598,490
89
N/A
4,258,365
102
1966
4,167,665
81
N/A
4,035,878
97
Source: Bureau of the Census, Current industrial Reports
Summary reports for 1987, 1986, 1985, January 1982, 1980, 1979, 1978, 1976, 1974, 1973.
9-4
-------
Table 9-1; Production of Phosphoric Acid, Met Process Phosphoric Acid and Phosphate Fertilizer.
{Part 2 of 2)
Metric Tons
BREAKDOWN
Of TOTAl PHOSPHATE
FERTILIZER PRODCUT ION
YEAR
NORMAL & ENRICHED
CONCENTRATED
DIAMMONIUM
OTHER PHOSPHATE
SUPERPHOSPHATES
SUPERPHOSPHATES
PHOSPHATE
FERTILIZERS
196?
58,088
867,101
4,550,845
968,200
1986
59,129
881,512
3,829,047
770,380
1985
91,441
1,079,364
4,843,020
927,610
1984
115,023
1,019,321
5,264,103
886,494
1983
110,776
1,129,675
4,337,248
822,327
1982
125,746
966,163
3,338,334
654,398
1981
215,369
1,352,681
3,696,905
1,001,885
1980
412,986
1,535,601
4,509,868
1,105,181
1979
320,012
1,670,263
3,861,275
1,097,874
1978
264,057
1,650,616
3,569,683
1,024,163
1977
308,360
1,624,232
3,133,542
1,009,595
1976
346,981
1,446,577
2,608,263
880,514
1975
439,040
1,521,848
2,407,662
686,305
1974
632,790
1,559,068
1,904,436
771,560
1973
561,873
1,535,258
314,526
1972
613,858
1,504,441
517,171
1971
567,782
1,371,838
415,225
1970
607,690
1,336,737
327,246
1969
731,677
1,228,169
260,944
1968
828,635
1,259,642
194,461
1967
1,073,707
1,343,086
257,225
1966
1,031,985
1,538,726
216,682
Source:
Bureau of the Census, Current
Industrial Reports
Summary reports for 1987, 1986, 1985,
January 1982, 1980
, 1979, 1978, 1976,
1974, 1973.
9-5
-------
Price Trends
Spot prices of WPPA have varied considerably in the 1970s and 1980s. These changes have an
enormous influence on the cost of phosphate fertilizers. WPPA represents 70 percent of the
production costs of diammonium phosphate and 69 percent of the cost of granular triple super
phosphate (TSP) [TFI87c], TSP also requires some phosphate rock in its production, contributing
another 9 percent of its production cost. Table 9-2 shows the prices for phosphoric acid and
fertilizer in absolute and constant dollars. Table 9-2 also gives prices for sulfur and phosphate rock,
the two most important inputs to WPPA. These inputs will be discussed in detail later in this chapter.
Figure 9-1 graphs the changes in prices of the commodities listed in Table 9-2. The prices con-
sidered in these exhibits are for the export market for product loaded and leaving from terminals
in the Gulf of Mexico. Prices in this market are more volatile than prices determined by long term
contracts. The price for WPPA shipped under long-term contracts, however, are not often published.
In the early 1970s, fertilizer prices were restrained in the U.S. by the national wage and price
controls. After wage and price controls ended, prices increased rapidly, reaching a high in the
middle of 1974. The price for phosphoric acid in 1974 was $712 per ton (1982 dollars). It dropped
by 62 percent to $271 {1982 dollars) by 1977 and rebounded to $439 (1982 dollars) per ton in 1980.
Prices have declined since 1980, to $257 per ton (1982 dollars) in the spot market in April 1988.
The April 1988 price, in current dollars, was $307.50 [BSC88b|.
Plants and Operating Capacity
There are 20 operating WPPA plants in the U.S. [TVA88]. According to the Tennessee Valley
Authority, six of their plants were indefinitely closed in the mid-1980s. Two other plants, owned
by the bankrupt Beker Industries Company, are closed and for sale. The eight plant shutdowns have
resulted in a U.S. WPPA capacity reduction of 1.4 million tons per year. The 20 plants in operation
give the U.S. a capacity of 11.5 million tons of WPPA. Since 1984, the 20 operating plants have
increased overall capacity by 735,000 tons, although one of these plants reduced capacity by 100,000
tons [TVA88], There are 11 WPPA plants operating in Florida, comprising 67 percent of the capacity
of U.S. plants still in operation. Louisiana has 4 operating WPPA plants and the remainder are
distributed among North Carolina, Mississippi, Texas, Idaho and Wyoming.
9-6
-------
Figure 9-1: Price of P205 and Related Products
m -f
fx
¦ +
¦ k-
\
% -n
J-
t.
^ / Wi, ^
n /
¥ f I
Win -HI
%
jr
-------
table 9*2: Pries of Phosphoric Acid, Sulfur
Phosphate Rock and Dtawmoniu»
Phosphate.
{Average of Honthly Prices)
PHOSPHORIC PHOSPHATE DIAHMOtliW
ACID
SULFUR
ROCK
PHOSPHATE
1972
$111.46
$15.69
$7.77
$89.96
1973
$155.42
$17.97
$13.55
$120.33
1974
$384.38
$37.64
$35.43
$332.29
1975
$359.38
$54.57
$48.00
$247.29
1976
$196.59
$40.18
$37.00
$119.36
1977
$182.29
$37.30
$28.04
$133.25
1978
$202.29
$40.45
$31.04
$139.29
1979
$292.33
$83.36
$34.42
$197.04
1980
$376.46
$122.77
$44.50
$223.25
1981
$341.88
$111.25
$45.17
$193.29
1982
$310.54
$110.31
$39,17
$180.67
1983
$268.46
$90.33
$31.96
$182.13
1984
$299.42
$98.63
$33.17
$189.08
1985
$274.25
$133.75
$32.92
$168.96
1986
$279.38
$133.63
$32.00
$154.21
1987
$250.46
$101.75
$27.25
$173.46
1988
$306.50
$94.00
$32.54
$188.60
CONSTANT DOLLARS
1982 DOLLARS
PHOSPHORIC PHOSPHATE DIAKKONIUM
ACID
SULFUR
ROCK
PHOSPHATE
1972
$239.70
$33.73
$16.72
$193.46
1973
$313.97
$36.31
$27.38
$243.10
1974
$711.81
$69.70
$65.61
$615.35
1975
$606.03
$92.02
$80.94
$417.02
1976
$320.59
$64.14
$59.17
$189.91
19 77
$270.86
$55.42
$41.67
$197.99
1978
$280.18
$56.03
$42.99
$192.92
1979
$371.93
$106.05
$43.79
$250.69
1980
$439.27
$143.26
$51.93
$260.50
1981
$363.70
$118.35
$48.05
$205.63
1982
$310.54
$110.31
$39.17
$180.67
1983
$258.38
$86.94
$30.76
$175.29
1984
$277.49
$91.40
$30.74
$175.24
1985
$245.96
$119.96
$29.52
$151.53
1986
$244.85
$117.11
$28.05
$135.15
1987
$213.16
$86.60
$23.19
$147.62
1988
$251.23
$77.05
$26.67
$154.59
Ati data are in dollars per metric ton.
Phosphoric acid and diammonium phosphate
prices are FOB US Gulf; phosphate rock is
FOB Florida, and sulfur is FOB Vancouver.
BMP Deflator used to compute constant-dollar
series.
Source: Data purchased from British Sulphur
Corp., June 5, 1983.
9-8
-------
Production Costs
Estimates of the production costs of WPPA are available from a variety of sources. Table 9-3 shows
estimates from The Fertilizer Institute (TFI). The data are from an industry survey of U.S. producers
of 1986 costs. According to the TFI estimates, sulfuric acid represents 49 percent of the cost of
producing phosphoric acid. Over 96 percent of the cost of sulfuric acid is accounted for in
purchasing the sulfur itself. Phosphate rock represents another 31 percent of the production cost of
phosphoric acid. Energy costs represent 6 percent of production costs. Per ton of phosphoric acid
requires 2.74 tons of sulfuric acid and 3.55 tons of phosphate rock. Plants with an annual capacity
over 400,000 tons enjoy a considerable cost advantage over smaller plants. According to the TFI
survey, large plants had an average production rate of $229 per ton, compared to $289 for plants
with a capacity under 400,000 tons. The average cost in 1986 was $239.35 per ton [TFI87dj.
Traditionally, phosphoric acid production occurred almost entirely in tandem with fertilizer
production. However, improved transportation options and heightened international competition has
created a distinct market for the production and sale of phosphoric acid.
Transportation Costs
The markets a nation's phosphate industry serves depend in large measure on transportation costs.
In March 1988, the cost to ship a ton of phosphoric acid from the Gulf of Mexico to India averaged
$48, a little over 15 percent of the current U.S. price [BSC88a], North African producers have a
transportation advantage over U.S. producers for many markets. According to estimates by Zellars-
Williams for the cost of shipping one type of phosphate, DAP fertilizer, Morocco and Tunisia have
a $5 per ton advantage shipping to northern Europe and India. Freight costs to China are essentially
the same for both regions [Ze86].
Few U.S. phosphoric acid producers have their own shipping fleets. The notable exception is
Occidental Petroleum Co., which has a dedicated fleet of three vessels supplying contract deliveries
of phosphoric acid to the Soviet Union. Office Cherifien Des Phosphates (OCP) of Morocco and ICM
of Tunisia both ship phosphoric acid, using captive tonnage. Brazil and India, important phosphoric
acid consumers, have both invested in dedicated fleets of phosphoric acid tankers, but the bulk of
their import requirement continues to be met by outside carriers.
With the exception of phosphoric acid, phosphate products do not require specialized handling
facilities and these products can be readily shipped in conventional bulk carriers. The market for
9-9
-------
Table 9-3: Phosphate Fertilizer Production Casts
Total
Diaaaoniua Phosphate
Phosphoric Acid
Anhydrous Aaaonia
Electricity
Stean
Operating Labor
Other
Total
Granular Triple Super
Phosphoric Acid
Phosphate Rock
Electricity
Natural &>s
Operating Labor
Other
Total
Cost per Percent of
¦etri c ton total cost
Wet Process Phosphoric Acid
Sulfuric Acid 130.07 49.3%
Phosphate Rock 81.24 30.8%
Electricity 6.44 2.4%
Stesa 10.22 3.9%
Operating Labor 4.70 1.8%
Other 31.21 11.8%
263.88 100%
126.90
70.5%
30.02
16.7%
1.68
0.90%
3.53
2.0%
1,91
1.1%
16.42
8.8%
180.45 100%
Phosphate
88.71
69.5%
10.98
8.6%
2.95
2.3%
2.27
1.8%
2.58
2.0%
20.19
15.8%
127.68 100%
Source: Phosphate Fertilizer Production Cost
Survey, Year Ended December 31,1986. Compiled
by National Fertilizer Development Center for
The Fertilizer Institute, Hay 1,1987. pp.2-5.
§-10
-------
such vessels has been characterized by chronic oversupply throughout the 1980s, and freight rates
have steadily declined. It is not clear how freight rates will vary over the next several decades.
British Sulphur Corp. has only made forecasts for the short term and Zellars-Williams's forecasts
assume rates will remain essentially the same between 1985 and 2005.
Fertilizer producers historically have located phosphoric acid production near either phosphate rock
or sulfur supplies. Economical domestic supplies of phosphate rock and sulfur have been an essential
factor in allowing the U.S. to obtain its dominant position in the international market. Thus, the
outlook for the domestic phosphoric acid industry depends in large measure on the availability of
economical supplies of phosphate rock and sulfur.
Phosphate Rock
The production of WPPA requires a phosphate rock product whose specifications are most easily
achieved from deposits in the Bone Valley Formation of Central Florida. Most North Carolina
phosphate rock deposits are of a lower grade primarily because of a high level of organic matter.
Western rock is of even tower grade [St86a]. Thus, most of the rock acid used to produce WPPA
comes from Florida. In 1986, Florida produced about 80 percent of the phosphate rock in the United
States and over 95 percent of that went for the production of WPPA [DOC87].
In 1986, U.S. mines produced 38.7 million tons of phosphate rock, down from levels in 1984 and 1985
that were around 50 million tons. Each year approximately 20 percent of U.S. phosphate rock
production is exported. A small amount of rock is imported, often to obtain high-grade rock for
making especially pure phosphoric acid. Trends in world production levels of phosphate rock have
paralleled trends in U.S. production levels.
Most phosphoric acid plants operating in the United States enjoy a significant competitive advantage
over potential new firms because their parent companies own rock reserves, which are mined
relatively cheaply. Plants that do not have a rock mine on site are usually supplied by a mine that
can be linked by barge. U.S. mines had average production costs of $15.60 per ton in 1986, according
to TFI [TFI87d]. In contrast, the export price in 1986 from Florida for equivalent rock was $25.02
per ton [St86a], Because 3,6 tons of rock are used in making one ton of P2Os, this difference in cost
translates into approximately a $33 per ton cost difference for domestic phosphoric acid production
compared to the cost of purchasing rock for export sale, 25 percent of total average production costs.
The continued availability of low cost phosphate rock is a central factor in the future of the
phosphate industry.
9-1 i
-------
The U.S. rock mining capacity far exceeds that of any other nation. According to the Bureau of
Mines, the U.S. capacity of nearly 62 million tons is twice as large as the next country, the U.S.S.R.,
which has 31 million tons capacity. Africa has a 48 million ton capacity, with over half of that in
Morocco. Table 9-4 lists rock capacity by each major country, according to both the Bureau of
Mines and Zeilars-Williams.
Phosphate Rock Reserves -- Estimating the size of phosphate reserves requires many assumptions.
Estimates by the U.S. Bureau of Mines and the U.S. Geological Survey classify reserves according
to the extent to which assumptions needed to be made. The reserve estimates are ranked according
to the level of confidence: demonstrated, inferred, hypothetical, and speculative levels.
Demonstrated reserves are those that can be profitably extracted using current technology. The level
of demonstrated reserves changes with new technological development and significant changes in
market conditions. At the demonstrated resource level, there are approximately 35 billion tons of
recoverable rock worldwide in 28 market economies, located in approximately 200 deposits. Fifty-
six percent of this is in Morocco and 19 percent is in the United States. There is a further 1.5 billion
tons of recoverable rock located in the U.S.S.R. and China. An estimated 95 billion tons of
recoverable phosphate rock exists at the demonstrated, inferred, hypothetical, and speculative levels
[BOM84],
Worldwide availability of demonstrated recoverable rock reserves is shown in Table 9-5. Within the
United States as of 1983, 5.4 billion tons of phosphate rock were potentially recoverable at the
demonstrated reserve level as defined above. Approximately 3.7 billion tons of this was located in
Florida and North Carolina. As of 1983, 1.4 billion tons were available at costs ranging up to $30
per ton. Three-fourths of the demonstrated reserves in Florida and North Carolina is available at
a cost of less than $45 per ton [St85].
Inferred deposits are estimates that assume a continuity from indicated resources which are based on
geological evidence. Hypothetical resources are another step away from direct geological evidence
than are inferred resources. Hypothetical reserves "may be reasonably expected to exist ... under
analogous geologic conditions [BOMbJ," At the inferred level, 7 billion tons of rock are available in
the U.S., 80 percent of which is in the Southeast. Twenty-four billion tons are available at the
hypothetical level, with 60 percent in the Southeast. A further 2 billion tons have been identified,
but are high in magnesium content so are not currently profitable to process. New discoveries are
likely, particularly offshore along the eastern seaboard, and new technologies could easily increase
the amount of profitably-recoverable phosphate rock [BQMb].
9-12
-------
Tsblt 9-4: Phosphate fteek Statistics on World Supply
Sock Birring Capacity.
(MILLION TONS PER YEAR, DRY BASIS)
location WORLD PHOSPHATE ROCK CAPACITY,USBK \1 2*llars-Ui Lliaas Sock Production Forecasts
1985
1990
1995
2000
1985
1990
1995
2000
2005
NORTH AMERICA
61.7
67.1
62.2
45.9
48.1
58.0
58.6
56.2
52.3
United States
61. 7
67.1
62.2
45.9
CENTRAL AMERICA
1.0
2.5
2.5
3.5
0.6
1.8
2.3
2.3
2.3
Mexico
1.0
2.5
2.5
3.5
SOUTH AMERICA
4.5
7.0
9.0
10.0
3.8
5.0
5.0
5.0
5.0
BraziI
4.5
7.0
8.0
8.0
Peru
-
-
1.0
2.0
WESTERN EUROPE
0.5
0.6
0.6
1.1
0.8
0.8
0.8
0.8
0.8
Finland
0.5
0.5
0.5
1.0
Turkey
-
0.1
0.1
0.1
EASTERN EUROPE
31.0
36.0
45.0
50.0
31.0
35.1
38.9
42.6
45.1
USSR
31.0
36.0
45.0
50,0
AFRICA
48.1
57.1
62.1
68.1
Algeria
2.2
2.2
2.2
2.2
Egypt
1.Z
1.2
1.2
1.2
Morocco
28.0
35.0
38,0
44.0
21.3
28.4
34.0
44.0
54.0
Senegal
Z.O
2.0
2.0
2.0
1.9
1.9
1.9
1.9
1.9
South Africa, Rep. of
4.7
4.7
5.7
5.7
3.0
3.4
1.4
3.4
3.4
Togo
3,0
3.0
3.0
3.0
2.5
2.5
2.5
2.5
2.5
Tunisia
7.0
9.0
10.0
10.0
4.6
7.2
10.2
11.0
13.4
ASIA
27.1
36.6
49.1
60.6
China
13.0
20.0
30.0
40.0
17.0
17.8
21.0
24.0
2S.0
Israel
3.5
5.0
6.5
6,5
3.0
3.5
3.5
3.5
3.5
Iraq
1.7
1.7
1.7
1.7
Jordan
6.5
7.5
8.5
10.0
5.0
6.0
10.0
12.0
12,0
Syria
2.4
2.4
2,4
2.4
OCEANIA
Australia
1.0
1.0
1.0
1.0
Christaas Island \3
1.8
1.8
3.0
3.0
Nauru
2.0
2.0
2.0
-
UORLD TOTAL \A
290.9
351.5
404.8
436.5
142.6
171.4
192,1
209.2
221.2
\1 Source: V.F. Stowasser, Phosphate Rock: World Resources,
Supply and Oeaand, 1986
Figures for all years are U.S. Bureau of Nines estimates based on the size of the reserve base. Unfavorable
econoaics «ay alter the forecasted rock capacities in future years.
\2 Source; Phosphate Rock 1985/86, by Zellars-Willisas. Blanks aean data is not available. This data are not
directly coaparable to the Stowaaaar aatfaata. The stawaaaar astiaat* of capacity 1*» aaeh year does not
taply that the capacity will be uaarf fully. Zellar»-lMU1aa's product ion forecast *ay at lav far mm tmuaad
capacity, aapacially fn tMS. Wa»ar Unlets, a aaaparlaan mf the data reveals different outlook*.
\3 Christ™* bland eloeed at the end of 1*7.
\4 Cannot accurately coapare world totals between the two aoureae as both do not contain all the saae data.
9-13
-------
Table 9-5; Phosphate Rock Statistics to World Supply Benorertrnitetl lock Reserves.
LOCATION
NUMBER
OF
DEPOSITS
RESERVES
(Million
Metpie Ton*VI)
RESERVE BASE
(Million*
Metric Ton*V2)
United States
Florida
North Carolina
Idaho
Utah
Uyoaing
Other
Canada
Mexico
108
1,400
520
400
50
220
210
5 ,,400
2,400
1,300
220
730
690
60
<0
120
Brazi I
ColuMbia
Peru
9
1
1
40
350
100
140
Finland
Turkey-
USSR
2
1
11
1,300
110
30
1,300
Algeria
Egypt
Morocco £ Western Sahara
Morocco
Western Sahara
Senegal
South Africa, Republic of
Togo
Tunisia
1
5
12
11
1
2
1
1
?
7,750
6,900
850
130
2,600
50
60
2S0
790
20,850
20,000
850
130
2,600
50
120
China
Israel
Jordan
Syria
6
3
3
2
210
20
120
210
90
510
180
Australia
Other
320
500
130
UORLD TOTAL
192
14,000
34,000
\1 Cost less than $35 per Metric ton. Cost includes capital, operating expenses, taxes,
royalties, Miscellaneous costs, and a 15X rate of return on investment. Costs and resources
as of January 1983, F.O.B, Nine.
\2 Cost less than $100 per Metric ton; costs as defined in footnote 1.
SOURCE: W.F. Stowasser, US8H Mineral Facts and Problems 19®
9-14
-------
There are many unknowns in estimating resource reserves. For example, there is speculation about
a new deposit in North Carolina. Details have not been finalized and tests will take two years to
complete after they have begun. Should this deposit be realized, an estimated 70 to 90 million metric
tons of new phosphate rock reserves could be added to North Carolina reserves and the costs could
be as low as $7 to $10 per ton [BSC87b].Prices — The price of phosphate rock has followed a similar
set of swings as has the price of WPPA. Table 9-2 lists phosphate rock export prices between 1972
and 1988. Prices have fallen from around $45 per ton in 1980 and 1981 to between $27 and $31 per
ton in 1987 and 1988 [BSC88b].
Production Forecasts — Rock production forecasts require a number of assumptions concerning the
price and demand for phosphate rock, as well as operating costs in future years for known but
undeveloped deposits. William Stowasser at the U.S. Bureau of Mines and Zellars-Williams have
made the most careful production forecasts. While both sources anticipate similar trends, Stowasser
is considerably more pessimistic concerning the prospects for U.S. rock production after the year
2000.
Stowasser forecasts that U.S. production of phosphate rock will be 46.4 million tons per year by the
year 2000 [St85j and will decline significantly after that to about 28 million metric tons in 2010
[BOM88d], Stowasser reexamined this forecast in June of 1988 after a survey of company's
production plans and did not significantly modify his forecast [BOM88c], The production level in
the year 2000 is within the range of production achieved in the mid-1980s. Rock production from
Florida is expected to decline at a rapid rate after 2010 as reserves in currently operating mines in
the Bone Valley are exhausted. Production from North Carolina will increase through 2000 and be
about 10 million tons in 2010. Other U.S. production will remain about the same. These forecasts
assume an economically competitive technology will not be developed that would permit utilizing
undeveloped central Florida phosphate resources [BOM88c], Thus, in Stowasser's forecast, sufficient
domestic supply will not be available after the year 2000 to satisfy demand at production levels being
met in the 1980s. Such a scenario would force major increases in the price of phosphate rock.
The Zellars-Williams supply estimate is more optimistic and forecasts 56.2 million tons per year in
the year 2000 and 52.3 in 2005. The accuracy of both of these forecasts depends on trends in the
phosphate markets, such as the demand and price of phosphate rock. For example, the current
oversupply situation in the world could cause the decline to occur several years later as rock sales
may be below production capacity. However, each forecast expects that there will be a decline in
rock capacity in the U.S. in the next 20 to 25 years.
9-15
-------
The forecasts of production described above do not indicate the future price of phosphate rock.
Industry experts have consistently avoided forecasting price levels. However, some indication of
future prices for phosphate rock can be found from examining forecasts of the cost of producing
phosphate rock. A study by Fantel, Stowasser and others at the Bureau of Mines examined 201
mines. Fantel, et. al., made separate estimates for mines operating in 1981 and for undeveloped
mines. The study estimated that mines operating in 1981 could produce, in 1995, 10.8 million tons
a year of rock for between $18 and $30 and another 1.4 million tons for between $30 and $40. This
estimate assumed the mines operated at full capacity since 1981. The study also forecasted that
undeveloped mines could produce 10.3 million tons for between $2? and $35, another 21.8 million
tons for between $35 and $45 per ton [Fa83]. The estimate for undeveloped reserves is based on
production levels that would be attained 10 years after development is initiated.
To estimate production costs in the year 2000, it is necessary to make several assumptions. The study
described above noted that the forecast for currently operating mines should be revised in the future
if the mines do not operate at full capacity. Because they have frequently operated below capacity,
it is reasonable to assume that the developed reserves continue at 1981 production levels until the year
2000. It is necessary to assume that the new reserves begin, on average, to be developed in 1990 and
that the cost of production estimates in this study are spread evenly over the cost range given. With
these assumptions, it is apparent that the marginal cost of production at 1980 production levels, such
as 40 million tons, would be $43 per ton in 1981 dollars. The average cost of production would be
S33 per ton. Assuming that the price of phosphate rock equals the marginal cost of production and
adjusting for inflation, this forecast suggests that the U.S. open market price of phosphate rock will
almost double from current prices by the year 2000.
Not all domestic phosphoric acid producers will be forced to pay more for phosphate rock. This is
because many phosphoric acid producers have captive rock mining capacity and the average cost of
production is approximately ten dollars below the marginal cost. Consequently, the production costs
for all phosphoric acid producers will not increase to the full extent of the potential price increase.
However, if production cost is measured using the opportunity cost to the producer, the production
cost for all producers would increase.
Maintaining current rock production will require major capital investment by the phosphate industry
during the next several decades. Fantel, et. al, at the Bureau of Mines, estimate that the initial capital
cost to develop new potential surface phosphate mines is between $75.20 and $88.40 per ton. They
project that U.S. mining capacity will decline by 39 million tons between 1981 and 1995, assuming
the plants operate at full capacity. Since many plants have been operating below market capacity,
9-16
-------
it is reasonable to extend the operating levels to the year 2000, Replacing this capacity will require
industry investment of between $2,9 and $3.4 billion before the year 2000 [Fa85J. However, the
higher costs of production diminish the incentives for this level of investment.
Though phosphate rock mining capacity in the U.S. is expected to decline, both Zellars-Williams and
the Bureau of Mines expect rock mining capacity to grow rapidly throughout the rest of the world.
The Bureau of Mines projects that Morocco will increase its capacity to 44 million tons per year by
the year 2000 and that the People's Republic of China will increase its capacity from 13 to 40 million
tons per year. Many other countries will also expand so that world capacity will grow from 291
million tons in 1985 to 436 million tons in the year 2000 [St86b], Country by country projections by
both the Bureau of Mines and Zellars-Williams are contained in Table 9-4.
Sulfur
Approximately 60 percent of sulfur used in the U.S. is consumed in the production of phosphoric
acid [Mo85], Sulfur is produced in the U.S. either as a by-product from the processing of other
materials (known as "recovered sulfur") or from mining. Most U.S. sulfur is recovered at natural gas
wells, during the refining of petroleum and during the processing of some minerals, such as copper.
Sulfur is also mined at a small number of sites. In the case of recovered sulfur, the supply is
insensitive to the price and demand for sulfur so long as its price is low enough that it does not
dominate the decision to produce natural gas or petroleum. The supply of recovered sulfur is
extremely sensitive to changes in the use of natural gas and petroleum products. The burden for
adjusting to shifts in demand rests on sulfur mines.
Most sulfur is used in production processes, such as making phosphoric acid, after being converted
into sulfuric acid. According to a survey sponsored by The Fertilizer Institute, the cost of obtaining
sulfur represents 96 percent of the cost of producing sulfuric acid. Each ton of sulfur can produce
3 tons of sulfuric acid [TFI87cJ. Because of this increase in weight and volume, sulfur is usually
transported to the plant where it will be used and then converted into sulfuric acid. However, a
number of processes described in the following text produce sulfuric acid instead of elemental sulfur.
In addition, some sulfuric acid users are too small to engage in converting sulfur into sulfuric acid,
and, consequently, purchase acid directly.
Sulfur resources are abundant throughout the world. Billions of tons of sulfur could be recovered
from coal and oil shale but cost-competitive processes are not available. However, some sulfur is
9-17
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now extracted as a by product from these sources in order to meet environmental standards.
Following is a review of the current sources of sulfur and forecasts of future supply of sulfur.
Current Production Recovered Sulfur — Recovered sulfur supplied 52 percent of U.S. sulfur
production in 1986. Recovered sulfur provides a similar proportion, 55 percent, of world
production. The sulfur is recovered where petroleum is processed and where sour natural gas is
taken from the ground. "Sweet" and "sour" refer to oil and gas sources with relatively small and large
quantities of sulfur, respectively. Texas, Mississippi and Louisiana produced 47 percent of U.S.
recovered sulfur in 1986 [Mo85], The quantity of sulfur in oil and gas varies greatly.
In recent years, there has been a trend towards the production of a higher proportion of sour energy
sources. This trend reflects the depletion of easier-to-refine sweet oil and gas. Sour natural gas is
poisonous and highly corrosive and, consequently, more expensive to refine.
In the international market, Canada is the dominant exporter. Canada has been producing recovered
sulfur for decades. Not until the mid-1960s, with the growth of the phosphate fertilizer industry,
was there an important international market for sulfur. Canada, consequently, has had substantia!
inventories. Canada had an inventory of 20.4 million tons in 1979, which had shrunk to 6.7 million
tons by 1987. Canada produced 5.9 million tons in 1987 [Ph88]. Production in the U.S. and U.S.S.R.
exceeds Canadian production but in both countries the sulfur is largely used domestically.
Current Production of Mined Sulfur -- Two technologies are most important in the mining of sulfur:
Frasch mining and pyrite mining. The Frasch technology extracts the sulfur by pumping large
quantities of superheated water into underground deposits. The melted sulfur settles at the bottom
of the well and is pumped out. While Frasch is the only technology used in the U.S., several other
extraction methods are used elsewhere. There are four domestic sulfur mining producers, with four
sulfur plants operating in 1986 in Texas and Louisiana and several plants idle. Three of the four
producers, Freeport Minerals Co., Farmland Industries and Texasgulf Chemicals Co. are phosphoric
acid producers. The fourth producer, Penzoil Sulfur Co., does not produce phosphoric acid.
Farmland Industries sulfur mines were last reported closed. Throughout the world, Frasch mining
contributes a little over 20 percent of sulfur production [Mo87],
Sulfur is mined outside the U.S. from pyrite deposits. The sulfur in these deposits is usually
recovered as sulfuric acid (HjSO^) instead of as elemental sulfur. While phosphoric acid plants use
sulfuric acid, the cheapest form to transport is elemental sulfur. Thus, while sulfur from pyrite
deposits represents 19 percent of world production, it is not an attractive supply source for U.S.
9-18
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demand. The economics of pyrile deposits are often improved by the presence of valuable minerals
within the deposit. Such minerals, including copper, lead, gold, zinc, and silver, make deposits less
rich in sulfur still profitable to exploit [Bu86],
In general, the location of sulfur production has benefitted U.S. producers of phosphoric acid in
comparison with foreign competitors. Because the U.S. is an important oil and gas producer and
consumer and because the U.S. has developed Frasch mines, domestic phosphoric acid producers have
had convenient, ample sources of sulfur supply. Many foreign phosphoric acid producers, however,
have little or no domestic sulfur production. Morocco, for example, imports most of its sulfur from
Canada. Phosphoric acid production cost estimates by Zeliars-Williams gave U.S. producers a cost
per ton for sulfuric acid approximately $5 lower than Morocco producers. This difference amounts
to a $13.70 cost advantage per ton of phosphoric acid.
Prices — Because significant inventories of sulfur existed in the late 1960s, the increased demand for
phosphoric acid and the corresponding increase in demand for sulfur did not lead to wide swings in
price of sulfur as in the price of phosphate rock and phosphoric acid. Sulfur prices increased at
almost half the rate of phosphate rock prices in the early 1970s. Nevertheless, the price increase was
substantial. Between 1972 and the middle of 1980, sulfur prices had increased from $17 to $127 per
ton, then dropped to $84 in late 1983 and stood at $94 in the spring of 1988 [BSC88b], Table 9-2
shows the sulfur export prices between 1972 and 1988.
Forecasts of Mined Sulfur Supply -- D.A. Buckingham, with the U.S. Bureau of Mines and with
assistance from Jacobs Engineering Co, (the parent company of Zeliars-Williams), estimated in 1986
the availability of mined elemental sulfur and pyrite in market economy countries through the year
2005. This study focused on 36 developed operations. Buckingham projected that 152 million tons
of elemental sulfur are available throughout the world at less than $90 per ton (January 1984 dollars)
[Bu86]. Approximately 23 percent of these developed reserves, 34.8 million tons, are in the United
States. In a 1988 article, Buckingham revised his estimate for the United States upward to 41.6
million tons at essentially the same cost, $93.50 (January 1986 dollars). Another 19.9 million tons are
available at a cost of less than $136 per ton (January 1986 dollars) [Bu88].
In 1986, U.S. Frasch mines produced slightly more than 4 million tons of sulfur [Mo87], At this rate
of production, developed reserves would be depleted in approximately fifteen years, Buckingham
projects that production from these reserves will decline steadily. Production levels will decline to
2.5 million tons in the late 1990s and will be below 500,000 tons by year 2001. These projections
9-19
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indicate that unless new mines are developed in the near future, domestic Frasch mines is the future
will supply only a small portion of U.S. sulfur demand.
In terms of world supplies of sulfur, pyrite is a more important source than elemental sulfur from
Frasch mines. Buckingham estimates that 256 million tons are available at production costs of $43
per ton or less (January 1984 dollars) [Bu86]. This cost corresponds to the 1984 market price of pyrite
concentrate. Pyrite generally sells for approximately one third the price per ton of elemental sulfur.
In addition, a portion of pyrite is available as a co-product. In these cases, the value of the other
metals found with the pyrite cover some or all of the mining costs and the pyrite could be
economically mined at a lower price level [Tu87],
The Bureau of Mines research described in the preceding paragraphs presents only a partial picture
of the availability of elemental sulfur from Frasch mines and sulfuric acid from pyrite mines.
Because of the narrow focus of the study on developed deposits, nearly 90 percent of the sulfur
resources identified by the U.S. Geological Survey were not examined [Tu87]. Insufficient data,
however, are available with which to make production cost estimates for these other reserves.
Forecasts of Recovered Sulfur Production -- Because recovered sulfur is a by-product, forecasts of
the supply of recovered sulfur are neccessarly based on forecasts of the production of petroleum,
natural gas and other products from which sulfur is recovered. Although forecasts of these products
are available, it is not clear to industry experts what ratio of sweet to sour petroleum and natural gas
wjl] be used in the U.S. or elsewhere {Mo88bJ. Consequently, authorities in the sulfur field avoid
forecasting the supply of recovered sulfur.
Only approximately 15 percent of U.S. natural gas reserves are sour, when sour is defined as gas
containing by volume 5 percent or more I-^S content. Such an estimate would represent a reserve of
108 million tons of recoverable sulfur. Crude oil processed in the U.S. has gone from 65 percent
sweet in 1964 to only 40 percent in 1980 [BSC85h]. The trend toward a higher proportion of sour
oil has continued in the 1980s. Table 9-6 shows the trend in sulfur production from petroleum and
natural gas between 1980 and 1985. For petroleum refining, the trend has been towards a steadily
higher ratio of sulfur to oil. Between 1980 and 1985 the quantity of sulfur recovered for the same
quantity of oil increased by 45 percent. In the case of natural gas, the trend has been erratic with
the ratio of sulfur to gas increasing 61 percent between 1980 and 1983 but dropping slightly in 1984
and then rising slightly in 1985 [Mo85]. The Department of Energy projects that in the year 2000,
6,679.5 million barrels of oil will be refined and 20.02 trillion cubic feet of natural gas will be in
9-20
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Table 9-6: U.S. Sulfur Recovery Trends 1980-1985
RATIO OF
SULFUR PRODUCED
PER UNIT REFINED
OIL \1
NATURAL
GAS \2
1980 1981
0,4694 0.5014
87.6 98,7
1982 1983
0.5643 0.6051
105.8 141.0
1984 1985
0.6311 0.6787
132.1 137.7
\1 Calculated by dividing recovered sulfur at petroleui refineries by crude oil
receipts at refinery. Units are thousand aetric tons of sulfur recovered
per trillion barrels of oil refined.
\2 Calculated by dividing recovered sulfur at natural gas plants by natural gas,
¦arketed product. Units are thousand metric tons of sulfur recovered
per trillion cubic feet of gas refined.
SOURCE: Statistical Abstract of the U.S., Department of Co««erce,
various years; Minerals Yearbook, Bureau of Nines, various years.
9-21
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supply [EIA88], These forecasts imply a supply of approximately 7,2 million teas of recovered
sulfur in the year 200CP, compared to 5.8 million tons in 1986,
The U.S.S.R. should become a major exporter in the near future as it completes development of the
Astrakhan natural gas development. The addition of the U.S.S.R. as a major exporter will lower
Morocco sulfur costs. In 1985, Morocco imported 65 percent of its sulfur from Canada and 19
percent from the U.S. at much higher transportation costs than it would experience with the U.S.S.R
[BSC86].
Summary — There is little risk of a shortage of sulfur in the next several decades. However, sources
of supply will change. In the past decade, the U.S. phosphate industry has had a competitive
advantage because of relatively low priced and nearby sulfur supplies. In the next several decades
this advantage will end and most U.S. phosphoric acid producers will experience relatively higher
sulfur costs. At the same time, the relative price of sulfur for Morocco and other North African
producers will decline as sulfur supplies increase in nearby regions.
9.2.1.2 Products
In 1987, the U.S. produced 9.5 million metric tons of phosphoric acid. Wet-process phosphoric acid
(WPPA) comprised 94 percent of this production. Fertilizer uses claimed 89 percent of all phosphoric
acid production and a higher proportion of WPPA production. The remaining 5 percent was used
in the production of animal feed supplement and other food additives. About 72 percent of the
WPPA used in fertilizers was used to produce mixed phosphate fertilizers; the rest went into direct
applications (fertilizer products that have primarily one plant nutrient) [DOC87], Mixed fertilizers
have two or more nutrients. Diammonium phosphate (DAP), for example, is a mixed fertilizer with
18 percent nitrogen and 46 percent phosphate [Vr86], A chart of intermediate and end products of
the WPPA industry is provided in Figure 9-2.
9.2.1.3 U.S. Phosphate Producers
The fertilizer industry is devoted to the production and marketing of three basic nutrients: nitrogen,
potassium and phosphate. The scope of the fertilizer industry includes production of ammonia,
^This estimate uses the most recent ratios of sulfur recovered to fuel refined. Since, as noted,
these ratios are increasing, this should be regarded as a conservative forecast.
9-22
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20%
(Exports |
5%
[ISO
72%
Figure 9-2: Uses for Phosphoric Acid, 1985-86
Phosphate Rock
95%
[_Fertll^erJ
Super Phosphate and
other phosphatk fertilizers
69%
12%
Dlammonium
Phosphate
Fertilizer
16%
Moooammonium
Phosphate
Fertilizer
80% j
| Domestic Use
87%
I
I Phosphoric Acid
C
13%
Other Uses
94%
6%
Wet-Process
Phosphoric Acid
Thermal
Phosphoric Acid
28%
Direct Use
D
19%
Concentrated
Super Phosphate
Fertilizer
2%
Normal and
Enriched Super
Phosphate
Fertilizer
Other Ammontur
Phosphate
Fertilizers
Source; "Inorganic Fertilizer Materials and Related Products"
Current Industrial Reports. October 1986; Jack Faucett Associates.
-------
ammonium nitrate, urea, phosphates (diammonium phosphate, triple superphosphate, and others),
nitrophosphates, mixed plant foods, superphosphates, phosphoric acid and potash.
According to the most recent Department of Commerce census, the phosphate industry had $3.6
billion in assets in phosphate fertilizer manufacturing facilities JDOC86b] and another $33 billion
in phosphate rock mines [DOC82b], Table 9-7 shows other information from the industry census.
Phosphoric acid producers are generally not single-product firms. Few companies are totally
dependent on fertilizer production; most fertilizer production is a subsidiary activity of a large,
diversified corporation.
Most of these companies are vertically integrated from phosphate rock production to fertilizer
production. The largest WPPA producers are also among the largest phosphate rock producers.
Each of the largest phosphate rock producers owns basic fertilizer production facilities either directly
or through equity interest in chemical producing companies. Some also have interests in sulfur
reserves. Table 9-8 gives a geographical breakdown of the major phosphate fertilizer producers and
their capacities to mine phosphate rock and produce phosphoric acid and several phosphate fertilizers.
In many cases the production facilities are linked in a single plant. Where it is clear that mines and
plants are closely linked, Table 9-8 lists the facilities together. This information is summarized in
Table 9-9.
In 1984, 22 U.S. companies accounted for 33 percent of world phosphate rock production; 12
companies in Florida and one in North Carolina produced 87 percent of the U.S. total [Ga85], Most
of the fertilizer production plants in Florida are located in Polk and Hillsborough counties in Central
Florida.
Most chemical fertilizer producers have been operating below capacity since the early 1980s, at 79
percent capacity for WPPA on average. The lowest rates occurred in 1982, when the industry
averaged 63 percent of capacity [TFI86B], This information is summarized in Table 9-10.
The Fertilizer Institute sponsors periodic surveys of member companies to collect general financial
information for the integrated fertilizer manufacturing industry. TFI survey results show that the
return on total assets was less than one percent, either positive or negative in 1982, 1983, and 1985.
In 1984 and 1986, the return on total assets was a positive 5 percent and a negative 5 percent,
respectively [TFI87b], These low rates of return have been blamed on poor demand for fertilizer and
on excess capacity.
9-24
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Table 9-7: Financial Condition of Phosphate Industry
PHOSPHATE PHOSPHATE
FERTILIZER MINING
MANUFACTURING
{1985 dollars} (1982 dollars)
(thousands)
CAPITAL ASSETS AND EXPENDITURES
ASSETS
NEW CAPITAL EXPENDITURES
DEPRECIATION
3/639,000 \a 3,301,700 \b
171,TOO Va 223,000 \b
244,600 \a 144,500 \b
RETIREMENTS AND USED ASSETS \e 180,100 \a 17,500 \b
OPERATING EXPENDITURES
a) 1985 Annual Survey of Manufacturers, Expenditures for Plant
and Equipment, Table 2, page.4-30.
b) 1982 Census of Mineral Industries, Sross Book Value of
Depreciable Assets, Table 2, page 2-4 and 2-5
c) 1982 Census of Mineral Industries, General Suaaary, Table
7, page 1-28.
d) 1984 Annual Survey of Manufacturers. Statistics for
Industry Groups and Industries, Table 2, p. 1-14.
e) Includes assets that are sold.
PAYROLl&BENIF ITS
RENTS
SUPPLIES & MATERIALS
FUEL
EXPENSED MINERAL RIGHTS
337,200 \d 267,700 \c
13,000 \a 9,800 \c
3,576,600 \d 540,000 Vc
161,400 \c
........ 77,500 \c
9-25
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Table 9-8: Producers of Phosphate Rock, yet Process Phosphoric Acid arsd Phosphate Fertilizer.
(Thousand Metric Tons Per Year}
PLANT
PHOSPHATE
PHOSPHORIC
AMMONIUM
CONCENTRATED
COMPANY
LOCATION
STATUS
ROCK
ACID
PNOSPHATE
SUPERPHOSPHATE
Freeport HcHoran
Dortaldsonvi lie, LA
OPERATING
430.8
816.3
Pierce, Ft
OPERATING
380.9
75.3
250.3
Uncle Sam, LA
OPERATING
798.2
Fort Green, FL
OPERATING
2,721,0
Payne Creek, FL
OPERATING
2,721.0
Taft, LA
PLANNED
335.6
Arcadian Corp
Geismar, LA
OPERATING
163.3
125.2
Bartow Chem (U. R. Grace)
Bartow, Ft
OPERATING
375.5
CF Industries
Ptant City, Ft
EXPANSION
789.1
Plant City, FL
OPERATING
544.2
367.3
Chevron Chemical Co
Rock Springs, UY
OPERATING
181.4
181.4
Vernal, UT
OPERATING
1,179.1
Conserv (Agrimont)
Nichols, Fl
OPERATING
181.4
172.3
Cominco
Garrison, MT
OPERATING
249.4
Estech, Inc
Watson Mine, FL
OPERATING
907.0
farmland Industries
Pierce, Fl
OPERATING
520.6
304.8
Florida Phosphate Corp
Lakeland, FL
OPERATING
108.8
Ford Motor Co
Dearborn, MI
OPERATING
9.1
Gardinier
Tampa, Fl
OPERATING
653.0
430.8
272.1
Fort Meade, FL
OPERATING
2,721.0
Grace, U. R, & Co
Bartow, Fl
OPERATING
281.2
648.5
113.4
Hooker's Prairie, FL
OPERATING
2,721.0
Four Corners, FL
OPERATING
4,988.5
IMC FertiIizer, Inc
Bonnie, Fl
OPERATING
1,541.9
1,224.5
163.3
Bartow, Ft
OPERATING
11,337.5
648.5
Brewster, Ft
OPERATING
4,555.0
Kaiser Steel Corp
Fontana, CA
OPERATING
13.6
Mobil Chemical Co
Fort Meade, FL
OPERATING
2,902.4
Nichols, FL
OPERATING
1,360.5
Pasadena, TX
OPERATING
217.7
208.6
Monsanto Co
Henry, ID
OPERATING
907.0
Nu-West Industries
Conda, ID
OPERATING
281.2
189.6
Dry Valley, ID
OPERATING
1,360.5
Wingate Creek, FL
PLANNED
1,814.0
Pascagoula, MS
OPERATING
308.4
312.9
Occidental Ag Chemicals
White Springs, Fl
OPERATING
4,988.5
1,015.8
317.5
Columbia, TN
OPERATING
907.0
PresnelI Phosphates
Columbia, TN
OPERATING
453.5
Soyster Co
Mulberry, FL
EXPANSION
226.8
249.4
Piney Point, Fl
OPERATING
172.3
166.9
Simplot, J. R.
Pocatello, ID
EXPANSION
317.5
173.2
40.8
Fort Hall, ID
OPERATING
907.0
Smoky Canyon, UY
OPERATING
1,814.0
Stauffer Chemical Co
Leefe, WY
OPERATING
453.5
Mt Pleasant, TW
OPERATING
544.2
Wooley Valley, ID
OPERATING
680.3
Tennessee Valley Authority Muscle Shoals, AL
OPERATING
18.1
Texasgulf (Aquitaine)
lee Creek, NC
EXPANSON
5,079.2
1,020.0
348.3
299.3
USS Agri-Chemicals
Bartow, FL
OPERATING
219.5
109.7
Fort Meade, Fl
EXPANSION
1,814.0
426.3
Total United States
60,174.9
9,263.2
7,734.0
1,616.3
For completeness, this table includes companies that only produce phosphate rock and do not
produce phosphoric acid.
SOURCE; National Fertilizer Development Center, Tennessee Valley Authority, "North American
Fertilizer Capacity Data," pp. 7-10, July 1988.
-------
Table 9-9: Capacities of Major Phosphoric Acid Producers
Estimates for 1988/89
(Metric Tons Per Year)
PHOSPHATE ROCK PHOSPHORIC
COMPANIES MINIMS ACID CAPACITY
FREEPORT MCMORAN
AGRIHONT
ARCADIAN CORP.
CF INDUSTRIES
CHEVRON CHEMICAL
FARMLAND INDUSTRIES INC.
6ARDINIER INC.
W.R.GRACE & CO. (1)
INTERNATIONAL MINERALS
g CHEMICALS CORP.
MOBIL CORPORATION (2)
NU-WEST INDUSTRIES
OCCIDENTAL CHEMICAL
AGRICULTURAL PRODUCTS
ROYSTER CO.
J.R. SIMPLOT CO. MINERALS
AND CHEMICALS DIVISION
TEXASGULF
USS AGRI-CHEMICALS
OTHER (3)
5,443,200 1,610,280
181,440
163,296
789,264
1,179,360 181,440
520,733
2,721,600 653,184
7,711,200 566,093
15,872,500 1,541,900
4,263,840 217,728
3,175,200 589,680
5,896,800 1,016,064
399,168
2,721,600 317,520
5,080,320 1,152,144
1,814,400 426,384
4,294,880
TOTAL 60,174,900 10,326,318
Source: National Fertilizer Development Center, North
Aaerican Fertilizer Capacity Data, July 1988.
1) Includes Bartow Chcaical phosphoric acid capacity
owned by tf.R. Grace.
2) Includes Mobil Mining and Minerals Phosphates
Minerals Group and Mobil Cheaical Coapany.
3) Companies which produce phosphate rock but do not
produce phosphoric acid are not shown on this table.
0-27
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Table 9-10. Operating Rates for U.S. Fertilizer Producers (percentage of full capacity)
mi 1*82 1983 im 1985
Jan-Jung .fuly-Dac Jmi-Aotc Jufr-Dcc Jan-June July-Ptc Julv-Dw Jan-June July-Pee Average
Phosphoric AeW, Sup®r $8.3 74.3 55.4 59.8 57.1 70.7 72.2 83.8 75.1 87.3 68.0
ftXMpfcorlc Arid, W«t Ptwnm 83.3 78.3 #3.4 83.2 73.2 T».S 84.2 87.2 85.1 74.2 79.2
« CanotntnUK) Super, Qmmitar 82.0 tt.O 47.3 71.8 73.1 83.3 87.3 73.3 76.2 80.8 73.4
i
P*o«pf»te 98.1 73.2 18.0 59,8 70.2 75.4 82.8 81.# 82.1 81,3 75.0
Meawmmanittiit ftiMftwt* §3.4 M,8 81.2 71.1 74.1 83.1 «#.§ 82.3 82.4 80.« 76.1
Bmntmi flw Parti I Mr Iwitttiit*
-------
In order to cut losses, firms have been re-organizing and consolidating. Beker has filed for
bankruptcy under Chapter II and no longer operates any plants. Over 17 percent of U.S. capacity
has either been recently sold or is closed awaiting higher prices. Another 17 percent of current
capacity is somewhat insulated from price shifts because it is owned by farm cooperatives. Following
is a short description of the corporate structure and activities of those publicly owned chemical
manufacturers with WPP A operating capacity of over 500,000 tons4. Four privately owned companies
also have a capacity over 500,000 tons. They are C.F. Industries, Gardinier Inc., Nu-West Industries,
and Occidental Chemical Agricultural Products, Inc. Data are not available to describe their financial
status.
W.R. Grace and Company — Grace is a highly diversified company with a 624,000 ton capacity in
phosphoric acid production and 8,500,000 ton capacity in phosphoric rock mining. Grace had sales
of S3.7 billion in 1986, with $2.5 billion in specialty chemicals. Grace went through major
restructuring in 1986 and had losses from continuing operations of $324 million in 1986.
As part of its restructuring, Grace has announced its intent to divest its agricultural chemicals
business and in 1986 it set aside $221 million to cover losses from that move [Ri87], Grace closed
its Four Corners plant during the 1986/1987 season. As of July 1988, however, a report from the
Tennessee Valley Authority shows Grace operating its wet process acid plants in Hooker's Prairie and
in Four Corners, both in Florida [TVA88], Green Markets reported in March 1988 that Grace had
sold more of its retail fertilizer operation and plans to sell the remainder of its fertilizer business by
the end of 1988 (GM88d].
Farmland Industries. Inc. — Farmland Industries, Inc., is a regional agricultural cooperative based
in Kansas City, Missouri. Farmland is owned by 2,186 local cooperatives and serves a federated
network in 19 midwestern states and Canada. Farmland had $2.6 billion in sales in 1987 and profits
of $55.2 million. Petroleum, food marketing, agricultural chemicals and feed are its four principal
sectors. Agricultural chemicals represented 20.2 percent of total sales. Sales of all agricultural
chemicals were $528.5 million in 1987, down from $573.6 million in 1986. This sector had operating
income of $1.3 million, after a loss of $38.4 million in 1986 and $49 million in 1983.
Farmland has a phosphoric acid operating capacity of 574,000 tons in Pierce, Florida, representing
5 percent of the entire industry capacity. Farmland has a phosphate rock mining capacity of 2
4
Unless otherwise indicated, the information for each of the companies that is provided in this
section came from annual corporate reports for the years 1982 to 1987.
9-29
-------
million tons; this operation was closed as of January 1988. Us total fertilizer capacity is 3.6 million
tons, including operations in ammonia, ammonia nitrate and urea. In addition, Farmland has a
proposed phosphate mining operation in Hardee County, Florida with a 40 million ton reserve
[TVA88].
In 1987, Farmland sold 3.58 million short tons of phosphate and nitrogen fertilizers. Unit sales
increased in 1987 by 25 percent, but at lower prices so that revenue from fertilizer safes increased
only $13.9 million. Growth came from an expansion of sales to industry and from exports. Sales to
non-members represented 27 percent of total sales of agricultural chemicals.
In some years, losses in phosphate operation have been fully offset by gains in other agricultural
chemicals. While Farmland had operating income of $2.7 million for agricultural chemicals in 1985,
the phosphate division lost $42 million in that year. In 1985, Farmland closed a sulfur mine that
services phosphate production and charged the $3.7 million cost against phosphate operations. In
1984, phosphate operations lost $ 12 million while agricultural chemicals overall had positive operating
income of $38 million. In 19E3, total phosphate losses amounted to $8.3 million.
AMAX — AMAX is a diversified energy development and minerals company with extensive
operations in aluminum, coal and molybdenum as well as many other minerals. AMAX had modest
and successful operations in phosphate and potash throughout the 1970s, with average sales between
1973 and 1979 of $43.7 million. AMAX expanded the phosphate operations with a purchase of the
Big Four mine in Florida in July 1980. Beginning in 1982, AMAX phosphate operations have been
consistently unprofitable; in 1984 AMAX announced its desire to get out of the business.
In 1984, AMAX began to phase out the agricultural chemicals segment and set aside $195 million for
losses on properties and investments in that segment. In December of 1985, AMAX had a tentative
agreement to sell its phosphate operation for $40 million. However, a July 1988 listing of production
capacities by the Tennessee Valley Authority continues to show AMAX with a closed 2.5 million ton
capacity phosphate rock mine in Big Four but lists its 190,000 ton phosphoric acid capacity in Piney
Point, Florida as sold [TVA88]. Because all AMAX facilities have ceased operations, the firm is not
included in Table 9-8.
Total sales for AMAX in 1986 were $1.3 billion, with earnings of $89.4 million. Because of changes
in the organization of the company annual report, it is not possible to reliably analyze the change in
total sales during the mid-1980s. The 1986 annual report gave 1985 sales of $1.2 billion with an
operating loss of $106.5 million. Losses in that division during those years were $17.3, $214.4 and
$17.1 million, respectively.
9-30
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International Minerals and Chemicals CIMC) -- IMC is a diversified chemical producer. Up to 1986,
its sales were concentrated in animal and fertilizer products. That year it acquired Mallinckrodt, Inc.,
a producer of medical products, drugs, chemicals, laboratory reagents for $700 million. Fertilizer
sales dominate IMC financial activity. In 1986, IMC fertilizer sales represented 53 percent of total
net sales of $1.6 billion. Animal products, including feed grade phosphate and other feed additives,
and Mallinckrodt, Inc. represented 11 percent and 40 percent, respectively. Phosphate chemicals
represented 41 percent of total IMC fertilizer sales.
In 1987, IMC owned or operated 15 percent of U.S. phosphoric acid capacity. It owns 25 percent of
the U.S. phosphate rock mining capacity in Florida.
Most of the WPPA is produced at its New Wales, Florida facility (1.7 million tons of WPPA
manufacturing capacity). The phosphate rock is mined at a nearby plant. In 1987, 45 percent of its
New Wales production was sold domestically, 38 percent was exported and 17 percent was used by
IMC to manufacture its own brand of fertilizer. The plant operated at 85 percent capacity in 1987.
In 1986, IMC reported operating losses of $61.0 million, but by 1987 sales had picked up, yielding
$67.1 million in operating profits. Nevertheless, IMC fertilizer sales have been flat since 1986,
reflecting lower average product prices.
IMC has also been cutting operating costs. It reported developing a process to reduce the amount of
sulfuric acid needed per unit of P2O5 product. It has sold most of its retail outlets in the midwest.
IMC Fertilizer Group employment has been reduced to 5,525 in 1986 from 6,687 in 1981.
Texasgulf Chemicals Comnanv -- Texasgulf Chemicals Company has operations primarily in
phosphate and sulfur, but also in potash and soda ash. Texasgulf is a division of Elf Aquitaine, S.A.
(EAI). EAI is a U.S. subsidiary of Elf, a multinational company based in Paris with operations in
oil, gas, chemicals and pharmaceuticals. EAI's 1986 sales were $1.7 billion. The sales for Texasgulf
were $474, $461 and $547 million in 1984, 1985 and 1986, respectively. Texasgulf had assets of $2.2
billion in 1986.
Texasgulf has a phosphoric acid plant in Lee Creek, North Carolina, with a capacity of 1,270,000
tons, 10 percent of U.S. capacity. It also has a phosphoric mining capacity of 5.6 million tons. The
Lee Creek plant was expanded, beginning in the mid-1970s. The expansion was completed in 1986.
This plant is unusual in a number of ways. It disposes of its gypsum by blending it with clay and
returning it to the mine. It also removes the overburden in its Lee Creek mine with dredges.
9-31
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The Lee Creek wet-process plant produces a high quality phosphoric acid that has been sold for
industrial grade acid and for animal feed. Texasgulf produces several types of calcium phosphate
animal feeds in North Carolina and Nebraska.
Freeport-McMoRan. Inc. -- Freeport-McMoRan, Inc. (FMI) has operations in agricultural minerals,
oil, gas, geothermal energy and uranium. Revenues in 1986 totaled $629,7 million. Because of a $277
million write down of oil and gas related assets, its operating loss in 1986 was $147 million. Revenues
were $722 million and $842 million in 1985 and 1984, respectively, and operating income was a
positive $156 million and $170 million, respectively. The agricultural minerals sector earned $39
million in 1986 and $62 million in 1985.
FMI's sulfur operations are as important as its phosphate operations and depend heavily on demand
for phosphates. Sales of phosphate and sulfur in 1986 were $161.5 and $161.3 million, respectively.
In mid-1986, FMI conveyed its sulfur, phosphate and geothermal properties, among others, to
Freeport-McMoRan Resource Partners, Limited Partnership (FRP) and approximately 19 percent of
FRP was sold in a public offering.
FMI produces phosphoric acid in its Uncle Sam plant in Louisiana. This plant produced 715,500 tons
in 1986 and 714,000 tons in 1985. FMI produced 332,200 tons of DAP in 1986.
Freeport Uranium Recovery Company produces uranium oxide at recovery facilities at the Uncle Sam
plant and at the Agrico plant in Donaldsonville, Louisiana. These operations produced 1,720,000
pounds of uranium oxide in 1983.
The Uncle Sam plant has limited space to store its phosphogypsum. As a consequence, FMI has
worked with Davy McK.ee and the Florida Institute of Phosphate Research to test technology to
recycle phosphogypsum into sulfuric acid and aggregate. FMI is spending $3 to $4 million on a
demonstration plant at Uncle Sam that will consume 33 tons of phosphogypsum per day [L188],
Construction of the plant was halted in the summer of 1987 because of engineering problems, but was
resumed in the spring of 1988. An FMI spokesperson said that the plant will begin operation in the
early fall of 1988 [GM88d],
The FMI phosphate rock mine was shut down in April 1982, because of weak demand for phosphate
rock, and reopened in April 1984. During this time, FMI purchased rock from others. At the end
9-32
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of 1986, FMI held phosphate rock proved and probable reserves of J 4 million tons and sulphur
proved and probable reserves of 10,5 million long tons.
FMI agreed in principle to purchase most of the assets of Agrico Chemical Company, a subsidiary
of The Williams Company, for $250 million cash and another $100 to $250 million in cash or other
compensation. Agrico has extensive operations in Florida and Louisiana in phosphate mines,
phosphoric acid, and phosphate fertilizer plants.
9.2.1.4 Employment
In 1988, approximately 10,900 persons were employed directly by the phosphoric acid and phosphate
fertilizer industry [DOC88a], Since 1981, employment in the industry has decreased at an average
annual compound rate of 3.6 percent. Table 9-11 provides employment and earnings trends from
1984 to 1988. Employment increased during the 1970s and peaked in 1981 at 15,700 workers
[DOC84],
Phosphoric acid production is not a labor intensive industry. Operating labor represents less than 2
percent of total costs, according to TFI. Operating labor represents 9 percent of the cost of mining
phosphate rock [TFI87c],
Direct employment represents only a part of the employment that could be affected by a change in
demand for WPP A. Others affected would include phosphate rock plant workers, miners and
agricultural chemical manufacturers and retailers. The phosphate rock mining industry employed
7,800 people in 1982 [DOC82b],
The 1982 drop in fertilizer sales led to the reported firing of nearly 5,000 workers in phosphate
producing plants. At least another 25,000 in businesses that depended on phosphate, such as
engineering firms and port workers, lost jobs as well. This reduction in sales provided a graphic
representation of the importance of the phosphate fertilizer industry for local economies in the U.S.
For example, the drop in fertilizer manufacturing activities hurt Tampa Electric which supplies
power to most of Florida phosphate companies and the Tampa Port Authority which handles over 87
percent of all WPPA exported from the United States [Te87,FF85].
9-33
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Table 9-11: issplopient in the Phosphate Industry, (thousands)
Compound Annual
Percent Change
1984 1985 1986/1 1987/1 1988/2 1972-85 1980-85
total Eaployaent
Production Workers
Average Hourly Wage (J)
Notes: /1 Estiaated.
/2 Forecast.
Source; International Trade Comission, U.S. Oepartaent of Coaaerce, U.S. Industrial
Outlook 1988, January 1988, p.14-3.
13 13 11.2 10.9 10.9 -1 -3.6
8.9 8.7 7.8 7.8 7.8 1.6 -4.6
11.54 12.12 12.73 13.75 - 8.9 8
9-34
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9-2.2 Characteristic^ of Phosphoric Acid Demand
The demand for WPPA is largely determined by the demand for phosphate fertilizers. Widespread
chemical fertilizer use is a relatively recent phenomenon. In the early- to mid- 1960's world and
domestic fertilizer use expanded rapidly. The "Green Revolution" of this time brought high yielding
varieties of grain crops which required more intensive fertilizer application than did traditional
varieties [Te87], Between 1970 and 1983, fertilizer use per acre grew about 271 percent in low
income countries and 107 percent in middle income countries. The largest per acre increases were
reported by India (a 246 percent increase) and the People's Republic of China (a 332 percent increase)
[WB86].
Fertilizer use has not increased evenly for all nutrients. Nitrogen use has increased more rapidly than
have phosphate and potassium use, due primarily to the favorable response of crop yield to
nitrogenous fertilizer. The share of phosphates in total plant nutrient consumption in the U.S. has
declined from about 33 percent in 1960 to about 23 percent in 1986 [Vr86]. Figure 9-3 traces the
growth of plant nutrient use in the United States.
Given its relatively small share of domestic and world phosphate use (about 5 percent, see figure 9-
2), fluctuations in animal feed consumption are of limited importance to the phosphate industry.
Consumption of phosphate supplements for animal feeds and other minor uses has varied in the past
decade, reaching a high of 661,920 tons in 1984 [DOC87], Demand for phosphate animal feed
supplements dropped because of a decrease in the recommended supplement ratios and the increased
availability of a substitute, fish meal. Almost all phosphate supplements are in the calcium
phosphate form. Exports of phosphate supplements represented only 5 to 6 percent of 1983 domestic
production [SRI85J.
9.2.2.1 Determinants of Domestic Demand
Demand for WPPA in the United States depends directly on those factors which affect the demand
for fertilizer. Some of these factors are acreage planted, application rates, crop prices, prices of other
fertilizers, farm income, population, and weather. It is important to understand how these are
interrelated in order to understand what has determined the growth of phosphate fertilizer demand
in the 1980s and the soft prices which have characterized the domestic and international markets.
The consumption of any agricultural nutrient depends upon the acreage of different crops and the
application rates on specific crops. Some crops use more phosphate than others and respond much
9-35
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better to one type of fertilizer than to another. Food grain production requires lower proportions of
nutrients per acre than does feed grain production [WH88], In the United States, corn uses the most
phosphate fertilizer per acre of the major crops, while soybeans and wheat use the least [Vr86].
Planting pattern changes on U.S. farms have favored growth of phosphate demand. Almost every
year since 1964, more acres have been harvested with corn than any other major crop including
wheat, cotton and soybeans. In addition, a greater proportion of corn acreage has been fertilized over
the years than any other major crop. Approximately 85 percent of the corn acreage harvested in 1987
received phosphate applications, compared to roughly 50 percent of cotton, 48 percent of wheat and
29 percent of soybean acreage. In fact, U.S. farms used more fertilizer of all types on corn than on
any other crop. Almost 98 percent of corn planted received some type of fertilizer in 1985, compared
to about 75 percent of the wheat planted and 38 percent of the soybeans [Vr86]. Finally, major crops
(which include corn, wheat, soybeans and cotton) are fertilized more intensively than non-major
crops (such as sorghum, oats, barley, rice, rye, peanuts, potatoes). The percentage of acres planted
to major crops has been increasing since 1964, while acreage of non-major crops harvested decreased
13 percent between 1964 and 1985 [WH88].
Application rates have been an important factor influencing fertilizer demand in the U.S. Use on
corn and other crops increased dramatically between 1964 and 1980, due more to higher application
rates than to an increase in the proportion of acreage either harvested or fertilized. For example,
while corn acreage increased by about 36 percent between 1964 and 1980, nitrogen use rose 272
percent, phosphate use increased 118 percent and potassium increased 225 percent. In the early
1980s, phosphate application per acre began declining [Vr86]^. Since 1985, the rate of phosphate
fertilizer use has been linked more closely to increases in acreage planted and fertilized than to
application rates [Vr86j.
Since 1983, the acreage of major crops planted has depended in large part on U.S. government price
support programs. Under the payment-in-kind program of 1983, U.S. farmers agreed not to grow
crops on a total of 77 million acres (37 percent of the land sowed with grains, cotton and rice). In
return for idling their land, farmers got up to 80 percent of the quantity of grain they would
5
The decline in phosphate application rates is generally explained as follows: Unlike nitrogen
and potash, any phosphate not used by the crop remains in the soil and is available for a future crop.
As this fact became known, farmers decreased phosphate use. Also, new tilling and crop management
practices have allowed farmers to increase yields using less phosphate (see E.A. Harre, "Emerging
Trends in World Phosphate Market," National Fertilizer Development Center, Circular No. Z-228,
September 1987).
9-36
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normally have grown. The in-kind payments came from crops that had been stored by the
government [Wb86].
In 1985, the Food Security Act was passed to increase grain exports, reduce inventories and support
farm income [St85], Through a variety of different measures, including set-asides, paid land
diversions and the Long-Term Conservation Reserve, U.S. crop-planted acreage decreased from 363
million acres in 1981 to 305 million acres in 1987 [WH87], Farmers have responded to the acreage
reduction by using somewhat higher quantities of fertilizer per acre on the remaining acreage but in
general the acreage reduction has led to a reduction in demand for phosphate fertilizers.
These programs, aided by dry weather and the drop in the number of operating farms between 1985
and 1987, have begun to reduce the reserves of surplus agricultural commodities accumulated by the
U.S. Department of Agriculture (USDA). In 1988, corn stocks are expected to fall by 400 million
bushels, wheat stocks by 200 million bushels, and soybean stocks by 20 million bushels [WHS7],
Fertilizer and crop prices also affect the demand for plant nutrients. In general, as the fertilizer price
to crop price ratio decreases, the application rate per acre increases. As crop prices rise relative to
fertilizer prices, farmers wish to increase yields and hence increase fertilizer use.
Because the full effect of reduced phosphate application does not occur immediately, farmers may
be highly-responsive to fertilizer price increases in the short run. Phosphate is depleted from the
soil more slowly than nitrogen, for example, and the effects of decreased phosphate application only
become apparent once the level in the soil is depleted. It is estimated that a 10 percent reduction in
phosphate application in the first year will reduce corn yields by 3 percent in the first year and 4
percent in the third year. Wheat yields are more sensitive in the long run: a 10 percent reduction
in phosphate application will reduce yields I percent in the first year but by 7 percent in the third
year [GA079],
Fertilizers represent only about 7 percent of total farm costs; phosphate fertilizers account for about
J percent of total farm costs. On the other hand, fertilizers account for a large part of the variable
costs of crop production: 50 percent of wheat production costs, 35 percent of corn costs and 20
percent of soybean costs [GA079J.
Finally, fertilizer use is also affected by changes in farm income. Net farm income, in 1967 dollars,
was lower in 1985, $9.5 billion, than in 1971, $12.4 billion. Yet this still represented an improvement
9-37
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Figure 9-3
United States Fertilizer Consumption
thousand short tans nutrient
25,OOO
PotusiuM
PhoSPhAt«
20.000
N> tNfen
10,000
O h n n « 10 *
«««««««
CN Chi Qfl 0t {ft flfc Qb
H H H H H M H
o«: USM
-------
over the 1983 low of $4.4 billion [USD87e]. In 1986, over 33 percent of all net farm income came
from government payments. The heavy dependence of farmers on government programs has
increased their responsiveness to acreage reduction policies [Ri87],
9.2.2.2 Determinants of Foreign Demand
Foreign demand for WPPA depends on the same variables described in the preceding section:
population, acreage, crop variety, fertilizer application rates, and crop and fertilizer prices. World
plant nutrient consumption has been growing at an average annual compound rate of 4.2 percent since
1975, though in 1986 consumption of fertilizer dropped about 4 percent from the 1985 high of 34.29
million metric tons [TFl86b]. Phosphate fertilizer consumption accounts for about 26 percent of total
world nutrient consumption and increased at an annual compound rate of 3 percent between 1975 and
1985 [TFIS6b].
Fertilizer use patterns have varied considerably from one region of the world to another. Fertilizer
demand in less developed countries (LDCs) has tended to grow much faster than in the industrialized
countries, but fertilizer use per acre is still, in absolute terms, much greater in the industrialized
world [WH87J.
According to each of the fertilizer demand forecasting models examined for this report, population
growth is one of the most important factors leading to growth in the volume of world grain trade and,
indirectly, affecting acreage and fertilizer application rates. Population growth in LDCs has
historically been 1 to 2 percentage points higher than in high-income economies. But high population
growth rates alone are not enough to guarantee high grain demand. Grain demand in low- and
middle-income countries has been sluggish since 1980 due to growing debt problems and the
relatively high value of the U.S. dollar vis a vis these currencies. In fact, world grain trade has
stagnated or declined in recent years, in contrast to the 75 percent increase in trade during the 1970s,
due in large part to the adverse economic conditions facing these countries.
Acreage expansion seems to have played a limited role in the expansion of world fertilizer demand.
World acreage, which had declined since 1982, stabilized by 1987. While acreage expansion rates
have differed regionally, overall expansion has been limited. In North America and Europe, farm
subsidy policies and acreage reduction programs have caused acreage planted and harvested to decline
since the early 1980s. In Latin America, economic and financial instability stemming from debt
problems have kept growth down. In Asia, low commodity prices have led to reduced acreage from
the highs of the 1970s. In Africa, drought has severely limited agricultural production [WH87J.
9-39
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Fertilizer application rates have varied substantially across regions as well. The developed regions
(North America and Western Europe) have mature agricultural industries, and fertilizer gains made
through technological advances have been minimal since the early 1980s. Growth of fertilizer
consumption has been strongest in those regions where fertilizer use has not matured, such as Latin
America, Asia and Africa. Thus, while application rates are higher in the developed regions, growth
rates of application per acre over time are much lower [WH88].
Differences in application rates by region also reflect variations in cropping patterns, soil quality and
climatic conditions. Acreage shifts to coarse (or animal feed) grains in Western Europe have brought
about an increase in the demand for fertilizer nutrients since coarse grains are fertilized more
intensively than other crops [WH88]. In Latin America, fertilizer use has been among the lowest in
the world due to high natural soil fertility. However, Latin America is the only region in the world
where the application rate for phosphates is greater than that for nitrogen, due to differences in soil
fertility and differing crop needs. According to Wharton Econometric Forecasting Associates
(WEFA), the nitrogen-to-phosphate ratio in 1987 was 0.8 in Latin America, compared to 2.8 in North
America, 1.2 in Africa, and 3.2 in Asia [WH88]. Hence, acreage shifts in Latin America have a
relatively large impact in phosphate fertilizer consumption.
World demand for fertilizer has also been affected by shifts in crop prices. The general oversupply
of farm commodities in Japan, Western Europe and North America in the early 1980s has changed
the demand for plant nutrients. The Green Revolution in the 1960s introduced new, higher-yielding
varieties of grains to the developing world, dramatically increasing yields and bringing many
countries close to self-sufficiency in food. While the initial impact of the Green Revolution was to
dramatically increase dependence on chemical fertilizers, by the early 1980s, it also enabled many
countries to reduce their reliance on grain imports. By 1987, low world grain prices adversely
affected acreage planted and fertilizer use in many grain-producing countries, particularly in the U.S.
and Europe.
Domestic and export fertilizer prices have fluctuated very differently within different regions and
countries. The reasons for these fluctuations are varied and include weather, government crop and
fertilizer pricing policies, decisions to invest in new capacity, and capacity utilization. These
elements have resulted in shortages and oversupplies of particular types of fertilizer at various times
[WH87,WH88|.
9-40
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In general, however, over-investment in plant capacity relative to demand (both foreign and
domestic) has led to lower fertilizer prices in all countries. Aggressive pricing policies by large
suppliers such as Morocco have further increased the downward pressure on prices. In fact, by 1987
this situation had led a number of developed countries (European Economic Community, U.S. and
Australia) to impose minimum prices, quotas and/or dumping margins on fertilizer imports.
Regulatory agencies in these countries found that LDC imports had been sold below their fair market
value and had caused material damage to domestic suppliers. These trade restrictions generally
resulted in higher domestic prices in these countries {Co87J.
Finally, demand for fertilizer depends on the availability of foreign exchange, particularly for LDCs.
Oil price increases in the 1970s, while causing balance-of-payments problems, also directed more
money to Western bankers who were then willing to increase loan portfolios in LDCs. LDCs used
the increased availability of foreign exchange to buy farm supplies and inputs, pushing up the
demand for fertilizer in the 1970s and early 1980s. This situation lasted until rising interest rates
in the 1980s, low commodity prices, and ensuing Third World debt service problems restricted the
availability of foreign exchange in LDCs. Thus, despite drops in fertilizer prices in the 1980s, many
less-developed economies were unable to import their full requirements. In the 1980s, aid and
concessionary loans have played an important role in determining fertilizer imports and use.
9.2.2.3 World Demand for U.S. Phosphate Exports
World Trade Characteristics
World exports of the three plant nutrients, nitrogen, phosphorus and potassium, presently amount to
approximately one-third of total world consumption, but this percentage has been declining. Most
of the decline, particularly in phosphate trade, has been felt by the United States, since exports from
African, Near East and Far East producers have actually increased.
In general, the share of the world phosphate trade held by the developed countries has been declining,
though production from the developed economies still dominate world trade. The large increase in
the LDCs share of world phosphate trade in the 1980s was largely due to the increase in Morocco's
WPP A production capacity and the development of new plants in the Philippines. The Moroccan
phosphate industry is government owned and has been pursuing an aggressive pricing policy aimed
at increasing its share of the world market [Co87J.
9-41
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The regions most dependent on Imports were Africa (which imports over 70 percent of its nutrient
requirements, and about 58 percent of its phosphate needs), the Far East (which imports 40 percent
on average, and 45 percent of its phosphate needs) and Latin America (importing 48 percent overall,
and 55 percent of its phosphate requirements). In contrast, the developed countries imported on
average 36 percent of their nutrient needs and 25 percent of their phosphate needs. Most trade by
centrally planned economies was with other centrally planned economies [Co87],
U.S. Export Market
In recent years, U.S. phosphoric acid exports (which do not include phosphate fertilizers) have
typically been less than 10 percent of total domestic output [St86a]. Exports, however, of phosphate
fertilizers represent a much higher proportion of phosphate fertilizer production. The U.S. is the
largest exporter of phosphate fertilizer to the world. But the U.S. share of the phosphate fertilizer
export market has decreased from 53 percent in 1981-82 to about 47.6 percent in 1985-86. In 1987,
according to The Fertilizer Institute, the U.S. exported 620,777 tons of merchant grade phosphoric
acid, 2,686,104 tons of concentrated superphosphate and 6,564,300 tons of DAP. These export levels
are a significant improvement over the levels reported by the Bureau of Census for 1985 and 1986
[Ye88,St86a], Table 9-12 shows the level of the U.S. exports between 1979 and 1986.
U.S. exports have met increasing competition since the mid-1980s. Many phosphate rock producers
in less developed countries have increased their capacity to convert phosphate rock into fertilizer.
The resulting oversupply of phosphate commodities partially explains the soft and falling export
prices of the late 1980s [St86aJ.
High tariffs on U.S. exports of phosphate rock and phosphate fertilizer also affect the demand for
U.S. product. Domestic fertilizer companies paid about $200 million in tariffs in 1985. The Indian
government alone collected $40 million from U.S. manufacturers. Such tariffs decrease the
competitiveness of U.S. producers in the international market [St86a].
Nevertheless, foreign demand for U.S. phosphate fertilizer seems to have strengthened in 1987.
Consumption of U.S. fertilizer by the rest of the world rose 2 percent in 1986/87 and 3 percent in
1987/88. Demand grew most rapidly in Asia and Latin America. Several major importers such as
India and China have reduced their fertilizer reserves so that more of their demand is being reflected
in increased imports than in preceding years [Te87],
9-42
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The devaluation of the U.S. dollar in 198? increased the competitiveness of U.S. producers with
respect to foreign producers. Relaxed foreign exchange constraints in many LDC's have helped to
increase UrS. exports to LDCs. Improved demand and reduced phosphate commodity stocks also
helped push up phosphate fertilizer prices [Te87].
In addition, U.S. exporters have organized into a cartel-like operation to help promote their product
more effectively abroad. In 1987, almost all U.S. exports were handled by The Phosphate Chemical
Export Association (Phoschem), an association for the export of phosphate chemicals from the United
States. Phoschem operates as a membership association under the provisions of the Webb-Pomerane
Act of 1918 and is regulated by the Department of Commerce and the Department of Justice. The
Act permits U.S. companies to effectively organize export operations in the face of overseas
competition when this competition is considered to be, as U.S. manufacturers allege, in the form of
a cartel. After nearly disbanding during the very soft 1985 export market, the organization has
rebounded.
Trade in WPP A occurs at two levels. Of the $1.6 billion in phosphate fertilizer sales in 1985, 18
percent was in phosphoric acid and the remainder was in finished fertilizers, especially diammonium
phosphate (DAP) [DOC86aJ. The distribution of sales varies with each year. Large sales in recent
years of phosphoric acid to the U.S.S.R. by Occidental Petroleum Co. and large sales of DAP to China
have made the export market erratic. As described in the section on demand for phosphoric acid,
in recent years competition has intensified in the markets for phosphate fertilizers and phosphoric
acid.
Foreign Competition
Two types of foreign producers have cut into the U.S. export market. The first is new production
in countries that have traditionally been important importers. The second is expanded production
facilities in exporting countries. Importing countries such as The People's Republic of China and
India have expanded fertilizer production capacities. Some of these facilities are not competitive with
imports but are nevertheless protected from foreign competition. To a limited extent, these facilities
have merely switched from importing finished fertilizers to importing phosphoric acid. Less
developed countries are the primary competitors in the export market. Most of the LDC's new
phosphate production capacity has been initiated by state owned enterprises. Other developed
countries have production capacities that, with a few exceptions, cover only a portion their domestic
needs. Western Europe has in recent years cut back production that supplied primarily domestic
needs, in response to increased costs and environmental concerns.
9-43
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Table 9-12: U.S. Export# of Phoaphorie Acid
(Part 1 of 23
(Thousnad Metric Toiw, Thoutand Dollars)
LESS THAN 65% P205 GREATER THAN 65% P205 TOTAL
» : VALUE
QUANTITY VALUE QUANTITY VALUE
1986
700
110,010
NA
NA
NA
1985
716
141,162
95
123,817
264,979
1984
867
181,055
854
215,513
396,568
1983
337
84,979
842
237,167
322,146
1982
530
117,785
893
289,296
301,291
1981
1,004
303,390
549
183,506
592,686
1980
1,212
281,348
84
21,686
303,034
1979
677
131,324
505
95,289
226,613
SOURCE: Uilliaa Stowasser, Bureau of Mines, "Phosphate
Rock," Minerals Yearbook, Preprint of 1986, 1985, 1984,
1982, 1980, 1978-79, 1977 arid 1976, Also, Department of
Coaaerce, U.S. Exports.
9-44
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Table 9-12; Exports of Phosphate Fertilizer.
(Part 2 of 25
(Thousand Metric Tons, Thousand Boilers}
SUPERPHOSPHATE (1> DIAMMONIUH TOTAL
FERTILIZER
QUANTITY
VALUE
QUANTITY
VALUE
VALUE (2)
1986
1
237
155,861
4,120
641,385
907,256
1985
1
420
176,515
6,131
1,048,322
1,489,816
1984
1
092
149,150
6,346
1,200,579
1,746,297
1983
1
263
166,177
4,758
729,233
1,217,556
1962
1
148
158,140
3,707
678,685
1,138,116
1981
1
$20
245,341
3,942
789,770
1,627,797
19®
1
57?
287,366
4,995
1,095,944
1,686,344
1979
1
469
188,898
4,026
676,194
1,091,705
1978
1
494
145,703
3,929
525,610
671,313
1977
1
181
HA
2,581
335,883
446,417
1976
1
210
NA
2,182
269,855
380,690
1) The export figures for superphosphate are divided
between fertilizer that is less than and greater than
40 percent phosphoric acid. These eoluans are suaaed
above.
2) Includes pure phosphoric acid and other phosphate
fertilizers besides superphosphate and diUMoniua.
9-45
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In 1986, Monsanto Chemical Co. and FMC Corp, filed an anti-dumping petition with the U.S.
Department of Commerce over imports of industrial phosphoric acid from Belgium and
Israel[CMR86]. While this dispute does not directly affect the agricultural phosphoric acid market,
it is an indication of the increased level of competition.
Table 9-13 shows the major exporting countries. The U.S. has maintained its dominant position in
the phosphate fertilizer trade with over half of all sales. Morocco stands out as the key foreign
competitor. Morocco is the leading exporter of phosphate rock and in recent years has dramatically
expanded its phosphoric acid and fertilizer capacity. Moroccan phosphate fertilizer exports nearly
doubled between the 1981/1982 season and the 1984/85 season and have continued to increase
capacity. Phosphoric acid exports, which are more important to Morocco than are phosphate
fertilizer, have also nearly doubled during this period [FA085]. The Moroccan industry is operated
by the state owned company, Office Cherifien des Phosphates (OCP). OCP has its own fleet of ships
designed to transport phosphoric acid. Many in the industry believe OCP will operate at a loss in
order to expand its market share and to bring in foreign currency.
Outlook
The predominance of domestically protected foreign production and state owned export competition
has led Zellars-Williams to label the U.S. the "residual supplier." As world demand for phosphate
product fluctuates, the production of U.S. firms goes up and down [Ze86]. This is because the U.S.
firms are among the only ones that will not operate at a loss for prolonged periods, British Sulphur
Corporation echoes Zellars-Williams' analysis and predicts that continued overcapacity in the
international market will force the U.S. industry to consolidate to only 4 or 5 producers [BSC87b],
Since 1981, the U.S. has been unable to sustain the rate of growth of its phosphate exports. Zellars-
Williams forecasts' that phosphate fertilizer exports from the U.S. will decline from 4.45 million tons
in 1985 to 3.08 million tons in year 2005, while African exports will increase 1985 to 8 million in year
2005.^ In Zellars-Williams' forecast, U.S. exports are fairly strong until the year 2000, when exports
are projected to be at 5.3 million tons. However, between the year 2000 and 2005, U.S. exports
plunge 42 percent. This decline coincides with the expected exhaustion of prime central Florida
phosphate reserves and the need to develop new, more expensive reserves.
^Zellars-Williams' estimates of export differ from those given in Table 9-14, because this table
reports exports on a "fertilizer year" (July 1 to June 30) instead of a calendar year.
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Table 9-13: Trade in Phosphate Product# by Major* Exporter, 1981-1984 CD
PHOSPHATE FERTILIZER
METRIC TONS, P205)
1981
1982
1983
1984
UNITED STATES
3,403,000
3,553,000
3,948,000
5,047,0)0
MOROCCO
125,542
207,308
383,315
245,500
USSR*
254,100
250,000
312,000
281,900
NETHERLANDS*
311,765
336,645
348,215
343,660
TUNISIA
445,600
454,564
485,300
441,280
CANADA
162,000
96,000
94,000
99,000
BELGIUM-LUX
470,000
411,000
480,000
450,000
TOTAL UORLD
TRADE
6,450,486
7,064,137
8,213,908
9,193,717
~Large importer
of phosphoric acid.
PHOSPHATE
ROCK
(METRIC TONS,
P205)
1981
1982
1983
1984
UNITED STATES
10,554,000
9,735,000
13,197,000
11,318,000
MOROCCO
15,635,000
13,976,000
13,976,000
14,951,000
USSR
5,020,000
5,278,000
4,899,000
4,383,000
TOTAL UORLD
TRADE
45,271,000
43,154,000
47,223,000
47,769,000
PHOSPHORIC ACID
(METRIC TONS P205)
1981
1982
1983
1984
UNITED STATES
761,800
1,047,500
1,235,000
937,000
MOROCCO
548,900
649,800
857,700
1,080,800
TUNISIA
251,800
311,500
380,000
333,500
SOUTH AFRICA
229,600
228,100
123,300
211,900
TOT«. UORLD
TRADE
2,453,200
2,880,500
3,189,500
3,258,700
1) Years indicated are "fertilizer years,," fro* July 1 to June 30,
Source: Fertilizer Yearbook, Food and Agriculture Organization of
the United Nations, 1985.
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The decline in U.S. exports can be expected to continue as the less developed countries expand their
phosphoric acid and fertilizer capacities. Zellars-Williams forecasts that the U.S. share of the
phosphate rock export market will fall to 15.5 percent in the year 2005, from 23.1 percent in 1984.
Zellars-Williams also forecasts that the Moroccan share of the export market will go from 31.4
percent in 1984 to 46.5 percent in 2005.
9.2.2.4 Demand Forecasts
There are a number of multi-equation models used for forecasting phosphate fertilizer demand. The
models are of varying degrees of sophistication, use a variety of estimation methodologies and have
differing time horizons. They alt include, to one degree or another, the set of variables discussed in
the preceding section; population, acreage of major crops harvested, fertilizer application rates,
fertilizer and crop supply and prices, crop mix and yield estimates.
Forecasters disagree on the outlook for the world as a whole. The Food and Agriculture Organization
(FAO) predicts that worldwide phosphate demand will grow less than one percent per year up to the
end of the century. Zellars-Williams and WEFA analysts have a more optimistic outlook, estimating
annual growth at 1.3 and 2.4 percent, respectively. Their optimism is based largely on the prediction
that grain prices will increase due to grain stock depletion by 1995. While both sets of analysts expect
North American phosphate demand to recover from its lows of the mid-1980s, neither expect acreage
or production to increase to their early-1980 levels.
Table 9-14 provides a basis for comparison of the forecasts for four years of interest. The shorter-
range forecasts provided by, or imputed from, the various models generally agree on the level of
demand over the next few years. The more recent forecasts are substantially more conservative over
the long run, reflecting new information about government-sponsored acreage reduction programs
in the U.S. and Europe. For example, the 1979 Chase Econometrics forecast estimated that U.S.
agricultural demand would grow 3 percent per year between 1979 and 2000, while the 1985 Bureau
of Mines forecast implies a U.S. growth rate of 1.3 percent for 1983 through 2000. The earlier
forecast also did not anticipate the drop in economic growth rates in LDCs and the emergence of
Third World debt problems. The other forecasts provided in Table 9-14 were performed after 1983
and provide more pessimistic assessments due to these events.
However, all forecasters agree that phosphate fertilizer demand (and therefore demand for WPPA)
in developed market economies will grow at a substantially lower rate than demand in other regions
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Table 9-14
Summary Of World Phosphate Fertilizer Demand Forecasts
YEAR
(Million Nutrient Metric Tons P205)
Source
1990
2000
2010
2018
WEFA1
35.10
42.12
49.20
57.20
FAO2
37.35
47.67
59.68
72.66
BOM3
35.33
44.35
55.68
66.79
Chase4
36.31
48.80
65.58
83.07
Z-W5
41.75
50.48
59.58
70.36
Sources;
1) World Demand for Fertilizer Nutrients for Agriculture," Wharton Economic Forecasting
Associates (WEFA), #OFR 24-88, Bureau of Mines, April 1988.
2) "Current World Fertilizer Sitation and Outlook, 1985/86-1991/92," Food and Agricultural
Organization (FAO), United Nations, Rome, June 1987.
3) W.F. Stowasser, "Phosphate Rock," Minerals Facts and Problems. Bureau of Mines (BOM)
Bulletin 675, 1985.
4) Study by Chase Econometrics, cited in "Phosphates," General Accounting Office (GAO), #80-
21, November 1979.
5) Phosphate Rock 1985/86. Multiclient study by Zellars-Williams Co., Jacobs Engineering
Group, 1987.
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(see Table 9-15). The lower estimates reflect the fact that the developed market economies have
more mature agricultural industries and thus potential fertilizer gains are minimal. In addition, new
ideas for fertilizer application currently being implemented in these countries have resulted in
reduced fertilizer requirements.
Forecasters agree that demand for fertilizer in Western Europe will be stable or decreasing over the
next 20 years. These assessments are based on the maturation of the agriculture industry in these
countries, and more specifically on the expectation that Western European governments will
implement programs to reduce agricultural subsidies and stimulate a decline in crop acreage. On the
other hand, WEFA analysts note that a possible future shift from food grain to feed grain production
will stimulate phosphate fertilizer use [WH88J.
Analysts at Zellars-Williams estimate that population pressures and the pursuit of food self-
sufficiency policies in Asia will keep demand for phosphate fertilizers in that region growing at an
annual rate of about 3.4 percent at least until the year 2005. WEFA analysts estimate a lower 2.7
percent growth rate for the same time period. Their lower growth estimate reflects beliefs concerning
fertilizer use in Asia. WEFA analysts believe that Asian countries will experience diminishing returns
to fertilizer applications by 1995, leading to reduced fertilizer requirements in that region [WH88],
Most of the future demand for phosphate fertilizers in Africa will result from increased application
rates rather than increased acreage. Climatic conditions and destructive farming practices are likely
to continue to turn much African land into desert. WEFA projects that acreage in the region will
grow less than one percent per year [WH88],
All forecasters seem to agree that Latin America has tremendous potential for growth in agriculture
and fertilizer usage over the next 25 years. This optimistic assessment is based on the fact that
certain countries in the region are the lowest-cost producers of corn, soybeans and wheat, and hence
will be producing increasing shares of these major crops in the future, in addition, analysts expect
agriculture in the region to become more intensive. Agricultural policy will seek to meet production
targets by increasing yields rather than opening new lands for cultivation.
Thus, in general, most of the growth in demand will come from LDCs in Asia and Latin America.
Within Asia, most of the growth is expected to come from the People's Republic of China; in Latin
America, most of the growth is expected to come from Brazil and Mexico, although the debt and
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Tabl* 9-18: forecast# of Fertilizer Dwmd by Itagion and Swire#, 1995-2005
(HiUion Metric Tons P205)
1995 2000 2005 2010
REGION WEM ZW FAO WEFA 2U FAO (1) WEFA ZW WEFA
NORTH AMERICA 5.0 5.6 4.2 5.6 5.9 5.3 6.2 6.2 6.8
LATIN AMERICA 2.8 3.1 3.3 3.2 3.6 2.6 3.5 3.8 3.9
WESTERN EUROPE 4.9 6.6 5.2 4.9 7.0 4.8 7.5 4.8
AFRICA 3.6 3.5 0.8 1.5 2.3 0.5 1.6 2.5 1.7
ASIA 11.4 14.2 10.8 13.0 15.7 15.1 14.5 16.7 16.0
CHINA 6.8 3.4 7.8 12.0 8.3
OCEANIA 1.0 1.3 1.2 1.1 1.3 0.4 1.1 1.3 1.2
CENTRALLY PLANNED
ECONOMY 12.0 12.2 11.4 1.8 13.9 15.7 14.9
E. EUROPE 3.6 3.5 3.9 3.6 4.2 4.6 4.4
USSR 8.3 8.7 9.0 10.1 9.7 11.1 10.5
(1) Refers to 1997/98 (only).
Sources: "(torld Demand for Fertilizer Nutrients for Agriculture," UEFA, #OFR-24-88, far Bureau of
Nines, April 1988; Phosphate Rock 1985/86, Zellars-Uillia«s, 1987; "Current World Fertilizer
Situation and Out Look," Food and Agriculture Organization of the United Nations, June 1987.
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foreign exchange problems of both countries are expected to dampen import consumption and
encourage further investment in domestic capacity.
Most of the forecasts mentioned do not deal directly with U.S. exports. Zellars-Williams, however,
expects U.S. exports to increase until 1990 and to fall by almost 50 percent between 1990 and the year
2005 [Ze86j. This reflects the expectation that an increasing share of WPPA will be supplied by
LDCs. WEFA expects an average growth in exports of 2.0 percent per year until 1996 [WH88J.
Phosphate exports, according to the WEFA analysis, will constitute over half of the total identified
demand for U.S. produced phosphates over the forecast period. Thus, the outlook for the domestic
phosphate industry is unclear.
9.2.3 Other Issues
9.2.3.1 Substitutes
Besides phosphate ore, guano (igneous apatite and marine phosphorites) is the only significant source
of phosphorus. However, it is no real substitute for phosphate rock as a raw material for producing
phosphate fertilizers. Guano accounts for about 3 percent of world production of phosphate. All
large accumulations of guano were formed on the surface of the earth by seabxrds. The composition
of these deposits varies with the degree of leaching by surface waters. Chile holds most of the world
guano supply [St85j.
In some limited cases, phosphate rock can be used directly as a fertilizer, instead of first being
converted into phosphoric acid. According to Ed Harre at the National Fertilizer Development
Center, approximately a million tons of phosphate rock is used in this way each year around the
world, mostly in the Soviet Union. The rock must be finely ground and even then only a small
percent of the P2O5 can absorbed by the crops. The yield response is best in very acidic soils.
A potential substitute for the production of phosphoric acid is the production of nitrophosphate (NP)
fertilizers. In this process, nitric acid is substituted for sulfuric acid. NP is produced in Europe,
India and China but not in the U.S. One study estimates that sulfur prices would have to double, to
$200 per ton for the process to become economically attractive. In any case, environmental concerns
remain with NP. With NP, the radium in the phosphate rock is absorbed into the fertilizer instead
of remaining in the waste product [P187,P188]. Consequently, the radon emissions from the spreading
of the radium over millions of acres of farmland would certainly exceed the emissions from
phosphogypsum stacks.
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Spent acid from aluminum bright dipping is a substitute for WPPA in the manufacture of ammonium
phosphates only. The spent acid is recovered from aluminum bright-dip baths and may be used in
the production of fluid mixed fertilizers. This product is being used for this purpose in the midwest
and southeast, where most bright-dip plants are located. Its price per unit of PjOg is usually lower
than the price for WPPA. But the availability of this spent acid has been declining in recent years
as large U.S. bright-dipped aluminum alloy manufacturers have installed acid regeneration units in
their plants. Increased regeneration activity has been concurrent with the decision of auto
manufacturers to use less bright-dip trim on cars [SRI86].
Thermal phosphoric acid is also a substitute, but its production costs are much higher and the
production of thermal phosphoric acid presents other environmental problems.
9.2.3.2 Alternative Uses for Phosnhoevpsuin
Alternative uses for phosphogypsum attempt to exploit the material's two key properties: its physical
similarity to natural gypsum, and its sulfur and calcium content. Industrial and agricultural uses for
phosphogypsum are nothing new: research into sulfuric acid production from phosphogypsum started
at least as early as World War I [BSC85g]. Applications in building materials were common in Europe
until the 1950s and in the U.K. until the 1970s [BSC87f] and are still found in Asia [FIP88J. Below
is a review of the current uses of phosphogypsum and of the limited data available on radiation levels
from these uses.
Current Uses -- Alternative uses in the United States are fairly recent phenomena, and are a small
scale; one industry source estimates that only about 5 percent of U.S. phosphogypsum output is put
to use in some way [An88], The end of this section summarizes the information available on uses of
phosphogypsum by U.S. companies. By contrast, a 1981 study by a United Nations researcher
estimated that 14 percent of world phosphogypsum output was reprocessed [Ca88].
Most of the research in the U.S. has focused on two uses: the use of phosphogypsum as a road base,
usually mixed with other material, and processing of phosphogypsum into sulfuric acid and aggregate,
a solid material that can be used for a variety of construction purposes. Agricultural applications,
more common overseas, have been somewhat limited in the United States. Other uses for
phosphogypsum have been tried on a small scale but never widely adopted.
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Building Materials -- Much effort has been devoted to the development of methods which use
phosphogypsum as a construction material. Many of these are the same as uses for natural gypsum;
for example, plaster and wallboard. The use of phosphogypsum In building materials is hence
doubly attractive where natural gypsum is expensive or impossible to obtain locally and disposal of
phosphogypsum poses economic or environmental problems. For example, in Japan, where there are
no natural deposits of gypsum and land for dumping is scarce, the Nissan company has developed
and installed its own advanced phosphoric acid production technology to produce high-quality
byproduct gypsum.
There is no evidence that phosphogypsum straight from a stack is suitable for use in construction
materials. The phosphogypsum must be produced in a purer form than is usual in the U.S., and then
dried, or processed. It is then combined with some other substance (often flyash) and compacted to
make bricks, blocks or boards, or molded into piaster. Laboratory tests at the University of Miami
found that, depending on moisture content, compacted phosphogypsum can achieve compressive
strength as high as 1000 pounds or more per square inch [Ch87], Phosphoric acid plants in Austria,
Japan, and Belgium have been designed to produce as a byproduct high-quality phosphogypsum
specifically for construction purposes [Ca88|. Construction uses in Europe have become more
common as restrictions on dumping at sea have been imposed; at least one German firm sells
wallboard and other construction materials fashioned from phosphogypsum [LI85]. The Donau
Chemie Company in Austria has one 50,000 ton per year phosphoric acid plant where all of the
byproduct phosphogypsum is recycled into building materials ICa§8]. A technique for purifying
phosphogypsum to make it suitable for building materials has been patented by the American
company United States Gypsum but has never seen commercial usage [Mn88]. There is no evidence
that phosphogypsum has found a building materials market in America.
Road Base — Phosphogypsum is well-suited for use as a road bed. Either the aggregate from a
cement and acid process or unprocessed waste gypsum may be used. Unprocessed phosphogypsum
for use in road beds, mixed with flyash, cement, or other materials, has found an increasing but
limited market in America. Since July 1984, Mobil Mining and Minerals in Pasadena, Texas has
taken phosphogypsum from inactive stacks, mixed it with 6 percent cement, and sold it as "Gypsum
Aggregate." As of December 1986, over 300 projects utilizing a total of 340,000 tons of Mobil
phosphogypsum had been completed [FIP88], Mobil's Gypsum Aggregate has a number of other uses,
including railroad base and embankment construction. However, despite the good engineering
qualities of gypsum from phosphogypsum in this use, it is profitable to produce and sell as a road
base only where there is no natural local source for aggregate material because of high transportation
costs. Some of Mobil's success in this area is because the Houston area has few sources of aggregate.
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In Florida, some unknown number of private roads and parking lots have a phosphogypsum base;
but since they were built informally, little is knows about the details of their construction [L185],
Circular Grate Technology — The alternative use which has received the most attention in recent
years and which holds the most promise for the future concerns the processing of phosphogypsum
to produce sulfuric acid and a solid material, called aggregate. There are a number of techniques of
this type, generically referred to as "cement-acid processes." The most discussed technique for this
is known as the "circular grate process." The process can be varied to produce various forms of
aggregate appropriate for different applications [Ke86]. As mentioned, the production of sulfuric
acid from phosphogypsum dates back at least 50 years, but the high energy costs of earlier techniques
rendered them economically infeasible under most conditions. However, some recent studies indicate
that us'e of the circular grate process can lead to rates of return as high as 25 to 38 percent [Mc87c].
A pilot project at Freeport McMoRan's Uncle Sam plant in Louisiana, co-sponsored by the Florida
Institute of Phosphate Research and the Davy McK.ee Corporation, is expected to use 35 tons of
phosphogypsum and other inputs each day and produce 29 tons of sulfuric acid and 25 tons of
aggregate per day when it begins operation which is expected to be in early September of 1988
[Mc87c,LL88].
Where there is no nearby cement supply, other technologies can be profitable; for example, the
Fedmis Division of Sentrachem Ltd. in South Africa operates a 70,000 ton per year cement and acid
plant. Forty percent of Fedmis phosphogypsum output goes into profitable recycling. The Fedmis
example is unusual because reasonably priced cement is not available in the region surrounding the
Fedmis plant. Cement produced elsewhere and shipped to the area is not competitive because of the
high relative cost of transporting cement.
Strong demand for aggregate in Florida is expected to last for several decades, as the state's
population is forecast to increase to over 15 million by the year 2000 IDOC88c], With higher
population there will be a need for more roads. Most of the aggregate used to build roads in Florida
has to be brought in from outside the state; since many phosphate producers are located there, there
are some hopes in the phosphate industry that both the road and phosphogypsum problems may be
solved at once, using the circular grate technology [BSC87g], However, some sources in companies
not directly involved in the circular grate process are skeptical about this new technology. Several
people in the industry argue that low sulfur prices and high transportation costs for aggregate make
the technology unprofitable. Others doubt that it is technically feasible. However, it is estimated
that the circular grate process could produce sulfuric acid at a cost of $21.65 per short ton, compared
to $43.70 per short ton for the more traditional sulfur burning process [BSC8?h]. Iowa State
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University has developed a similar process using a fluid bed reactor rather than a circular grate, but
this approach has never left the test-plant stage [Mn88],
Agriculture — Phosphogypsum also has properties which make it potentially useful in agriculture.
As a fertilizer, it contains significant amounts of sulfur and calcium, both beneficial to growing
plants. According to Mike Lloyd of the Florida Institute for Phosphate Research, the sulfur content
is in a form usable by the soil directly, without any processing of the phosphogypsum. Of 18
American companies for which information is available, § currently sell some amount of
phosphogypsum for agricultural use; 3 have done so in the past but have stopped recently, usually
because the sales proved unprofitable. However, in all cases these sales have been small compared
to total phosphogypsum output, occasionally as much as 5 percent but often less than 1 percent of
total phosphogypsum produced by the firm. Application rates have been estimated as varying
between one half and 3 tons per acre, depending on locale and crop [Mc88].
There are two reasons why phosphogypsum is not used more for agricultural purposes. First, only
a limited number of crops benefit from phosphogypsum. Second, the potential profits from the
phosphogypsum are small relative to its bulk. Consequently, even at little or no cost for the material,
it is not profitable to transport phosphogypsum for long distances.
In other countries, phosphogypsum is used as a fertilizer. In India, the Gujarat State Fertilizer
Company has been making high-quality gypsum from phosphogypsum and also converting it into
ammonium sulfate fertilizer at a facility with 205-210 metric tons per day capacity [FIP88]. As a soil
additive, it can be used to remove aluminum toxicity [L188], It is also used to make clay and other
tough soils more porous, improving drainage [FIP88].
Sulfur Recovery — As the price of sulfur has risen, more research has focused on potential methods
of recovering the sulfur from phosphogypsum. A significant proportion of the energy and capital
costs in the acid-cement techniques goes into producing commercial-quality cement. This fact has
led at least one source to comment that the use of these techniques should be considered as cement
production rather than acid production [FIP88], Elemental sulfur can be produced via thermal
processing of gypsum (natural or byproduct). Due to energy and capital costs, this technique has been
feasible only when the supply of sulfur is extremely limited—for example, it has been used abroad
when wartime blockades or government import controls have cut sulphur supplies [L185], The British
Sulphur Corporation has speculated that environmental considerations may lead to more thermal
processing of waste gypsum to yield elemental sulfur, even when it is not "strictly profitable
[BSeS7g]."
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Radiation Considerations -- A few studies of radon and radioactivity hazards in alternative uses of
phosphogypsum have been completed. One University of Florida study of agricultural applications
estimated the radionuclide uptake by plants, the resultant concentration in food, and the subsequent
doses to consumers, for applications of one ton of phosphogypsum per acre every four years. The
study claimed to find no significant radiological problems implied for horizons of up to 50 years
[FIP88],
University of Miami engineering professor Wen F. Chang claims that radon emissions from
phosphogypsum are greatly reduced when it is compacted (to make bricks, for example). He
estimates that emissions can be reduced 80 to 95 percent compared to the powder form, depending
on the force of compression [Ch88],
Two experiments have measured radon concentration in enclosed rooms fashioned from
phosphogypsum panels [FIP88], The first study was conducted by researchers from the University
of Miami and Jacobs Engineering, the second by a University of Miami professor. In each study,
the 'worst case' was examined: the rooms were windowless and ventless and constructed entirely from
the wallboard. In addition, the wallboard was painted on the outside of the room to minimize the
escape of radon gas. In both cases, radon concentration in the structure approached or was as high
as (EPA or Florida state) screening levels. In addition, the former study measured radon emissions
when the panels were painted on the surface facing the inside of the room and found that emissions
were reduced by 95 percent. Wen F. Chang, the University of Miami professor who performed the
second experiment, claims that painting the phosphogypsum panels reduces emissions to negligible
levels, and that the materials he has produced experimentally will pass any building code [Ch88J.
Little data on radon emissions in roadbase use is currently available, although a University of Miami
study has examined the impact of a phosphogypsum roadbase in Poik County, Florida on local
groundwater quality [FIP88], Neil Anderson, venture manager of the phosphogypsum project at
Mobil Mining and Minerals, claims that radon emissions from an installed phosphogypsum roadbase
of Mobil Gypsum Aggregate (without an intact covering such as asphalt) are 1 to 2 picoCuries per
square meter per second, and when the roadbase has an intact covering the emissions are essentially
none [An88]. However, such coverings almost always develop cracks which allow disproportionate
amounts of gas to escape. Mr. Anderson states that a hydration reaction takes place when the
phosphogypsum is mixed with cement, reducing the radon emissions. The following section
summarizes alternative uses of phosphogypsum by various companies.
9-5?
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Specific Uses Of Phosphogypsum bv U.S. Companies
Allied -- A small amount of phosphogypsum is sold from a plant in Geismar, Louisiana for
agricultural use on sugarcane. The volume sold is far less than one percent of output, estimated at
5000 tons out of a total production of 750,000 tons per year. The farmers are not charged for the
material itself, only for loading. Demand for phosphogypsum is erratic.
C F Industries — The company previously sold phosphogypsum from its Florida operations to peanut
farms in Georgia, but has not sold any since its plant shut down about five years ago.
Farmland — Farmland operates wet-process phosphoric acid facilities in southern Florida. Some
amounts are shipped for agricultural use, estimated to involve 0.2 percent or less of annual output,
between 0 and 5000 tons per year. It is generally used as a sulfur source on peanut fields in Georgia.
Four Court Incorporated — Eight million tons are stockpiled in the Utah plant which the company
bought from Chevron. Each year, 200,000 tons are shipped to the San Joaquin Valley in California
for use as a soil conditioner for sodic soils. According to Ed Sepehrenik, FCI engineer, California
demands a total of 750,000 tons per year from various sources. There is also some agricultural use
in Montana. A process which Mr. Sepehrenik designed himself and which is still in the experimental
stage produces sulfuric acid and an animal feed supplement; the latter can be sold for $450 per ton,
Gardinier — Gardinier operates one wet-process phosphoric acid plant, in Tampa, Florida. The
company had some agricultural sales of phosphogypsum in previous years, although not recently since
it is not profitable to sell. Gardinier has stockpiled phosphogypsum at rates up to 4 million tons per
year for the last 50 years.
Mobil Mining and Minerals -- Mobil operates a wet-process phosphoric acid plant in Pasadena,
Texas. The company previously sold phosphogypsum off the stack for agricultural use, and is
currently waiting for its license permitting this practice to be renewed by the Texas State Health
Department. The phosphogypsum was used as fertilizer for its calcium and sulfur and to condition
sodic soils. Mobil currently sells about 10-15 percent of its phosphogypsum output and hopes to sell
more in the future. As described above, Mobil also has been aggressive in developing a road building
market for phosphogypsum.
Occidental — The company owns one WPPA facility, in White Springs, Florida. Occidental sells
about 100,000 tons a year of straight phosphogypsum for agricultural use, less than 1 percent of total
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output. Markets are Georgia, Alabama, North Carolina, South Carolina, Texas, and Virginia. Peanut
farmers are most interested since phosphogypsum is especially suited for that crop.
Rovster -- Very little of its phosphogypsum goes to agricultural uses, less than 1 percent.
Simolot — The company has closed 2 plants in California, one in 1982, the other more recently. The
last of the phosphogypsum from those plants was shipped out recently. It had previously sold about
300.000 tons per year from plants in California. Its Pocatello, Idaho, plant currently sells much less,
about 40,000 to 50,000 tons per year, 3 to 4 percent of output. In Idaho, phosphogypsum is typically
used on alfalfa, onions, and potatoes; the usual application rate is about one half ton per acre. In
California, it is used on irrigated field crops, cotton, grain, wheat, beets, and alfalfa, with an
application rate of about 1 to 3 tons per acre. The only processing of phosphogypsum undertaken
is 'diking' to bring moisture to around 12 percent. Price runs about 12 dollars per ton loaded onto
trucks, and as much as 35 dollars per ton delivered to farm. According to Jim McGinnis, Distribution
Manager, use in Idaho will probably increase a little; it is expected that some may be shipped to
California.
Texaseulf -- The company operates one WPPA plant in Lee Creek, North Carolina. About 100,000
to 150,000 tons of phosphogypsum per year is used as peanut fertilizer in North Carolina and
Virginia, from a total of 5 to 6 million tons of phosphogypsum produced per year; phosphogypsum
is also blended with clay separated from phosphate rock and used to reclaim mine land. The
company's ultimate goal is to return all its phosphogypsum to the land in this way.
9.3 Current Emissions. Risk Levels and Feasible Control Methods
9.3.1 Introduction
The phosphate fertilizer industry described in section 9.2 is the subject of possible environmental
controls. These controls would reduce the incidence of lung cancer attributable to radon emissions
from the phosphogypsum stacks associated with the production of P2Og. One or more of these stacks
are located at most P2Os production facilities. Nationally, fifty-eight stacks have been identified.
The analyses in this and the following sections of this chapter (9.4 through 9.6) consider the costs,
magnitudes and effects on the risks of lung cancer of radon emission reductions, their benefits in
relation to their costs, their effects on economic activity in the United States and on the well-being
of small entities.
9-59
-------
Because the parameters affecting the radon emissions from all these stacks are not available and
because economic data is available for P205 producers linked to only a subset of the stacks, detailed
economic analysis is done for fourteen of the fifty-eight stacks. Details of the selection of the
fourteen appear in section 9,5.
9.3,2 Physical Attributes of Phosphogypstim Stacks
9.3.2.1 Design and Construction
Phosphogypsum is created when phosphate rock and sulfuric acid are combined to produce P205.
The amount of phosphogypsum produced is approximately five times that of the P2Os produced. For
disposal, the phosphogypsum is carried by a slurry and deposited on large piles known as stacks.
The stacks are large. Their bases range from 2 hectares to 284" hectares and some currently reach a
height of 50 meters. The quantity of phosphogypsum deposited in a stack in a year may reach
1,550,000 metric tons.
While the stacks are irregular in shape, they roughly resemble a rectangular box, with sloping sides.
While the sides of most stacks are sloped with one vertical meter for every three horizontal meter,
stacks in Louisiana and Mississippi have a more gradual slope, about one in eight. (Table 9-16) For
the purpose of modeling, it is also assumed that the length of the base of a stack is twice its width.
The tops of the stacks are constantly changing as a slurry of phosphogypsum is deposited first on one
segment, and then on another, of the tops. A road around the top and dikes to contain the new
deposits of phosphogypsum are frequently rebuilt to accommodate the changing dimensions of the
sides and top. When one section of the top is filled, it is allowed to dry and the flow of slurry is
diverted to another section. Much of the top is under water at any time, not only while the slurry
is settling, but also because portions of the tops are used for water storage as part of the waste water
management plan for the production facility.
9.3.2.2. Radon Emissions from Uncontrolled Stacks
Radon emissions from uncontrolled stacks depend on the flux, or rate of release of radon from the
phosphogypsum in the various portions of a stack, and on the areas of these portions. Radon flux
from the sides differs from the fluxes from the top. On top, the portions that are under water have
9-60
-------
>-16
: #
:sss
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
IS
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
Stack Parameters
HEIGHT BASE AREA SLOPE CAPACITY
(meters) (hectares) (1/entry) (1000 KT/yr) REGION STATUS
sssassaaassssssss
ssass
ssssssss
sssss:
rssssssss
10
9
3
3
Inactive
24
18
3
115
3
Open
18
20
3
430
3
Idle
18
30
3
115
3
Open
27
31
3
90
3
Open
10
32
3
90
3
Open
20
40
3
340
3
Open
22
40
3
340
3
Open
9
40
3
0
3
Idle
9
50
3
0
3
Idle
18
53
3
340
2
Open
23
61
3
430
3
Open
6
64
3
140
3
Open
20
92
3
520
3
Open
21
121
3
170
3
Open
54
138
3
650
3
Open
40
146
3
630
3
Open
21
140
3
380
3
Open
28
162
3
760
3
Open
12
164
3
140
3
Open
24
157
3
1550
3
Open
12
17
3
320
1
Idle
24
36
3
280
1
Open
18
81
3
320
1
Open
9
7
3
3
Idle
5
10
3
110
3
Idle
18
10
3
3
Idle
9
18
3
3
Inactive
4
28
3
3
Inactive
16
32
3
3
Idle
13
40
3
110
3
Open
27
77
3
110
3
Open
9
20
3
3
Idle
30
20
3
3
Idle
5
24
3
3
Idle
4
9
5
420
3
Open
10
9
5
160
3
Open
14
11
5
0
3
Idle
27
14
5
0
3
Idle
27
38
3
0
3
Idle
12
203
8
420
3
Open
20
284
8
800
3
Open
20
101
10
220
3
Open
10
0
3
3
Idle
10
20
3
3
Idle
15
28
3
3
Idle
10
20
3
383
2
Open
10
29
3
383
2
Open
10
97
3
383
2
Open
3
2
3
3
Idle
11
11
3
3
Inactive
11
14
3
3
Idle
27
14
3
3
Idle
27
24
3
220
3
Inactive
27
36
3
220
3
Idle
30
61
3
220
3
Open
5
121
3
90
1
Open
10
182
3
180
1
Open
een representative stacks selected for further study.
9-01
-------
no flux while the dry portions and the roads- have differing fluxes. Since roads, dikes, and
underwater portions of the top are in relatively constant ratios to each other as the stack grows,
weighted averages of the fluxes oa the top can be computed for each geographical region. This is
the value used in computations of total radon emissions from the tops of the stacks. Radon emissions
for a stack equal the sum of the products of its top and sides and its flux rates.
Radon flux also depends on the composition of the phosphate rock that went into the P205 production
and on the rainfall of the region. Flux rates were developed for three regions of the nation. Region
one contains Idaho, Utah, and Wyoming; region two is North Carolina and northern Florida; and
region three is the rest of the United States. (Table 9-17)
Calculations of radon emissions from each stack considered were done using a computer model that
first computes the areas of the sides and top of each stack, and then its radon emissions as it grows,
and areas and emissions of each stack after they reach their full sizes and are closed. Table 9-18
shows the total, uncontrolled, current emissions for each stack as calculated by the model.
9.3.2.3 Risks Due to Uncontrolled Stacks
The emissions shown in Table 9-18 result in some risk of lung cancer to the population. Two kinds
of risk were considered, risk to the individual most exposed to each stack and risk to the population
within an 80 km radius of each stack. These risks were calculated for each stack individually based
on its emissions by running the AIRDOS-EPA computer code. The results of these runs for the
fourteen stacks are also shown in Table 9-18.
9.3.3 Feasible Control Methods
9.3.3.1 Description of Controls
The primary control technique considered for the reduction of radon emissions from phosphogypsum
stacks is to cover the stacks with a layer of dirt. To meet a given standard a sufficient thickness of
dirt must be used. The thickness of dirt needed depends on the desired standard, the radon flux rate
from the stack, and the properties of the dirt used. The major option available is whether to add dirt
on the sides while the stack is in operation or wait until it is closed. The top can only be covered
after the stack is closed.
9-62
-------
Table 9-17: Radon Flux
Rates by Regional Group
(pCi/m2/s)
GROUP 1
Idaho, Utah, Wyoming
flux from:
TOP SIDES
uhlle
OPERATING 4.5 14.0
CLOSED 7.3 9.5
GROUP 2
North Carolina and Northern Florida
flux from:
TOP SIDES
while
OPERATING 1.5 3.0
CLOSED 1.0 2.0
GROUP 3
All other states
flux from;
TOP SIDES
whi le
OPERATING 4.0 9.0
CLOSED 4.0 12.0
9-63
-------
Table 9-18: incremental Cancer Risks Associated with Exposure
lo Radon Emitted from Phosphogysum Stacks with
Ho Controls
MAXIMUM
STACK #
LIFETIME
COMMITTED
FROM
RM-222
FATAL
FATAL
TABLE
EMISSIONS
CANCER
CANCERS/YR
STACK #
9-16
STATE
(Ci/yr)
RISK
<0-80 km)
It
31
»
II
K
If
K
SS5SSBSSS
sasssssrssss
SSaaKK«====™
issssstessss
SSSSSBSSSKS!
l
5
Florida
61
1E-0S
6E-Q2
2
6
Florida
50
1E-05
7E-03
3
11
Florida
20
5E-06
1E-03
4
14
Florida
150
4E-05
1E-02
5
18
Florida
218
11-05
2E-02
6
19
Florida
263
6E-05
3E-02
7
21
Florida
279
2E-05
3E-02
8
22
Idaho
39
9E-Q&
9E-04
9
31
Illinois
64
4E-05
3E-03
10
36
Louisiana
16
1E-06
9E-04
11
42
Louisiana
486
7E-05
3E-02
12
54
Texas
47
7E-05
9E-02
13
55
Texas
67
81-05
1E-01
14
56
Texas
113
9E-05
1E-01
sssssssss
as S 2TS2 — £ S SJ3S SS S
sssSSS=====:
II
It
II
it
ll
li
fl
ll
H
II
11
fl
I
If
!!
II
II
II
II
9-64
-------
The computer model used to analyze the control alternatives provides three scenarios. Scenario i is
to cover the sides while the stack is in operation and the top when it is closed, scenario 2 is to cover
the sides and top when the stack is closed, and scenario 3 is to do nothing. The model also allows
flux standards to be set at any level. These levels are considered: 20 pCi/m2/sec, 6 pCi/m2/sec, and
2 pCi/m2/sec.
Since all stacks already have radon fluxes of less than 20 pCi/m2/sec, only the latter two fluxes were
analyzed. The model calculates a thickness of dirt based on the highest flux rate from any portion
(top or sides) of the stack at any time. Runs were made for the following four combinations:
1, flux standard = 6 pCi/m2/sec and scenario = 1
2. flux standard = 6 pCi/m2/sec and scenario = 2
3. flux standard = 2 pCi/m2/see and scenario = I
4, flux standard = 2 pCi/m2/sec and scenario = 2
In the model, the ratio of the covered to uncovered flux (R) is computed for each stack and flux
standard. Thickness is then found from equation (1).
(1) R = exp(-B * thickness)
where
B is a property of the soil cover, and
R is the ratio of controlled flux to uncontrolled flux
Table 9-19 shows the ratios and thicknesses of dirt for flux standards of 6 pCi/m2/sec and
2pCi/m2/sec The thickness of dirt applied to most portions of each stack in each situation is greater
than is needed to meet the flux standard. The exact emission change resulting from the actual
amount of dirt applied is calculated. These emission reductions are greater than required to meet
the stated standard. However, the convenience of applying a uniform thickness of dirt to an entire
stack was considered to offset the savings of adjusting the amount of dirt used on each portion of
the stack in each situation. In particular, it was not contemplated that dirt would be removed from
the sides of a stack after it was closed in cases where the sides of a closed stack have a lower radon
flux rate than those of an open stack.
To cover the stacks, various preparations must be made and specific steps followed. First drains must
be laid on the stack. The drains prevent acidic water from seeping from the stack and killing the
ground cover. Vertical drains are installed every 30 meters around the base and slant upward to a
spacing at the top proportional to the spacing at the bottom. A peripheral drain is installed every ten
9-65
-------
Table 9-19; Control Parameters for Representative Stacks
STACK #
FROM
STD=6
STD=2
TABLE
i-
— — — -I I
I
STACK #
9-16
STATS
"B"
RATIO THICKNESS
RATIO THICKNESS
========:
ISSSSSSSS
It
II
II
II
II
II
11
u
II
II
II
II
II
II
II
II
II
1
II
«
II
!i
II
II
II
II
»
II
it
1
5
Florida
1.80
0.400 0.51
0,133 t.12
2
6
Florida
1.80
0.400 0.51
0.133 1.12
3
11
Florida
1.80
0.400 0.51
0.133 1.12
4
14
Florida
1.70
0.401 0.54
0.133 1.19
5
18
Florida
1.80
0.400 0.51
0.133 1.12
6
19
Florida
1.70
0.401 0.54
0.133 1.19
7
21
Florida
1.70
0.401 0.54
0.133 1.19
8
22
Idaho
0.83
0.429 1.02
0.143 2.34
9
31
Illinois
1.30
0.400 0.71
0.133 1.55
10
36
Louisiana
2.30
0.400 0.40
0.133 0.88
11
42
Louisiana
2.20
0.400 0.42
0.133 0.92
12
54
Texas
1.70
0.401 0.54
0.133 1.19
13
55
Texas
1.70
0.401 0.54
0.133 1.19
14
56
Texas
1.70
0.401 0.54
0.133 1.19
Where:
RATIO = the ratio of radon flux (pC/m*2-sec) from a covered surface to
that from an uncovered surface and is given by:
R = exp(-BX).
THICKNESS = soil thickness on the stack {given above in meters).
8 = an empirically estimated coefficient that is a function of soil
moisture content {described in the text of this report).
STD=6 = the flux standard that allows 6 pCi/m*2-sec»
STD=2 s the flux standard that allows 2 pCi/mA2-sec.
9-66
-------
meters of vertical height and connected to the vertical drains. If the entire stack is covered at
closure, as in scenario two, then all drains are installed simultaneously. But if the stack is covered
during operation, then vertical drains are installed continuously as the stack progresses and peripheral
drains are installed each time the stack grows ten meters in height.
Once the drains are in place, dirt is hauled to the site, placed on the stack, graded and compacted.
The dirt is then seeded with grass. The grass and drains require annual maintenance. Dirt is assumed
to be added every time the stack grows 3 meters in height. Before the top is covered, a synthetic
cover is placed over it. Then dirt is hauled, placed, graded and compacted over the cover and grass
is planted and maintained. No drains are installed on the top.
If the regulations required scenario one, covering the sides as the stack grows, existing stacks would
have to install drains, cover their sides and plant grass right away. The program closes operating
stacks when their tops get too small to accommodate more slurry. The minimum size needed for the
top depends on the level of activity. If a large amount of P205 is being produced, a large top is
needed. The stack is closed when the area of the top in square meters is less than .32 times the
amount of P2Os produced per year measured in metric tons.
9.3.3.2 Costs of Controls
Costs of controlling radon emissions were computed by the Basic model for each of the fourteen
stacks and for each of the four combinations of flux standards and scenarios. In computing the costs,
the following cost items were included from the Appendix to Volume 2:
dirt costs
purchase price of dirt
haulage costs of dirt
grading and placement of dirt
ITEM
COST
$22.56 per cubic meter
seeding costs
peripheral drains
downspouts
maintenance
synthetic cover for top
$0.62 per square meter
$27.62 per meter
$27.62 per meter
$0.29 per square meter
$1.70 per square meter
9-67
-------
The distribution of costs over time depends on the scenario. For scenario one, the initial year
includes expenditures for installing downspouts, dirt and grass on the existing sides. If the stack has
reached significant height, the first year's activities are of major scale. The following years all
include maintenance costs that are a function of the amount of grass and drains in place as well as
the cost of adding vertical drains and covering the newly developed sides. Every ten vertical meters,
i.e., every two or three years, depending on the geometry of the stack and the rate of deposit of
phosphogypsum, costs are incurred for the installation of peripheral drains. When the stack is closed,
all costs for covering and seeding the top are incurred in that year. For scenario two, cover top and
sides in the closure year, all costs for drains, cover, and seeding for the whole stack are incurred in
a single year. Once the stack is closed, there is only an annual maintenance cost.
The only costs of control that increase as standards are made more stringent are those that are
associated with the volume of dirt needed for coverage. All the costs of laying pipe, seeding and
cover and drain maintenance are dependent on the geometry of the stack only and are incurred in
any case in which control activity is required.
Appendix A to Chapter 9 lists the emission reductions and costs of attaining them by applying
controls to the fourteen stacks. The costs, emissions after controls, and emission reductions are stated
year by year for each of the fifty years, except that once the stack is closed the only cost is
maintenance which is constant for the rest of the period. Showing each year's cost allows the pattern
of costs and emission reductions to become apparent.
9.3.3.3 Emission Reductions Due to Controls
Reductions of radon emissions for each stack were computed by the computer program. For
example, if the sides of a stack were covered with a thickness of dirt, then the R value associated
with that thickness was multiplied by the product of the flux rate and area of the sides. If the sides
were not covered, then emissions equal the product of the flux rate and the area of the sides. As
stated above, the emission reductions from each stack over the fifty years considered will be larger
than the minimum amount needed to just meet the standard.
The major difference between scenario 2 and scenario 1 is that in scenario 2, the sides are not
covered while the stack is in operation. This does not reduce the monetary cost of coverage, but it
does delay certain expenditures, sometimes for years, and there is no maintenance cost for those
years. With regard to emissions under scenario 2 there is no emission reduction until the stack is
closed. Again, this delay is often for many years. Differences with respect to standards are that the
9-68
-------
maximum allowable flux rates are cut by two thirds, to 2pCi/mz/sec but the amount of dirt needed
is just over twice as much.
9-3.3.4 Reduction of Risk Due to Controls
The benefit of the reduction in radon emissions is the reduction in the risk of lung cancer due to the
emissions. Table 9-20 shows the reduction in risk to the most exposed individual and Table 9-21
shows the reduction in risk to the population within 80 km of each stack. Even though there are
numerous technical details involved in measuring the exposures of the population and of the most
exposed individual, including running the AIR-DOS computer code, these risks vary approximately
in proportion to the emission rate from the stack in question. A single run of AIR-DOS was done
using the initial emission levels. Changes in risk are computed using the proportional relationship.
Therefore the reduction in allowable flux rates to 2 pCi/m2/sec will reduce cancer rates to one third
their level if the rate were 6 pCi/m2/sec.
In computing the changes in risk to the population, the current emissions were assumed to continue
for fifty years and the emissions with controls in place over those fifty years were totaled. The ratio
of controlled to uncontrolled emissions was then computed and applied to the initial risks levels. In
computing the changes in risk to the most exposed individual, the current emissions were distributed
over seventy years, and seventy years of controlled emissions were totaled. The ratios of these values
were used to compute the new risk levels.
9.4 Analysis of Benefits and Costs
9.4.1 Introduction
In this section the costs, emission reductions, and risk reductions are analyzed with respect to four
combinations of scenarios and standard to establish their relative costs and benefits.
9.4.2 Least-Cost Control Technologies for Affected Plants
The options under consideration are to control to 20 pCi/m2/sec, 6 pCi/m2/sec, or 2 pCi/m2/sec
Control to 20 pCi/m2/sec is based on risk levels for other industries, and the lower levels are studied
to determine if a tighter standard is justified on economic grounds. The decision to require further
control depends on the benefits, costs, and other considerations discussed below. In this section,
cost of reduction of radon emissions from each stack per time period is the primary measure of
9-69
-------
Table 9-20: Reduction in Risk to the Most Exposed Individual
MAX IHUH LIFETIME FATAL CANCER RISK
STACK #
I --
1
FROM
WITH CONTROLS (STD
,SCNRO)
REDUCTIONS (STD.SCNRO)
TABLE
tin i
NU J
STACK #
9-16
STATE
CONTROLS
2,1
2,2
M
6,2
2,1
2,2
6,1
6,1
II
H
II
li
!!
II
II
XttSgSSSSiSSS
3KSSSSSSSS
s^ssssssas
ssssssssasss
ssssssssss:
1
5
Florida
IE-OS
2.Q1E-06
2.11E-06
5.98E-06
6.05E-06
86-06
8E-06
4E-06
46-96
2
6
Florida
16-05
2.45E-06
2.966-06
6.41E-06
6.76E-06
8E-06
7E-06
4E-06
3E-06
3
11
florida
5E-06
6.67E-07
6.67E-07
2.00E-06
2.00E-06
4E-06
4E-06
36-06
3E-06
4
14
Florida
4E-05
6.84E-06
7.07E-06
1.99E-05
2.01E-05
3E-05
3E-05
2E-05
2E-0S
S
18
florida
tE-05
3.07E-06
4.36E-06
6.69E-06
7.59E-06
7E-06
6E-06
SE-06
2E-06
&
19
florida
6E-05
1.02E-05
1.06E-05
2,986-05
3.01E-05
5E-05
5E-05
31-05
3E-05
7
Z1
florida
2E-05
2.67E-06
2.67E-06
8.00E-06
8.00E-06
26-05
2E-05
16-05
1E-65
8
22
Idaho
9E-06
1.29E-06
1.29E-06
3.86E-Q6
3.86E-06
8E-06
8E-06
56*06
5E-06
9
31
Illinois
4E-05
9.63E-06
1.17E-05
2.53E-05
2.68E-05
3E-05
3E-05
1E-05
1E-GS
10
36
Louisiana
ie-06
1.33E-07
1.33E-07
4.0QE-07
4.00E-07
9E-07
9E-07
6e.07
61-OF
11
42
Louisiana
7E-Q5
1.77E-05
2.25E-05
4.33E-05
4.67E-05
5E-05
5E-05
36-05
2E-05
12
54
Texas
7E-05
2.19E-05
7.00E-05
3.67E-05
7.00E-05
5E-05
4E-11
36-08
46-11
13
55
TeKBS
BE-05
3.QBE-05
8.00E-05
4.59E-05
8.00E-05
5E-05
OE*00
3E-05
OE*O0
14
56
lenm
9E-05
1.72E-Q5
1.80E-05
5.09E-05
5.14E-05
71-05
7E-05
4E-05
41-05
«
3
-------
Table 9-21: Reduction In Risk to Population within 80 km. of Stack
STACK §
FROM
TABLE
STACK #
9-16
1
5
2
6
3
11
4
14
5
18
6
19
7
21
8
22
9
31
10
36
11
42
12
54
13
55
14
56
COMMITTED FATAL CANCERS/YR (0-80 Ion)
STATE
NO |-
CONTROLS
WITH CONTROLS (STD.SCNRO)
2,1
2,2
6,1
6,2
REDUCTIONS (STD.SCMRO)
2,1 2,2 6,1 6,2'
Florida
Florida
Florida
Florida
Florida
Florida
Florida
Idaho
Illinois
Louisiana
Louisiana
Texas
Texas
Texas
.0E-03
.01-03
.0E-03
.OE-02
•0E-02
.0E-02
.0E-02
•0E-04
.0E-03
,06-04
.0E-02
.0E-02
.0E-01
.0E-01
1.21E-
1.81E-
1.33E-
1.736-
6.85E-
5.20E-
4.00E-
1.29E
7.61E-
1.2QE
8.18E
2.82E
3.85E'
1.93E
03 1.29E-
03 2.31E-
04 1.33E-
03 1.82E-
03 1.05E-
03 5.44E-
03 4.00E-
04 1.29E-
04 9.81E
04 1.20E
03 1.11E
02 9.00E'
02 1.00E
02 2.05E
03 3,
03 4,
04 4,
03 4.
02 1.
03 1.
03 1,
04 3.
04 1,
04 3.
02 1,
02 4,
01 5
02 5
59E-03
51E-03
OOE-04
99E-03
35E-02
49E-02
20E-02
86E-04
91E-03
60E-04
87E-02
72E-02
74E-02
65E-02
64E-03
85E-03
00E-04
05E-03
60E-02
1.51E-02
.20E-02
.86E-04
.06E-03
3.60E-04
2.08E-02
9.00E-02
1.00E-01
5.74E-02
4.8E-03
5.2E-03
8.7E-04
8.3E-03
1.3E-02
2.5E-02
2.6E-02
7.7E-04
2.2E-03
7.8E-04
2.2E-02
6.2E-02
6.2E-02
8.1E-02
4.7E-03
4.7E-03
8.7E-04
8.2E-03
9.5E-03
2.5E-02
2.6E-02
7.7E-04
2.0E-03
7.8E-04
1.9E-02
0.0E+00
Q.0E+00
8.0E-02
2.4E-03
2.5E-03
6.0E-04
5.0E-03
6.5E-03
5E-02
8E-02
1E-04
1E-03
.4E-04
1E-02
JE-02
4.3E-02
4.3E-02
2.4E-03
2.1E-03
6.0E-04
5.0E-03
4.0E-03
1.5E-02
1.8E-02
5.1E-04
9.4E-04
5.4E-04
9.2E-03
0.0E+00
O.OE+OO
4.3E-02
(p
-a
sura
avg
max
mirt
4.3E-01 1.16E-01 2.48E-01 2.36E-01 3.28E-01
3.IE-02 8.29E-03 1.77E-02 1.69E-02 2.34E-02
1.0E-01 3.85E-02 1.00E-01 5.74E-02 1.00E-01
9.0E-04 1.20E-04 1.20E-04 3.606-04 3.60E-Q4
3.1E-01 1.8E-01
2.2E-02 1.3E-02
8.1E-02 8.0E-02
7.7E-04 O.OE+OO
1.9E-01 1.0E-01
1.4E-02 7.2E-03
4.3E-02 4.3E-02
5.1E-04 O.OE+OO
-------
effectiveness. Since no portion of any stack has a flux rate of more than 15,0 pCi/'m2/sec., well
under the 20 pCi/m2/sec limit, the choice is between 2 pCi/m2/sec, 6 pCi/m2/sec. or no control.
Control costs and emission reductions for each stack under each standard are computed in the model.
There are two scenarios to consider. The sides can be covered with dirt while the stack is operating
and the top covered when the stack is closed (scenario 1), or the whole stack can be covered at closure
of the stack (scenario 2). Table 9-22 shows the total emission reductions and cumulative discounted
costs due to the emission reductions under each scenario and standard, for each stack and for all
stacks taken together.
9.4.3. Health Benefits of Controlling Radon Emissions
Lung cancer rates are directly related to radon emissions. The issue is the size of the risks of lung
cancer posed by phosphogypsum stacks and the reduction of the risk that will result from the control
chosen. The AIRDOS computer code was run based on current estimates of emissions from the
stacks. Two measures of risk were then calculated for each stack:
1. The risk to most exposed individual, usually one living near the base of a stack,
measured as the number of chances per one million trials. This measure assumes the
most exposed individual remains subject to the estimated radiation level for seventy
years.
2. The probability that the general population will get cancer due to the stack's
emissions, measured as the number of cases per one million persons. This measure
considers the effects of one year of emissions on the population located within 80
km of each stack. The rule of thumb for estimating the risk to the entire U.S. is to
double the risk to the 80 km population.
In cases where individuals may live within 80 km of more than one stack, the risk to the most
exposed individual, shown in Table 9-20, was based upon only the closest stack. Risks to the 80 km
populations were summed over all fourteen stacks. These are shown in Table 9-21.
9.4.4 Health Benefits and Cost Estimates
The greatest aggregate reduction in the risk of cancer in the 80 km region is obtained by setting the
flux rate at 2 pCi/m2/sec and requiring the sides of the stacks to be covered continuously as the stack
grows (scenario one). The second greatest aggregate reduction is obtained with a flux rate of 6
pCi/m2/sec and scenario one. Scenario two does not control emissions as effectively as scenario one
primarily because several idle stacks will not grow to their maximum size (at least as long as they
9-72
-------
TABLE 9-22; EFFECTIVENESS OF CONTROLS CSummed Over 50 Years)
STACK #
STACK 0
FROM
TABLE
9-16
t
5
2
6
3
11
4
14
5
18
6
19
7
21
a
22
9
31
10
36
11
42
12
54
13
55
14
56
CUMULATIVE REDUCTIONS IN EMISSIONS DUE TO CONTROLS
DIFFERENT STANDARDS, SCENARIO COMBINATIONS
Florida
Florida
Florida
Florida
Florida
Florida
Florida
Idaho
Illinois
Louisiana
Louisiana
Texas
Texas
Texas
sum
max
rain
Ci
Ci
Ci
Ci
sss—-eestxass
^sssa»a=ss5s£
========^====
II
II
II
If
II
II
I
II
3.2E+03
3.2E+G3
1.9E+03
1.9E+03
2.8E+03
2.6E+Q3
1.711-03
1.6E+03
4.6E+02
4.6E+02
4.6E+02
4.6E+02
7.26+03
7.2E+03
4.3E+03
4.3E+03
1.1E+04
9.4E+03
6.6E+03
5.7E+03
1.3E+04
1.3E+04
7.6E+03
7.6E+03
1.2E+04
1.2E+04
7.0E+03
7.0E+03
1.1E+03
O.OE+OO
7.3E+02
0.0E+00
3.5E+03
3.3E+03
2.1E+03
2.0E+03
6.8E+02
6.8E+02
4.4E+02
4.4E+02
5.4E+02
1.1E-02
3.46+02
1.1E-02
1.66+03
0.0E+00
9.71+02
0.0E+00
2,11*03
0.0E+0Q
1.2E+03
0.0E+00
5.8E+03
5.7E+03
3.5E+03
3.4E+03
=============
II
II
II
II
II
)l
I
II
11
H
6.4E+04
5.7E+04
3.9E+04
3.4E+04
1.31+04
1.31+04
7.6E+03
7.6E+03
4.6E+Q2
0.0E+QQ
3.4E+02
0.0E+00
!
II
II
II
It
11
II
==============
sssss==rsss==
li
II
II
11
il
II
tf-73
-------
TABLE 9-22: EFFECTIVENESS OF CONTROLS (Sunmed Over 50 Years)
(Continued)
STACK #
FROM
TABU;
STACK #
9-16
11
!»
11
I
»
II
II
11
II
It
It
It
It
II
II
II
it
1
5
2
6
3
11
4
14
5
18
6
19
7
21
8
22
9
31
10
36
11
42
12
54
13
55
14
56
K
If
II
It
II
II
II
1!
II
II
li
I
II
II
II
II
II
Total Cost
avg
max
min
:SS2=2SSSSS
it
IS
ii
»
it
n
CUMULATIVE cost of emission reductions in npv
DIFFERENT STANDARDS, SCENARIO COMBINATIONS
(discount rate = 0)
STD=2*SCNR(^1 ST0-2,SCMR0=2 STD=6,SCNR0»1 STD=6,SCNR0=2_
$10,216,062
$10,556,218
$11,642,131
$33,821,479
$44,146,277
$59,547,383
$58,933,036
$4,054,347
$16,141,632
#2,822,379
$82,571,649
$5,482,067
$7,040,622
$21,295,139
iSSSSSSSSSSSSS
$368,270,421
$26,305,030
$82,571,649
$2,822,379
$10,130,396
$10,324,874
$11,574,719
$33,742,995
$42,825,162
$59,291,675
$58,810,072
$0
$15,837,745
$2,793,853
$83,710,931
$0
$0
$21,212,145
$350,2i4,568
$25,018,183
$83,710,931
$0
$6,588,331
$6,697,169
$11,642,131
$21,453,771
$27,510,276
$37,757,329
$37,475,256
$2,316,907
$9,474,176
$1,990,128
$56,923,789
$3,499,779
$4,476,860
$13,507,061
$241,312,963
$17,236,640
$56,923,789
$1,990,128
$6,502,665
$6,465,824
$11,574,719
$21,375,292
$25,833,622
$37,501,635
$37,352,292
$0
$9,170,286
$1,961,603
$57,035,521
$0
$0
$13,424,072
$228,197,531
$16,299,324
$57,035,521
$0
y-74
-------
TABLE 9-22: EFFECTIVENESS OF CONTROLS (Summed Over 50 fears)
(Continued)
STACK #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
STACK #
FROM
TABLE
9-16
5
6
11
14
18
19
21
22
31
36
42
54
55
56
CUMULATIVE COST OF EMISSION REDUCTIONS IN NPV
DIFFERENT STANDARDS, SCENARIO COMBINATIONS
(discount rate ». 01}
Total Cost
avg
max
min
STD=2,SCNRO»1 STO=2,SCNRO=2 STD=6,SCNR0=1
*9,305,7% $9,179,842 $5,725,835
$9,345,817 $8,946,252 $5,682,395
$10,062,534 $10,000,281 $10,062,534
$30,806,255 $30,660,220 $18,643,564
$37,852,525 $35,163,892 $22,712,790
$54,219,319 $53,863,408 $32,790,960
$53,948,285 $53,827,744 $32,702,959
$3,840,260 $0 $2,120,022
$14,496,855 $13,891,433 $8,156,995
$2,545,085 $2,518,741 $1,721,074
$73,909,893 $74,575,890 $48,785,811
$5,020,712 $0 $3,058,051
$6,445,198 $0 $3,906,820
$19,425,357 $19,271,601 $11,749,836
STO=6,SCNRO=2
I
$331,223,890
$23,658,849
$73,909,893
$2,545,085
$311,899,302
£22,278,522
$74,575,890
$0
$5,623,591
$5,382,484
$10,000,281
$18,536,209
$20,528,238
$32,502,717
$32,582,417
$0
$7,734,146
$1,694,731
$48,685,000
$0
$0
$11,636,983
$207,819,644
$14,844,260
$48,785,811
$1,721,074
$194,906,798
$13,921,914
$48,685,000
(0
9-75
-------
TABLE 9-22: EFFECTIVENESS OF CONTROLS (Sunned Over SO Years)
CContinued)
STACK #
FROM
TABLE
STACK #
9-16
1
5
2
6
3
11
4
14
5
18
6
19
7
21
8
22
9
31
10
36
11
42
12
54
13
55
14
56
II
II
II
il
II
II
II
II
II
It
If
I
II
H
II
II
II
II
Total Cost
avg
max
min
CUMULATIVE COST OF EMISSION REDUCTIONS IH NPV
DIFFERENT STANDARDS, SCENARIO COMBINATIONS
(discount rate « .05)
'sTD=2,SCNRQ*1 STD=Z,SCNRO=2 STD=6,SCNRQ=1 STD=6,SCNRO=2
$7,386,824
$6,548,332
$6,911,048
$24,319,818
$23,504,981
$42,749,078
*43,588,260
$3,365,828
$10,561,823
$1,975,29?
$55,457,303
$4,060,513
$5,207,936
$15,445,719
ssssssss&ssss;
$251,082,759
$17,934,483
$55,457,303
$1,975,297
$7,114,867
$5,636,277
$6,865,421
$23,928,961
$17,393,402
$42,015,546
$43,476,727
$0
$9,032,556
$1,955,990
$54,445,872
$0
$0
$15,035,505
$226,901,125
$16,207,223
$54,445,872
$0
$3,986,672
$3,530,867
$6,911,048
$12,923,013
$12,626,224
$22,671,862
$23,152,279
$1,711,123
$5,304,183
$1,182,677
$32,255,469
$2,172,620
$2,766,258
$8,192,490
1139^86,784
$9,956,199
$32,255,469
$1,182,677
$3,824,408
$3,024,320
$6,865,421
$12,711,090
$9,220,181
$22,251,337
$23,040,746
$0
$4,519,757
$1,163,370
$31,402,650
$0
$0
$7,971,494
$125,994,775
$8,999,627
$31,402,650
$0
9-76
-------
TABLE 9-22: EFFECTIVENESS OF CONTROLS (Summed Over SO Years)
(Continued)
CUMULATIVE COST OF EMISSION REDUCTIONS IN NPV
DIFFERENT STANDARDS, SCENARIO COMBINATIONS
(discount rate = .10)
STACK i
*" ?~
2
3
4
5
6
7
8
9
10
11
12
13
14
STACK #
FROM
TABLE I
9-16 STD«2,SCNRO=1 STD=2,SCNRO=2 STD=6,SCNR0=1 STD=6,SCNR0=2
5
6
11
14
18
19
21
22
31
36
42
54
55
56
Total Cost
avg
max
min
56,
$4
$5
*20
$15
$36
$38
$3
$8
$1
S45
$3
$4
$13
,391,140
,892,154
,521,128
,787,287
,850,139
,500,339
,396,140
,086,094
,096,103
,700,090
,718,433
,577,533
,588,161
,331,347
$208,436,087
$14,888,292
$45,718,433
$1,700,090
*5,966,223
$3,596,385
*5,489,680
*20,139,886
*8,079,766
$35,352,529
*38,294,516
*0
*5,865,783
*1,686,782
$43,019,302
$0
$0
$12,652,399
*180,143,252
*12,867,375
$43,019,302
$0
$3,193,121
$2,453,156
$5,521,128
*10,239,975
$7,926,953
$17,921,655
$18,889,067
$1,506,603
*3,808,813
$943,498
$24,584,497
$1,775,453
$2,257,468
$6,550,114
*107,571,501
$7,683,679
$24,584,497
*943,498
$2,968,098
$1,796,110
$5,489,680
$9,918,644
$4,012,127
$17,344,232
$18,787,444
$0
$2,755,365
*930,191
$22,977,672
*0
$0
$6,215,975
$93,195,535
*6,656,824
*22,977,672
$0
v-n
-------
remain idle) and will therefore continue to emit from both their sides and top. Under scenario one,
the tops of these stacks will not be covered but the sides are covered the first year.
Looking only at individual stacks that are open and growing and will be shut down in a few years,
after reaching full size, the difference between scenario one and scenario two is minor. If scenario
two is chosen, a requirement to cover the sides of idle stacks would reduce the number of fatal
cancers per year significantly.
The pattern of reduction of cancer risks to the 80 km population evident in Table 9-21 deviates
slightly from the pattern of emission reductions shown in Table 9-22. In particular, a standard of
2 pCi/m2/sec combined with scenario two results in a larger reduction of emissions than a standard
of 6 pCi/m2/sec combined with scenario one. The reason is that each stack has a different number
of persons living close to it and a different initial emission of radon. Thus emission reductions at
each stack due to different policy options will have different relative effects on reduction of cancer
risks.
With respect to costs, a flux rate of 2 pCi/m2/sec combined with scenario one is the most costly, as
shown in Table 9-22. Switching to scenario two results in a small reduction in cost while switching
to 6 pCi/m2/sec results in a larger cost reduction. A flux rate limit of 6 pCi/m2/sec and scenario two
is the least costly of the combinations studied.
9.4.5. Sensitivity Analysis
The ranking of the costs of the four combinations discussed in the preceding paragraph is not altered
as the discount rate is changed. This was ascertained in Table 9-22 for discount rates of 0, 0.01, 0.05
and 0.10.
9.5 Industry Cost and Economic Imnaet Analysis
9.5.1. Introduction
Phosphogypsum is the major by-product of phosphate fertilizer production, an international industry.
Historically, the United States was the world's chief supplier of the industry's raw and processed
products. But as discussed in section 9.2, the United States' market share will decline sharply in the
future due to rising costs of phosphate rock to U.S. producers — as the better deposits are
depleted -- and to improved supply of sulfuric acid to the United States' competitors.
9-78
-------
In this section, two economic issues related to the control of radon emissions from phosphogypsum
stacks are considered: 1) the increase in the cost of P205 production and 2) the impact these costs
will have on the United States's economy and export revenues.
The analyses are performed using detailed data on the fourteen phosphogypsum stacks used in Tables
9-19 through 9-22, Two kinds of data are available for these stacks: first, production cost data for
the P205 production associated with the stack and, second, the stack parameters required to assess the
cost of controlling radon emissions from the stacks.
To estimate the effect of controls on U.S. exports a model was developed which estimates market
shares for the U.S. and the rest of the world's P2Os industry over the next thirty years in major
regional markets. The model used two scenarios, one scenario using relatively lower U.S. phosphate
rock costs in the production cost estimate and a second using relatively higher U.S. phosphate rock
costs.
Radon control costs were produced by the model described in section 9.3 using stack parameters
and input costs provided in section 9.3 and the appendix, respectively. For various discount rates,
0, .01, .05, and .10, the net present value (NPV) was calculated for the flow of costs and the
annualized payment corresponding to each NPV was then computed. Annualized regulatory costs for
each of the eleven producers — which use the fourteen stacks — per 1000 MT of P205 are provided
in Table 9-23. In computing the annualized costs of the regulation, it was assumed that the NPV of
the fifty year cost stream was paid off in the first five years the regulation was in effect. Five years
roughly approximates the average remaining lifespan of the fourteen existing stacks.
9.5.2. Production Costs and Market Prices
The production cost data come from Zellars-Williams and are based on detailed descriptions of
individual plant production functions. These data include both the expected quantities and prices
of resources used in the production of P205, including sulphur, phosphate rock, and waste disposal;
and credits for steam production and cogeneration of electricity. In addition, the source of the
phosphate rock used by each plant is identified. Estimates for each variable are made for the years
1990, 1995, 2000,and 2005.
Trends in market prices for P2Os are shown in Table 9-2 and Figure 9-1. An estimate of 1986
production costs for P2Os is shown in Table 9-3. For 1986, the price of P2Os (FOB U.S. Gulf)
9-79
-------
TABLE 9-23; COST OF CONTROLLING RADON IK DOLLARS PER 1000/KT OF
PLANT CAPACITY, ANNUALIZED OVER k FIVE YEAR PERIOD
STACK #
FROM
TABLE
FACILITY #
STACK #
9-16
3 = S£S2SS======S=: =
==========
II
li
II
II
tl
II
tl
II
II
II
* 1
1.2
5,6
2
3
11
3
4
14
4
5
18
5
6
19
6
7
21
*# j
8
22
8
9
31
9
10
36
10
11
42
*** 11
12,13,14
54,55,56
II
tl
tl
(1
II
II
II
II
II
II
II
II
II
II
II
II
FACILITY NAME
Conserv, I ric,
Occidental Chemical Co. (Swift River)
Farmland Industries, Irtc
Agrico Chemical Co
CF industries, Inc
IMC Corp
J.R. Slmplot Co
Mobil Chemical Co
Beker Industries Corp
Freeport Chemical Co
MobiI Mining and Minerals Division
CAPACITY
STATE (1000 MT/yr)
Florida
Florida
Florida
Florida
Florida
Florida
Idaho
Illinois
Louisiana
Louisiana
Texas
180
340
520
380
760
1550
0
110
420
800
220
STATUS
========
Open
Open
Open
Open
Open
Open
Idle
Open
Open
Open
Open
* -- Includes two stacks, each with a capacity of 90,000 MT/yr.
*• -- This plant's only stack is idle, ie, zero effective capacity. Therefore, although
costs were incurred, cost per unit of capacity is incalculable. The zeros in this record are not used
in determining the plant with the minimum unit costs. However, the annualized costs to this firm are
included in the "mean" figure.
*** -- This facility has three stacks, each with a capacity of 220,000 MT/yr. However, only one of the three
stacks {# 12) is operating. Unit cost was calculated by dividing annualized cost by capacity of the
operating stack.
**** .. sum 0f annualized costs divided by active yearly capacity.
9-80
-------
TABLE 9-23 (cont'd): COST OF CONTROLLING RADON IN DOLLARS PER 1000 MT OF PLANT
CAPACITY, ANNUALIZED OVER A FIVE YEAR PERIOD
STACK #
FROM
TABLE
STANDARDS SCENARIOS
FACILITY
STACK »
9*16
0
0.01
0.05
0-1
sssssssssssss
ssssass
SSSSSSSSSS£S£SS£Sr=S±::SS££S5SSSSSSSSS
SSSSSSSSSSS5SS5SS
ssssssasMassssE
* 1
1,2
5,6
$23,080
$21,350
$17,881
$16,536
2
3
11
$6,848
$6,098
$4,695
$4,284
3
4
14
$13,008
$12,206
$10,802
$10,545
4
5
18
$23,235
$20,524
$14,287
$11,003
5
6
19
$15,670
$14,699
$12,992
$12,669
6
7
21
$7,604
£7,171
$6,495
$6,535
** j
8
22
...
™ * *
—
—
8
9
31
$29,348
$27,1S4
$22,177
$19,416
9
10
36
$1,344
$1,249
$1,086
$1,068
10
11
42
$20,643
$19,035
$16,012
$15,076
*** ^ "i
12,13,14 54
,55,56
$30,743
$28,931
$25,947
$25,777
==============
=============
S5S*S=S5:=SSSS3SSSSS=SsrS:££££
_________________
=============
aggregate annualized
costs
$81,858,249
$79,002,947
$65,646,675
$60,947,215
****
mean
$14,078
$12,949
$10,643
$9,713
max
$30,743
$28,931
$25,947
$25,777
min
$0
$0
$0
$0
IP
11
!!
!!
IP
It
!!
!!
=============
iSSSSSE
sssssssss=ss===£=:s£:
=============
r = discount rate.
* -- see first page of this table.
** -- see first page of this table.
see first page of this table.
- see first page of this table.
***
9-81
-------
TABLE 9-23 (cont'd): COST OF CONTROLLING RADON IN DOLLARS PER 1000 MT OF
PLANT CAPACITY, ANNUALIZED OVER A FIVE YEAR PERIOD
***
STACK #
FROM
STANDARD=2
SCENARIOS
TABLE
1
FACILITY
STACK #
9.3-1
"rM s o
-r" = .01
"r" - .05
"r" ¦ .10
II
H
H
It
11
11
It
II
it
=::sskssss
ssssssssssssxsss
sssssssssssss
II
II
II
II
II
II
II
.SSSSSSSSSSBS
1
1,2
5,6
$22,728
$20,748
$16,362
$14,014
2
3
11
$6,809
$6,060
$4,664
$4,259
3
4
14
$12,978
$12,149
$10,629
$10,217
4
S
18
$22,540
$19,066
$10,572
$5,609
5
6
19
$15,603
$14,603
$12,769
$12,271
6
7
21
$7,588
$7,155
$6,479
$6,517
7
8
22
...
—
...
—
a
9
31
$28,796
$26,020
$18,966
$14,067
9
10
36
$1,330
$1,236
$1,076
$1,059
10
n
42
$20,928
$19,207
$15,720
$14,185
11
12,13,14
54,55,56
$19,284
$18,049
$15,786
$15,171
It
II
II
II
II
II
II
II
II
II
i
II
li
II
II
II
II
II
;:sss:£=z====:
tl
II
tl
«
II
1!
II
1!
II
1!
II
II
sssssssss&ss:
=SSSSSSSSSSSi
aggregate annualized costs
$78,125,118
$71,152,272
$56,084,043
$49,173,474
***#
mean
$14,417
$13,117
$10,275
$8,852
max
$28,796
$26,020
$18,966
$15,171
min
$0
$0
$0
$0
r = discount rate.
* -- see first page of this table.
** -- see first page of this table.
*** -- see first page of this table.
**** -- see first page of this table.
srrrsssssrssjsss
9-82
-------
TABLE 9-23 (cont'd): COST OF CONTROLLING RADON IN DOLLARS PER 1000 MT OF
PLANT CAPACITY, ANNUALIZED OVER A FIVE YEAR PERIOD
STACK »
FACILITT
STACK- §
FROH
TABLE
9* 16
»r" = 0
1
M
5,6
$14,762
2
3
11
$6,848
3
4
14
$8,251
4
5
18
$14,479
5
6
19
$9,936
6
7
21
$4,836
7
8
22
—
8
9
31
$17,226
9
10
36
$948
10
11
42
$14,231
11
12,13,14
54,5S,56
$19,531
STANDARDS SCENARIOS
°r" = .05
Kftl
.05
lif.ll
.10
$53
sss=:s8ssssssss&SKssss3£S£=sssBsaacasBS3:ss:
aggregate annualized costs
#*** mean
max
mm
ss==s£ssssssrsr==5==;=======ssssr:
r * discount rate.
* -- see first page of this table.
** -- see first page of this table.
*** -- see first page of this table.
**** -- see first page of this table.
,796,222
$10,095
$19,531
SO
$13,059
$6,098
$7,387
$12,315
$8,890
$4,347
$15,279
$844
$12,565
$17,527
$47,968*432
$8,937
$17,527
$0
$9,646
$4,695
$5,740
$7,675
$6,890
$3,450
$11,138
$650
$9,313
$13,786
$36,356,225
$6,635
$13,786
$0
$8,275
$4,284
$5,195
$5,503
$6,221
$3,215
$9,134
$593
$8,107
$12,690
$31,970,295
$5,747
$12,690
$0
s=ss::sssssssrs==sssssss
9-83
-------
TABLE 9-23 (cont'd): COST OF CONTROLLING RADON IN DOLLARS PER 1000/HT OF
PLANT CAPACITY, ANNUALIZED OVER A FIVE TEAR PERIOD
STACK #
FROM
STANDAR0=6
TABLE
I
FACILITY
STACK #
9-16
"r" = 0
"r" s ,01
ccsssrsssss
II
II
II
1!
s
If
II
1!
I!
II
li
»
1
1,2
5,6
$14,409
$12,598
2
3
11
$6,809
$6,060
3
4
14
$8,221
$7,345
4
5
18
$13,597
$11,131
5
6
19
$9,869
$8,812
6
7
21
$4,820
$4,331
7
8
22
* - -
...
8
9
31
$16,673
$14,487
9
10
36
$934
$831
10
11
42
$14,259
$12,539
11
12,13,14
54,55,56
$12,204
$10,899
:=sss:ssss£sssssssss
:=ss=s££;===sa
$51
aggregate annual lied costs
»*** mean
max
min
r = discount rate.
* -• see first page of this table.
** -- see first page of this table.
*** -- see first page of this table.
#*** .. see first page of this table
,006,427
19,254
$16,673
$0
$44,867,499
$8,094
$14,487
$0
»r»i s .05
ssssbssssssssssss;
$8,788
$4,664
$5,646
$5,604
$6,762
$3,433
$9,490
$640
$9,067
$8,369
rsr===s:=ss===s
$32,080,992
$5,679
$9,490
$0
•r" « .10
ssssstsss
$6,982
$4,259
$5,032
$2,785
$6,020
$3,197
$6,608
$584
$7,577
$7,453
$26,517,566
$4,591
$7,577
$0
9-84
-------
averaged $279.38 per metric ton and the estimated production costs totaled $263.88. P2Os prices for
the first half of 1988 averaged $306.50. While these prices and costs are snapshots of a highly
variable market, they are consistent in estimating the order of magnitude of the costs of producing
p2o5-
Runs of the control cost model, the results of which are displayed in Table 9-23, produced annualized
radon emission control costs per 1000 MT of P205 for each combination of emission flux standard,
scenario and discount rate. For each plant the most costly combination of these factors was
considered. For all runs, the highest cost per 1000 MT of P2Os production of controlling radon
emissions, from any of the eleven plants is estimated to be $30.74 per ton of P2Os. This amounts to
12 per cent of the 1986 production cost, 11 per cent of the 1986 average price, and 10 per cent of the
average price for the first half of 1988. The smallest maximum annualized cost of radon emission
control at any plant was $1.34. While the larger of these cost increases is significant, the ultimate
economic impact depends on the effects of the increases on the domestic and international markets.
9.5.3. Measuring Economic Impacts
9.5.3.1 Background
The approach to measuring the economic impacts of controlling radon emissions from
phosphogypsum stacks used in this section is to trace the initial round of effects on the U.S. economy.
The initial round of effects is generally the largest and easiest to identify. Adjustments made by the
rest of the world will not be traced in this section.
First round effects include changes in the relative price and real output of P205, which lead directly
to:
o changes in the prices and amounts of the inputs to P2Os used, including phosphate
rock, sulfuric acid, land and labor;
o changes in the amounts of resources used in the transportation of these inputs and
outputs;
o changes in the amounts of P205 exported and in the trade balance and foreign
exchange related to these exports.
These first round effects are discussed below. The nature of economic effects in further rounds of
adjustment will depend on the opportunity cost of using resources in P205 production and the
9-85
-------
substitutability of other products for P205. For example, if a decline in the sale and profitability
of P205 produced in Florida led to decisions not to begin new phosphogypsum stacks, the land that
would have been used for the stack becomes available for other purposes. If these other purposes
create economic activity then the new activity should be added to the ledger as the economic activity
attributable to the stack is subtracted. The activity attributable to the alternative use is the
opportunity cost of using the land for a stack. If the opportunity cost is relatively high, then the loss
due to not proceeding with the stack is relatively low, but if opportunity costs for using a resource
are low, then the loss of economic activity from not being able to open it is relatively high.
A concept related to this is the unemployment of resources. If resources have a low utilization rate,
then the reduction in economic activity of not using them in P205 production is high as alternative
uses are not available and the resources become idle. In short, the economic impact of a change in
usage of P205 plants will depend on the level to which resources are employed in the vicinities of the
plants affected by the controls.
9.5.3.2. Changes in Quantity of P^O; Produced Pue to Control Requirements
Changes in the quantity of P2Os produced in the United States will be a direct result of the change
in production costs attributable to the regulations. A reduction will take place if domestic producers
of P205 lack the ability or inclination to absorb the cost increase and therefore raise their prices
relative to the level they would have charged in the absence of regulation. As was described in
section 9.2, the phosphate fertilizer industry during the 1980s has generally experienced decreased
demand and lower relative prices. As a consequence some companies have sold their phosphate
fertilizer plants or gone out of business. This economic history makes it unlikely that producers will
be able or willing to absorb the cost of the controls.
Domestic producers are expected to pass on the cost of the controls. These price increases are
unlikely to jeopardize U.S. producers hold on the domestic market. The cost of production of foreign
producers, including transportation costs to the U.S., do not make foreign producers competitive in
the U.S. market, even after the controls. Since there is no direct substitute for phosphate fertilizer,
the reduction in domestic demand for phosphate fertilizer because of the increase in price will be
limited. Because there is no good estimate of the price elasticity of demand for phosphate fertilizer,
it is not possible to estimate the magnitude of this effect.
It is possible to estimate the effect of the controls on U.S. market share in the rest of the world.
When the specific costs of controlling radon emissions from phosphogypsum stacks are added to the
9-86
-------
production costs of U.S. producers, but not to those of foreign producers, shifts in market shares
result. The magnitude of the changes are not readily predictable from the average control costs
computed above, because of variation in the control costs faced by each plant and because a firm's
share of a market is not affected until the price at which it can supply the product exceeds the lowest
price at which a competing firm or nation is willing to offer the product. To determine the impact
of radon control costs on world markets, a model of world P205 markets was constructed and is
described below.
9.5.3.3 Methodology for Estimating Economic Impacts
Over the next thirty years, a host of factors will influence the level of production, prices and trade
patterns that will develop for phosphate products. Demand for fertilizer will increase at different
rates around the world. New production capacity will be built; sources of phosphate rock and sulfur
and the prices of those products will change. Transportation costs between importing and exporting
countries will change. To analyze these relationships and to develop a basis from which to estimate
the cost of the controls on the phosphate industry over the next 30 years, a computer model was
developed for this study. Below is a description of the model and the forecasts made with it.
Model Structure
The model developed to analyze these uncertainties uses the sources described in section 9.2. In
particular, the model makes use of plant-specific production cost estimates from Zellars-Williams,
alternative phosphate rock mining costs from William Stowasser at the Bureau of Mines, and
phosphate fertilizer demand estimates from WEFA.
The model contains forecasts of production levels, production costs, transportation costs and demand
for six regions and the United States. Production forecasts are not available beyond the year 2005.
Consequently, production forecasts for 2018 were produced separately and combined with the others.
WPPA is sold in several forms. Some countries purchase the acid and domestically produce various
fertilizers while other countries purchase finished fertilizers, such as diammonium phosphate. For
simplicity, the model considers only phosphoric acid production costs. This implicitly assumes that
no exporting country has a comparative advantage in producing various fertilizers.
The model considers the production and transport costs of each supplier and ranks the lowest to
highest suppliers for each region. Each supplier is assumed to maximize profits by supplying those
9-8?
-------
regions where its costs are lowest. Thus, if Morocco is the lowest cost supplier in more regions than
it can supply, Morocco is assumed to favor markets where its transportation costs are lowest.
The model is modified to allow for some special cases where noncompetitive domestic production is
assumed to receive special support to overcome foreign competition. The model does not, however,
consider cases where state-owned enterprises may export below cost for prolonged periods in order
to obtain foreign exchange. This possibility is a serious concern to many in the phosphate industry
because much of the foreign competition is state owned. Nevertheless, it is not possible to reliably
forecast political influences on financial decisions.
A detailed description of the methodology, data sources and assumptions used in the forecasting
model is given in Appendix B.
Forecast of Trade Levels Without Controls
Two scenarios, a lower phosphate rock cost, and a higher phosphate rock cost, were developed for
the model. The only variable changed between the scenarios is the cost of mining phosphate rock in
the United States. As was described in section 9.2, this factor is of primary importance in
determining the outlook for the phosphate fertilizer industry. The lower phosphate rock cost scenario
uses phosphate rock mining cost estimates developed by Zellars-Williams (ZW) and the higher
phosphate rock costs scenario uses rock mining cost estimates developed by experts at the U.S. Bureau
of Mines.
The higher phosphate rock cost, lower exports, scenario anticipates export levels in 1990 of 6.5
million tons. This scenario predicts exports will decline to 3.7 million tons in 1995 and continue
declining to 1.8 million tons in the year 2000 and 0.6 million tons in 2005. The U.S. is expected to
stop exporting phosphate fertilizer products sometime after 2005 and before 2018. Tables 9-24 and
9-25 show these forecasts for both scenarios by region. Because the model could not incorporate
all the factors which influence the regional trade levels, the regional forecasts are not as reliable as
the aggregate forecast.
The lower phosphate rock cost, higher exports, scenario uses the same rock cost estimates for 1990
as the previous forecast and consequently anticipates identical export levels in 1990. In 1995, export
levels are forecast to decline to 4,5 million tons. In the years 2000, 2005 and 2018, exports are
forecast to be 2.9, 1.9 and 0.6 million tons, respectively. Thus, the lower phosphate rock costs
scenario forecasts a similar trend as the previous scenario but forecasts a'slower rate of decline in
9-88
-------
TABLE 9-24A:
WORLD MARKET
SHARES OF U.S.
P205 PRODUCERS
EXPORTS
IN ABSENCE OF RADON CONTROL MEASURES (in 1000 MT)
Lower Phosphate Rock Costs
mo
1995
2000
2005
2018
LAI. AMER
771
422
338
187
0
U. EUROPE
940
832
987
433
620
E. EUROPE
488
448
121
0
0
S, C. ASIA
565
806
0
0
0
E. ASIA
2,901
1,204
520
310
0
OCEANIA
860
827
906
979
0
TOTAL AMOUNT
6,525
4,539
2,872 1,909
620
TABLE 9-24B:
WORLD MARKET
SHARES OF U.S.
P205 PRODUCERS
EXPORTS
WITH MOST EXPENSIVE RADON CONTROL MEASURES
(In 1000 MT)
1990
1995
2000
2005
2018
LAT. AMER
771
422
0
0
0
U. EUROPE
508
0
0
0
0
E. EUROPE
608
0
0
0
0
S. C. ASIA
508
0
0
0
0
E. ASIA
1,933
1,995
1,764
619
0
OCEANIA
860
827
0
0
0
TOTAL AMOUNT
5,188
3,244
1,764
619
0
TABLE 9-24C: DIFFERENCE IN WORLD MARKET SHARES OF US P205 EXPORTS
DUE TO HOST EXPENSIVE RADON CONTROL MEASURES
(in 1000 MT)
1990
1995
2000
2005
2018
LAT. AMER
0
0
(338)
(187)
0
W. EUROPE
(432)
(832)
(987)
(433)
<620)
E. EUROPE
120
(448)
(121)
0
0
S. C. ASIA
(57)
(806)
0
0
0
E. ASIA
(9685
791
1,244
309
0
OCEANIA
0
0
(906)
(979)
0
TOTAL AMOUNT (1,337) (1,295) (1,108) (1,290) (620)
8-89
-------
TA81E 9-25A:
WORLD MARKET SHAKES OF U.S. P2D5 PRODUCERS EXPORTS
IN ABSENCE OF RADON CONTROL MEASURES (in 1000 MT)
Higher Phosphate Rock Costs
1990
1995
2000
2005
LAT. AMER
771
422
0
0
W. EUROPE
940
272
0
0
E. EUROPE
488
0
0
0
S. C. ASIA
565
0
0
0
E. ASIA
2,901
2,187
1,764
620
OCEANIA
860
827
0
0
TOTAL AMOUNT
6,525
3,708
1,764
620
TABLE 9-25B: WORLD MARKET SHARES OF U.S. P205 PRODUCERS EXPORTS
WITH MOST EXPENSIVE RADON CONTROL MEASURES
{in 1000 MT)
1990
1995
2000
2005
2018
LAT, AMER
771
422
0
0
0
W. EUROPE
608
0
0
0
0
E. EUROPE
508
0
0
0
0
S. C. ASIA
508
0
0
0
0
E. ASIA
2,151
1,995
1,764
620
0
OCEANIA
860
827
0
0
0
TOTAL AMOUNT
5,406
3,244
1,764
620
0
TABLE 9-25C: DIFFERENCE IN WORLD MARKET SHARES OF US P205 EXPORTS
DUE TO MOST EXPENSIVE RADON CONTROL MEASURES
1990
1995
2000
200S
LAT. AMER
0
0
0
0
W. EUROPE
(332)
(272)
0
0
E. EUROPE
20
0
0
0
S. C. ASIA
(575
0
0
0
E. ASIA
(750)
(192)
0
0
OCEANIA
0
0
0
0
TOTAL AMOUNT
(1,119)
(464)
0
0
9-00
-------
export levels. Several important factors shed light on the model's forecasts. As explained in section
9,2, U.S. producers are expected to experience marginally higher costs for sulfur and North Africa
is expected to have a similar decrease in costs. Changing sulfur costs accounts for a $10 to $15 per
ton shift in phosphoric acid production costs between the U.S. and the major competitors in North
Africa. The most important factor influencing the pessimistic outlook for U.S. phosphate exports is
the cost of mining phosphate rock. Even the lower phosphate rock costs scenario allows for an
increase in phosphate rock costs for U.S. producers over time.
Forecast of Trade Levels With Controls
To estimate the trade impacts of the proposed controls, both scenarios of the model were run with
the added costs of the controls included. For each U.S. plant, the highest cost option for that plant
that was calculated in the previous section was added to the production cost of that plant in the
model. The forecasts are shown in Tables 9-24 and 9-25. The forecasts for trade levels with and
without the controls under the lower phosphate rock costs scenario are also illustrated on Figure 9-
4. In the lower phosphate rock costs scenario, the controls are projected to decrease exports by 1.3
million tons in 1990. This effect remains at 1.3 million tons in the year 1995, 1,1 million tons in the
year 2000, 1.3 million in 2005,and drop to 0.6 million tons by 2018. Assuming a continuous change
in export levels during the years not specifically forecast, the controls are forecast to decrease exports
by 31.0 million tons over the next 30 years using the lower phosphate rock costs scenario.
Using the higher phosphate rock costs scenario, the controls are forecast to decrease exports by 1.1
million tons in 1990 and by 464,000 tons in 1995. No effect on exports is projected by the year 2000
and beyond. Assuming a continuous change in export levels during the years not specifically
forecast, the controls are forecast to decrease exports by 5.1 million tons over the next 30 years using
the lower phosphate rock costs scenario. The forecasts for trade levels with and without the controls
under the higher phosphate rock costs scenario are illustrated on Figure 9-5.
Balance of Trade
The effects of the decrease in exports of phosphate products on the trade balance depends to some
extent on the form in which the phosphoric acid is exported. If the phosphoric acid is exported
directly, the loss in export revenue is approximately $307,50 per ton of P205 (1988 dollars). If the
phosphoric acid is first converted into phosphate fertilizer, the loss in export revenue is greater. For
example, diammonium phosphate (DAP) uses 0.478 tons of P205 to produce per ton of DAP. DAP
sold for $188.60 per ton in 1988. Thus, the decrease in export level from a one ton decrease in P205
9-91
-------
Figure 9-4: U.S. P205 EXPORTS
Assuming Lower Phosphate Rock Costs
Phosphate Exports in Millions of MT
1990
1995
2000
2005
2010
2015
Year
Without Regulation —+~ With Regulation Difference
Figure 9-5: U.S. P205 EXPORTS
Assuming Higher Phosphate Rock Costs
Phosphate Exports in Millions of MT
7
1990 1995 2000 2005 2010 2015 2020
Year
—Without Regulation —With Regulation Difference
9-01
-------
exports that has been converted into DAP is approximately $394,50 per ton of P2Os (1988 dollars).
In 1985, 17.8 percent of the revenue from phosphate products came from the export of P205 and
82.2 percent came from the export of finished fertilizer. Because the preponderance of P205 is
exported as finished fertilizer and the principal phosphate fertilizer is DAP, the revenue effects of
the controls are described in terms of a weighted average of P205 and DAP exports.
The two scenarios predict that the effect on export revenue in 1990 will be a reduction in export
revenue of $410 million for the low cost scenario and $343 million for the high cost The higher
phosphate rock cost, lower export, scenario predicts that the cumulative revenue loss over the next
30 years will be $1.4 billion. The lower rock costs, higher export, scenario predicts that the
cumulative revenue loss will be $9.5 billion. The revenue loss in the higher rock cost scenario is
limited to the next ten years, with no loss in exports by the year 2000 and beyond. These estimated
economic impacts of the standard are obviously dependent upon the many assumptions in developing
the model that are described in Appendix B. The export revenue effects of the standard in the early
years of the controls are much more reliable than the forecasts for 20 or 30 years in the future. The
decrease in export revenues in 1990 is estimated to be approximately a little under one half a billion
dollars. A revenue loss of this magnitude would continue were it not for the general decline in
phosphate exports that is forecast in both scenarios.
9.5.3.4. Other Impacts of Radon Control Requirements on the U.S. Economy
The shifts in the markets for P2Os are the most notable direct effects of radon control costs.
However, there are some spinoffs as noted above. These are discussed below.
Incuts: Sulfuric Acid
Most sulfuric acid used in the production of P205 is the by-product of other activities such as
removal of sulfur from gas or oil. Reductions in the demand for sulfuric acid for use in P2Os
production would reduce the prices at which this residual could be sold, and thereby increase the
net costs of oil and gas desulfurization. These effects are expected to be minor.
Inputs: Phosphate Rock
Phosphate rock is exported to some of the world's other P205 producing nations. If the United
States loses some exports of PgOs to other countries due to increased regulatory costs, it is likely
that exports of phosphate rock to these nations will increase. This will mitigate some of the losses
9-93
-------
of revenue that would accompany loss of P2Os markets. In many cases the increased sale of
phosphate rock will bring revenues to the same firms that lost revenue due to declines in P205 sales.
These effects, however, will be short term because the U.S. is not expected to remain a significant
phosphate rock exporter for many years.
Inputs: Labor
Since the value of labor required to produce P2Os is a small proportion of the total value of all
inputs, the absolute size of the shift in the labor market will be small. This small impact may be
magnified or diminished by the local employment situation. In areas that are experiencing economic
growth, there will be demand for labor that will be able to absorb the relatively small number of
persons affected. This is especially true in Florida, where population growth can be expected to
generate demands for increased levels of construction activity, and where the largest concentration
of workers in the P2Os industry is clustered. It should also be noted that the regulations require
increased ongoing activity in the form of the labor and other employment of resources and equipment
needed to lay drains on the stacks, move and place dirt on the stacks, and maintain the cover and
drains. The first two activities will occur so long as any stacks remain open and the last will be
required for all closed stacks.
Inputs: Land
The land for existing stacks is already in use and its quantity and location will not be changed by
the regulation. The regulation could affect the decision to start new stacks and would therefore
affect the land requirements in the future.
Transportation
Some reduction in the transportation of P205 exports can be anticipated. On the other hand,
increased transportation of phosphate rock will partially mitigate the reduction. However, since
most transport of these materials is by foreign-owned ships, this reduction will not affect U.S.
interests.
9-94
-------
9.6.1 Introduction
The Regulatory Flexibility Act was signed into law on September 19, 1980. Its purpose is to call to
the attention of federal agency personnel any impacts on small "entities" such as small business, small
organizations, or small governmental jurisdictions that may unduly hamper them. The hope of the
law's authors was that if federal agencies were aware of negative impacts on small entities due to a
rulemaking, they would modify the rule, if possible, to reduce the damage.
Two kinds of small entities are potentially affected by the rulemaking on phosphogypsum stacks:
small business and small government. However, the analysis below shows that entities falling under
the definition of the act are not adversely affected in a significant way.
9.6.2 Small Business
The business entities directly affected by the phosphogypsum rules under consideration are large
corporations. They include large, internationally operated chemical companies, oil firms and fertilizer
producers. For most of these firms, P205 production is but one of numerous activities including
phosphate rock mining and processing, fertilizer production, or chemical production. The amount
of investment and risk involved in these productions is large, too large for a firm that could qualify
as a small business to engage in.
9.6.3 Small Governmental Entities
The definition of a small county is one with less than 50,000 citizens. However, the counties in
Florida with the highest concentration of phosphoric acid production have greater than 50,000
citizens.
9-95
-------
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Fa84
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Fantel, R.J., Sullivan, D.E., and Peterson, G.R. Phosphate Rock Availability--
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GA079 General Accounting Office, Phosphates; A Case Study of a Valuable, Depleting
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GM87 Green Markets. Green Markets Trade Overview, May 18, 1987.
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Mike Lloyd, Florida Institute of Phosphate Research, Personal Communications,
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9-101
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MAN85 Mannsville Chemical Products Corporation. "Phosphoric Acid (Wet Process),"
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with J.S. Platou, The Sulfur Institute, June 14, 1988.
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Minerals, September 1987.
RP86 Rhone-Poulenc, annual report 1986.
Sp83 Spangenberg, Dale R., Carey, Edward F., and Takosky, Paula M. Minerals
Availability Commodity Directory on Phosphate (IC 8926). Bureau of Mines, 1983.
SRI85 SRI International, Animal Feeds, Phosphate Supplements, March 1985, p. 201.
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St86a
St86b
Te87
TFI86a
TFI86b
TFI87b
TFI88
TFI87C
TFI87d
TFI87e
Tu83
Tu87
TVA88
USD83
USD86
USD87a
USD87b
of Mines.
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. "Phosphate Rock," preprint from the 1986 Minerals Yearbook, Bureau
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. Fertilizer Financial Facts for Year Ended December 31, 1986
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. Fertilizer Record, January 1988 (production and disappearance data,
January 1988).
. Phosphate Fertilizer Production Cost Survey, Year Ended December
31, 1986 (compiled by National Fertilizer Development Center, Economics and
Marketing Staff, Tennessee Valley Authority), May 1, 1987.
Phosphate Rock Production Cost Survey, Year Ended December 31,
1986 (compiled by National Fertilizer Development Center, Economics and Marketing
Staff, Tennessee Valley Authority), May 1, 1987.
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year 1987. October 1987.
Turner, Billie. "Obstacles to International P205 Trade and Measures
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Tully, J.J. and Ziebold, S.A. "Economics of Manufacture of Sulfuric Acid from
Pyrites Compared to Sulfur," Sulphur/87, 1987, pp. 219-234.
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-------
USD87C
. Economic Indicators of the Farm Sector Costs of Production, 1986,
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Vr86 Vroomen, Harry. Fertilizer Use and Price Statistics, 1960-85, Economic Research
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WH87 Wharton Econometric Forecasting Associates. U.S. and World Fertilizer Service Long-
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Group, Wharton Econometric Forecasting Associates, for the Bureau of Mines, Dept.
of Interior, OFR-24-88, April 1988.
WI86 The Williams Companies (owners of Agrico Chemical Company), annual reports 1984,
1985, 1986.
WB86 World Bank. World Development Report 1986, Oxford University Press, 1986.
Ye88 Personal communication with Whitney Yelverton, The Fertilizer Institute, March 29,
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ZE86 Zellars-Williams Co. Phosphate Rock 1985/86: A Multiclient Study by Ze liars-
Williams Co., June 1986.
9-104
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Appendix A:
-------
Motes to Appendix A
The calculations presented in Appendix A are described in Section 9.3,3. Costs are accrued as
horizontal and vertical drain pipes are laid, as dirt cover is added, and as annual maintenance is
carried out. The major costs occur at closing when the tops are covered and, in Scenario One, in the
first year when the existing sides are covered. Further coverage of the sides occurs as the stacks
grow. The only cost after closure is for maintenance.
-------
APPEND IX 10 CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 1 FLUX STANDARD - 2
SCENARIO = 1 THIOCNESSCin meters) = .995
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pel/sec)
(pCf/iec)
COST
t
614,711.1
1.317,454.0
$4,316,410
2
409,857.9
2,049,289.0
$2,197,487
3
409,857.9
2,049,289.0
$111,128
4
409,857.9
2,049,289.0
$76,405
S
409,857.9
2,049,289.0
$76,405
6
409,857.9
2,049,289.0
$76,405
7
409,857.9
2,049,289.0
$76,405
8
409,857.9
2,049,289.0
$76,405
9
409,857.9
2,049,289.0
$76,405
10
409,857.9
2,049,289.0
$76,405
11
409,857.9
2,049,289.0
$76,405
12
409,857.9
2,049,289.0
$76,405
13
409,857.9
2,049,289.0
$76,405
14
409,857.9
2,049,289.0
$76,405
15
409,857.9
2,049,289.0
$76,405
16
409,857.9
2,049,289.0
$76,405
1?
409,857.9
2,049,289.0
$76,405
18
409,857.9
2,049,289.0
$76,405
19
409,857.9
2,049,289.0
$76,405
20
409,857.9
2,049,289.0
$76,405
21
409,857.9
2,049,289.0
$76,405
22
409,857.9
2,049,289.0
$76,405
23
409,857.9
2,049,289.0
$76,405
24
409,857.9
2,049,289.0
$76,405
25
409,857.9
2,049,289.0
$76,405
26
409,857.9
2,049,289.0
$76,405
27
409,857.9
2,049,289.0
$76,405
28
409,857.9
2,049,289.0
$76,405
29
409,857.9
2,049,289.0
$76,405
30
409,857.9
2,049,289.0
$76,405
31
409,857.9
2,049,289.0
$76,405
32
409,857.9
2,049,289.0
$76,405
33
409,857.9
2,049,289.0
$76,405
34
409,857.9
2,049,289.0
$76,405
35
409,857.9
2,049,289.0
$76,405
36
409,857.9
2,049,289.0
$76,405
37
409,857.9
2,049,289.0
$76,405
38
409,857.9
2,049,289.0
$76,405
39
409,857.9
2,049,289.0
$76,405
40
409,857.9
2,049,289.0
$76,405
41
409,857.9
2,049,289.0
$76,405
42
409,857.9
2,049,289.0
$76,405
43
409,857.9
2,049,289.0
$76,405
44
409,857.9
2,049,289.0
$76,405
45
409,857.9
2,049,289.0
$76,405
46
409,857.9
2,049,289.0
$76,405
47
409,857.9
2,049,289.0
$76,405
48
409,857.9
2,049,289.0
$76,405
49
409,857.9
2,049,289.0
$76,405
50
409,857.9
2,049,289.0
$76,405
-------
APP£N01X TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 2 FLUX STANDARD = 2
SCENARIO = 1 THICICNESSCin meters) ¦ -995
EMISSIONS REMAINING
REDUCTION IM EMISSIONS
AFTER CONTROLS
OUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
993,836.9
602,931.3
*1,959,538
2
956,465.9
681,670.4
$91,304
3
917,843.4
763,046.1
$534,857
4
877,780.5
847,456.5
$46,429
5
836,037.1
935,407.9
$581,340
6
792,286.9
1,027,588.0
856,025
7
746,080.0
1,124,943.0
$644,854
8
386,833.5
1,934,167.0
$3,228,241
9
386,833.5
1,934.167.0
$81,277
10
386,833.5
1,934,167.0
$81,277
1!
386,833.5
1,934,167.0
$81,277
12
386,833.5
1,934,167.0
$81,277
13
386,833.5
1,934,167.0
$81,277
14
386,833.5
1,934,167.0
$81,277
15
386,833.5
1,934,167.0
$81,277
16
386,833.5
1,934,167.0
$81,277
17
386,833,5
1,934,167.0
$81,277
18
386,833.5
1,934,167.0
$81,277
19
386,833.5
1,934,167.0
$81,277
20
386,833.5
1,934,167.0
$81,277
21
386,833.5
1,934,167.0
$81,277
22
386,833.5
1,934,167.0
$81,277
23
386,833.5
1,934,167.0
$81,277
24
386,833.5
1,934,167.0
$81,277
25
386,833.5
1,934,167.0
$81,277
26
386,833.5
1,934,167.0
$81,277
27
386,833.5
1,934,167.0
$81,277
28
386,833.5
1,934,167.0
$81,277
29
386,833.5
1,934,167.0
$81,277
30
386,833.5
1,934,167.0
$81,277
31
386,833.5
1,934,167.0
$81,277
32
386,833.5
1,934,167.0
$81,277
33
386,833.5
1,934,167.0
$81,277
34
386,833,5
1,934,167.0
$81,277
35
386,833.5
1,934,167.0
$81,277
36
386,833.5
1,934,167.0
$81,277
37
386,833.5
1,934,167.0
$81,277
38
386,833.5
1,934,167.0
$81,277
39
386,833.5
1,934,167.0
$81,277
40
386,833.5
1,934,167,0
$81,277
41
386,833.5
1,934,167.0
$81,277
42
386,833.5
1,934,167.0
$81,277
43
386,833.5
1,934,167.0
$81,277
44
386,833.5
1,934,167.0
$81,277
45
386,833.5
1,934,167.0
$81,277
46
386,833.5
1,934,167.0
$81,277
47
386,833.5
1,934,167.0
$81,277
48
386,833.5
1,934,167.0
$81,277
49
386,833.5
1,934,167.0
$81,277
50
386,833.5
1,934,167.0
$81,277
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 3 FLUX STANDARD = 2
SCENARIO = 1 TKICKNESSCin meters) * .331
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pel/sec)
(pCi/sec)
COST
1
354,356.6
291,323.3
$4,635,814
2
354,356.6
291,323.3
$141,610
3
354,356.6
291,323.3
$141,610
4
354,356.6
291,323.3
$141,610
5
354,356.6
291,323.3
$141,610
6
354,356.6
291,323.3
$141,610
7
354,356.6
291,323.3
$141,610
8
354,356.6
291,323.3
$141,610
9
354,356.6
291,323.3
$141,610
10
354,356.6
291,323.3
$141,610
11
354,356.6
291,323.3
$141,610
12
354,356.6
291,323.3
$141,610
13
354,356.6
291,323.3
$141,610
14
354,356.6
291,323.3
$141,610
15
354,356.6
291,323.3
$141,610
16
354,356.6
291,323.3
$141,610
17
354,356.6
291,323.3
$141,610
18
354,356.6
291,323.3
$141,610
19
354,356.6
291,323.3
$141,610
20
354,356.6
291,323.3
$141,610
21
354,356.6
291,323.3
$141,610
22
354,356.6
291,323.3
$141,610
23
354,356.6
291,323.3
$141,610
24
354,356.6
291,323.3
$141,610
25
354,356.6
291,323.3
$141,610
26
354,356.6
291,323.3
$141,610
27
354,356.6
291,323.3
$141,610
28
354,356.6
291,323.3
$141,610
29
354,356.6
291,323.3
$141,610
30
354,356.6
291,323.3
$141,610
31
354,356.6
291,323.3
$141,610
32
354,356.6
291,323.3
$141,610
33
354,356.6
291,323.3
$141,610
34
354,356.6
291,323.3
$141,610
35
354,356.6
291,323.3
$141,610
36
354,356.6
291,323.3
$141,610
37
354,356.6
291,323.3
$141,610
38
354,356.6
291,323.3
$141,610
39
354,356.6
291,323.3
$141,610
40
354,356.6
291,323.3
$141,610
41
354,356.6
291,323.3
$141,610
42
354,356.6
291,323.3
$141,610
43
354,356.6
291,323.3
$141,610
44
354,356.6
291,323.3
$141,610
45
354,356.6
291,323.3
$141,610
46
354,356.6
291,323.3
$141,610
47
354,356.6
291,323.3
$141,610
48
354,356.6
291,323.3
$141,610
49
354,356.6
291,323.3
$141,610
50
354,356.6
291,323.3
$141,610
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 4 FLUX STANDARD a 2
SCENARIO = 1 THICKNESS*in meters) = 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCi/sec)
(pCi/sec)
COST
1
2,716,696.0
2,029,631.0
$7,048,714
2
926,363.2
4,631,816.0
$14,964,290
3
926,363.2
4,631,816.0
$246,010
4
926,363,2
4,631,816.0
$246,010
5
926,363.2
4,631,816.0
$246,010
6
926,363.2
4,631,816.0
$246,010
7
926,363.2
4,631,816.0
$246,010
8
926,363.2
4,631,816.0
$246,010
9
926,363.2
4,631,816.0
$246,010
10
926,363.2
4,631,816.0
$246,010
11
926,363.2
4,631,816.0
$246,010
12
926,363.2
4,631,816.0
$246,010
13
926,363.2
4,631,816.0
$246,010
14
926,363.2
4,631,816.0
$246,010
15
926,363.2
4,631,816.0
$246,010
16
926,363.2
4,631,816.0
$246,010
17
926,363.2
4,631,816.0
$246,010
18
926,363.2
4,631,816.0
$246,010
19
926,363.2
4,631,816.0
$246,010
20
926,363.2
4,631,816.0
$246,010
21
926,363.2
4,631,816.0
$246,010
22
926,363.2
4,631,816.0
$246,010
23
926,363.2
4,631,816.0
$246,010
24
926,363.2
4,631,816.0
$246,010
25
926,363.2
4,631,816.0
$246,010
26
926,363,2
4,631,816.0
$246,010
27
926,363.2
4,631,816.0
$246,010
28
926,363,2
4,631,816.0
$246,010
29
926,363.2
4,631,816.0
$246,010
30
926,363,2
4,631,816.0
$246,010
31
926,363.2
4,631,816.0
$246,010
32
926,363.2
4,631,816.0
$246,010
33
926,363.2
4,631,816.0
$246,010
34
926,363.2
4,631,816.0
$246,010
35
926,363.2
4,631,816.0
$246,010
36
926,363.2
4,631,816.0
$246,010
37
926,363.2
4,631,816.0
$246,010
38
926,363.2
4,631,816.0
$246,010
39
926,363.2
4,631,816.0
$246,010
40
926,363.2
4,631,816.0
$246,010
41
926,363.2
4,631,816.0
$246,010
42
926,363.2
4,631,816.0
$246,010
43
926,363.2
4,631,816.0
$246,010
44
926,363.2
4,631,816.0
$246,010
45
926,363.2
4,631,816.0
$246,010
46
926,363.2
4,631,816.0
$246,010
47
926,363.2
4,631,816.0
$246,010
48
926,363.2
4,631,816.0
$246,010
49
926,363.2
4,631,816.0
$246,010
50
926,363.2
4,631,816.0
$246,010
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 5 FLUX STANDARD » 2
SCENARIO = 1 THICKNESS(in meters) - .995
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCf/sec5
(pCf/sec)
COST
1
4,430,001.0
2,465,139.0
$8,008,838
2
4,356,343.0
2,620,333.0
$238,847
3
4,281,658.0
2,777,689.0
$1,092,557
4
4,205,897.0
2,937,315.0
$137,726
5
4,128,984.0
3,099,367.0
$1,134,498
6
4,050,865.0
3,263,959.0
$151,884
7
3,971,441.0
3,431,302.0
$1,180,547
8
3,890,629.0
3,601,567.0
$166,738
9
3,808,326.0
3,774,978.0
$1,231,922
10
3,724,417.0
3,951,769.0
$182,426
11
3,638,763.0
4,132,239.0
$1,289,906
12
3,551,212.0
4,316,704.0
$199,164
13
3,461,588.0
4,505,538.0
$1,356,614
14
3,369,674.0
4,699,194.0
$217,249
15
1,658,091.0
8,290,455.0
$15,032,080
16
1,658,091.0
8,290,455.0
$357,865
17
1,658,091.0
8,290,455.0
$357,865
IS
1,658,091.0
8,290,455.0
$357,865
19
1,658,091.0
8,290,455.0
$357,865
20
1,658,091.0
8,290,455.0
$357,865
21
1,658,091.0
8,290,455.0
$357,865
22
1,658,091.0
8,290,455.0
$357,865
23
1,658,091.0
8,290,455.0
$357,865
24
1,658,091.0
8,290,455.0
$357,865
25
1,658,091.0
8,290,455.0
$357,865
26
1,658,091.0
8,290,455.0
$357,865
27
1,658,091.0
8,290,455.0
$357,865
28
1,658,091.0
8,290,455.0
$357,865
29
1,658,091.0
8,290,455.0
$357,865
30
1,658,091.0
8,290,455.0
$357,865
31
1,658,091.0
8,290,455.0
$357,865
32
1,658,091.0
8,290,455.0
$357,865
33
1,658,091.0
8,290,455.0
$357,865
34
1,658,091.0
8,290,455.0
$357,865
35
1,658,091.0
8,290,455.0
$357,865
36
1,658,091.0
8,290,455.0
$357,865
37
1,658,091.0
8,290,455.0
$357,865
38
1,658,091.0
8,290,455.0
$357,865
39
1,658,091.0
8,290,455.0
$357,865
40
1,658,091.0
8,290,455.0
$357,865
41
1,658,091.0
8,290,455.0
$357,865
42
1,658,091.0
8,290,455.0
$357,865
43
1,658,091.0
8,290,455.0
$357,865
44
1,658,091.0
8,290,455.0
$357,865
45
1,658,091.0
8,290,455.0
$357,865
46
1,658,091.0
8,290,455.0
$357,865
47
1,658,091.0
8,290,455.0
$357,865
48
1,658,091.0
8,290,455.0
$357,865
49
1,658,091.0
8,290,455.0
$357,865
50
1,658,091.0
8,290,455.0
$357,865
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 6 FLUX STANDARD = 2
SCENARIO « 1 THICKNESSCin meters) » 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
QUE TO CONTROLS
ANNUAL
YEAR
CpCi/sec)
(pCI/sec)
COST
1
4,794,927.0
3,550,362.0
$12,172,590
2
1,627,573.0
8,137,861.0
$26,451,610
3
1,627,573.0
8,137,861.0
$433,433
4
1,627,573.0
8,137,861.0
$433,433
5
1,627,573.0
8,137,861.0
$433,433
6
1,627,573.0
8,137,861.0
$433,433
7
1,627,573.0
8,137,861.0
$433,433
8
1,627,573.0
8,137,861.0
$433,433
9
1,627,573.0
8,137,861.0
$433,433
10
1,627,573.0
8,137,861.0
$433,433
11
1,627,573.0
8,137,861.0
$433,433
12
1,627,573.0
8,137,861.0
$433,433
13
1,627,573.0
a,137,861.0
$433,433
14
1,627,573.0
8,137,861.0
$433,433
15
1,627,573.0
8,137,861.0
$433,433
16
1,627,573.0
8,137,861.0
$433,433
17
1,627,573.0
8,137,861.0
$433,433
18
1,627,573.0
8,137,861.0
$433,433
19
1,627,573.0
8,137,861.0
$433,433
20
1,627,573.0
8,137,861.0
$433,433
21
1,627,573.0
8,137,861.0
$433,433
22
1,627,573.0
8,137,861.0
$433,433
23
1,627,573.0
8,137,861.0
$433,433
24
1,627,573.0
8,137,861.0
$433,433
25
1,627,573.0
8,137,861.0
$433,433
26
1,627,573.0
8,137,861.0
$433,433
27
1,627,573.0
8,137,861.0
$433,433
28
1,627,573.0
8,137,861.0
$433,433
29
1,627,573.0
8,137,861.0
$433,433
30
1,627,573.0
8,137,861.0
$433,433
31
1,627,573.0
8,137,861.0
$433,433
32
1,627,573.0
8,137,861.0
$433,433
33
1,627,573.0
8,137,861.0
$433,433
34
1,627,573.0
8,137,861.0
$433,433
35
1,627,573.0
8,137,861.0
$433,433
36
1,627,573.0
8,137,861.0
$433,433
37
1,627,573.0
8,137,861.0
$433,433
38
1,627,573.0
8,137,861.0
$433,433
39
1,627,573.0
8,137,861.0
$433,433
40
1,627,573.0
8,137,861.0
$433,433
41
1,627,573.0
8,137,861.0
$433,433
42
1,627,573.0
8,137,861.0
$433,433
43
1,627,573.0
8,137,861.0
$433,433
44
1,627,573.0
8,137,861.0
$433,433
45
1,627,573.0
8,137,861.0
$433,433
46
1,627,573.0
8,137,861.0
$433,433
47
1,627,573.0
8,137,861.0
$433,433
48
1,627,573.0
8,137,861.0
$433,433
49
1,627,573.0
8,137,861.0
$433,433
50
1,627,573.0
8,137,861.0
$433,433
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 7 FLUX STANDARD = 2
SCENARIO = 1 THICKNESSCin meters) * 1.054
EMISSIONS REMAINING
SEDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCi/sec3
(pCi/sec)
COST
1
1,475,431.0
7,377,153.0
$37,895,730
2
1,475,431.0
7,377,153.0
$549,788
3
1,475,431.0
7,377,153.0
$426,823
4
1,475,431.0
7,377,153.0
$426,823
5
1,475,431.0
7,377,153.0
$426,823
6
1,475,431.0
7,377,153.0
$426,823
7
1,475,431.0
7,377,153.0
$426,823
8
1,475,431.0
7,377,153.0
$426,823
9
1,475,431.0
7,377,153.0
$426,823
10
1,475,431.0
7,377,153.0
$426,823
11
1,475,431.0
7,377,153.0
$426,823
12
1,475,431.0
7,377,153.0
$426,823
13
1,475,431.0
7,377,153.0
$426,823
14
1,475,431.0
7,377,153.0
$426,823
15
1,475,431.0
7,377,153.0
$426,823
16
1,475,431.0
7,377,1S3.0
$426,823
1?
1,475,431.0
7,377,153.0
$426,823
18
1,475,431.0
7,377,153.0
$426,823
19
1,475,431.0
7,377,153.0
$426,823
20
1,475,431.0
7,377,153.0
$426,823
21
1,475,431.0
7,377,153.0
$426,823
22
1,475,431.0
7,377,153.0
$426,823
23
1,475,431.0
7,377,153.0
$426,823
24
1,475,431.0
7,377,153.0
$426,823
25
1,475,431.0
7,377,153.0
$426,823
26
1,475,431.0
7,377,153.0
$426,823
27
1,475,431.0
7,377,153.0
$426,823
28
1,475,431.0
7,377,153.0
$426,823
29
1,475,431.0
7,377,153.0
$426,823
30
1,475,431.0
7,377,153.0
$426,823
31
1,475,431.0
7,377,153.0
$426,823
32
1,475,431.0
7,377,153.0
$426,823
33
1,475,431.0
7,377,153.0
$426,823
34
1,475,431.0
7,377,153.0
$426,823
35
1,475,431.0
7,377,153.0
$426,823
36
1,475,431.0
7,377,153.0
$426,823
37
1,475,431.0
7,377,153.0
$426,823
38
1,475,431.0
7,377,153.0
$426,823
39
1,475,431.0
7,377,153.0
$426,823
40
1,475,431.0
7,377,153.0
$426,823
41
1,475,431.0
7,377,153.0
$426,823
42
1,475,431.0
7,377,153.0
$426,823
43
1,475,431.0
7,377,153.0
$426,823
44
1,475,431.0
7,377,153.0
$426,823
45
1,475,431.0
7,377,153.0
$426,823
46
1,475,431.0
7,377,153.0
$426,823
4 7
1,475,431.0
7,377,153.0
$426,823
48
1,475,431.0
7,377,153.0
$426,823
49
1,475,431.0
7,377,153.0
$426,823
50
1.475,431.0
7,377,153.0
$426,823
-------
appendix to CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 8 FLUX STANDARD = 2
SCENARIO « 1 THICKNESSC in meters) = 2.344
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
AMMUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
550,178.5
698,209.3
$3,227,551
2
550,178.5
698,209.3
$16,873
3
550,178.5
698,209.3
$16,873
4
550,178.5
698,209.3
$16,873
5
550,178.5
698,209.3
$16,873
6
550,178.5
698,209.3
$16,873
7
550,178.5
698,209.3
$16,873
8
550,178.5
698,209.3
$16,873
9
550,178.5
698,209.3
$16,873
10
550,178.5
698,209.3
$16,873
11
550,178.5
698,209.3
$16,873
12
550,178.5
698,209.3
$16,873
13
550,178.5
698,209.3
$16,873
U
550,178.5
698,209.3
$16,873
15
550,178.5
698,209.3
$16,873
16
550,178.5
698,209.3
$16,873
17
550,178.5
698,209.3
$16,873
18
550,178.5
698,209.3
$16,873
19
550,178.5
698,209.3
$16,873
20
550,178.5
698,209.3
$16,873
21
550,178.5
698,209.3
$16,873
22
550,178.5
698,209.3
$16,873
23
550,178.5
698,209.3
$16,873
24
550,178.5
698,209.3
$16,873
25
550,178.5
696,209.3
$16,873
26
550,178.5
698,209.3
$16,873
27
550,178.5
698,209.3
$16,873
28
550,178.5
698,209.3
$16,873
29
550,178.5
698,209.3
$16,873
30
550,178.5
698,209.3
$16,873
31
550,178.5
698,209.3
$16,873
32
550,178.5
698,209.3
$16,873
33
550,178.5
698,209.3
$16,873
34
550,178.5
698,209.3
SI6,873
35
550,178.5
698,209.5
$16,873
36
550,178.5
698,209.3
$16,873
37
550,178.5
698,209.3
$16,873
38
550,178.5
698,209.3
$16,873
39
550,178.5
698,209.3
$16,873
40
550,178.5
698,209.3
$16,873
41
550,178.5
698,209.3
$16,873
42
550,178.5
698,209.3
$16,873
43
550,178.5
698,209.3
$16,873
44
550,178.5
698,209.3
$16,873
45
550,178.5
698,209.3
$16,873
46
550,178,5
698,209.3
$16,873
47
550,178,5
698,209.3
$16,873
48
550,178.5
698,209.3
$16,873
49
550,178.5
698,209.3
$16,873
50
550,178.5
698,209.3
$16,873
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 9 FLUX STANDARD - 2
SCENARIO - 1 THICKNESS?in meters) = 1.378
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCi/sec)
(pCi/see)
COST
1
1,200,790.0
841,112.2
$3,703,130
2
1,158,819,0
929,542.9
$49,588
3
1,115,519.0
1,020,773.0
$813,694
4
1,070,704.0
1,115,196,0
$58,680
5
1,024,134.0
1,213,317.0
$877,891
6
975,501.7
1,315,783.0
$69,201
7
924,381,0
1,423,492,0
$964,019
8
486,211.5
2,431,058.0
$5,345,845
9
486,211.5
2,431,058.0
$101,419
10
486,211.5
2,431,058.0
$101,419
11
486,211.5
2,431,058.0
$101,419
12
436,215.5
2,431,058.0
$101,419
13
486,211.5
2,431,058.0
$101,419
14
486,211.5
2,431,058.0
$101,419
15
486,211.5
2,431,058.0
$101,419
16
486,211.5
2,431,058.0
$101,419
17
486,211.5
2,431,058.0
$101,419
18
486,211.5
2,431,058.0
$101,419
19
486,211.5
2,431,058.0
$101,419
20
486,211.5
2,431,058.0
$101,419
21
486,211.5
2,431,058.0
$101,419
22
486,211.5
2,431,058.0
$101,419
23
486,211.5
2,431,058.0
$101,419
24
486,211.5
2,431,058.0
$101,419
25
486,211.5
2,431,058.0
$101,419
26
486,211,5
2,431,058.0
$101,419
27
486,211.5
2,431,058.0
$101,419
28
486,211.5
2,431,058,0
$101,419
29
486,211.5
2,431,058.0
$101,419
30
486,211.5
2,431,058.0
$101,419
31
486,211.5
2,431,058.0
$101,419
32
486,211.5
2,431,058.0
$101,419
33
486,211.5
2,431,058.0
$101,419
34
486,211.5
2,431,058.0
$101,419
35
486,211.5
2,431,058.0
$101,419
36
486,211.5
2,431,058.0
$101,419
37
486,211.5
2,431,058.0
$101,419
38
486,211.5
2,431,058.0
$101,419
39
486,211.5
2,431,058.0
$101,419
40
486,211.5
2,431,058.0
$101,419
41
486,211,5
2,431,058.0
$101,419
42
486,211.5
2,431,058.0
$101,419
43
486,211.5
2,431,058.0
$101,419
44
486,211.5
2,431,058.0
$101,419
45
486,211.5
2,431,058.0
$101,419
46
486,211.5
2,431,058.0
$101,419
47
486,211.5
2,431,058.0
$101,419
48
486,211.5
2,431,058.0
$101,419
49
486,211.5
2,431,058.0
$101,419
50
486,211.5
2,431,058.0
$101,419
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 10 FLUX STANDARD « 2
SCENARIO = 1 TH!CKNESS(in meters) = .779
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAS
(pCi/sec)
(pCi/sec)
COST
1
86,530.8
432,654.1
$1,617,673
2
86,530.8
432,654.1
$24,004
3
86,530.8
432,654.1
$24,004
4
86,530.8
432,654.1
$24,004
5
86,530.8
432,654.1
$24,004
6
86,530.8
432,654.1
$24,004
7
86,530.8
432,654.1
$24,004
8
86,530.8
432,654.1
$24,004
9
86,530.8
432,654.1
$24,004
10
86,530.8
432,654.1
$24,004
11
86,530.8
432,654.1
$24,004
12
86,530.8
432,654.1
$24,004
13
86,530.8
432,654.1
$24,004
14
86,530.8
432,654.1
$24,004
15
86,530.8
432,654.1
$24,004
16
86,530.8
432,654.1
$24,004
17
86,530.8
432,654.1
$24,004
18
86,530.8
432,654.1
$24,004
19
86,530.8
432,654.1
$24,004
20
86,530.8
432,654.1
$24,004
21
86,530,8
432,654.1
$24,004
22
86,530.8
432,654.1
$24,004
23
86,530.8
432,654.1
$24,004
24
86,530.8
432,654.1
$24,004
25
86,530.8
432,654.1
$24,004
26
86,530.8
432,654.1
$24,004
27
86,530.8
432,654.1
$24,004
28
86,530.8
432,654.1
$24,004
29
86,530.8
432,654.1
$24,004
30
86,530.8
432,654.1
$24,004
31
86,530.8
432,654.1
$24,004
32
86,530.8
432,654.1
$24,004
33
86,530.8
432,654.1
$24,004
34
86,530.8
432,654.1
$24,004
35
86,530.8
432,654.1
$24,004
36
86,530.8
432,654.1
$24,004
37
86,530.8
432,654.1
$24,004
38
86,530.8
432,654.1
$24,004
39
86,530.8
432,654.1
$24,004
40
86,530.8
432,654.1
$24,004
41
86,530.8
432,654.1
$24,004
42
86,530.8
432,654.1
$24,004
43
86,530.8
432,654.1
$24,004
44
86,530.8
432,654.1
$24,004
45
86,530.8
432,654.1
$24,004
46
86,530.8
432,654.1
$24,004
47
86,530.8
432,654.1
$24,004
48
86,530.8
432,654.1
$24,004
49
86,530.8
432,654.1
$24,004
50
86,530.8
432,654.1
$24,004
-------
APPENDIX TO CHAPTER 9
EFFECTS Of CONTROLS FOR STACK 11 FLUX STANDARD * 2
SCENARIO = 1 THICKNESS< in meters) = .814
EMISSIONS REMAINING REDUCTION IN EMISSIONS
YEAR
AFTER CONTROLS
CpCf/sec)
DUE TO CONTROLS
(pCi/sec)
ANNUAL
COST
1
7,231,534.0
8,165,137.0
$22,308,660
2
6,872,522.0
8,675,178.0
$470,067
3
3,216,295.0
16,081,480.0
$26,294,080
4
3,216,295.0
16,081,480.0
$712,741
5
3,216,295.0
16,081,480.0
$712,741
6
3,216,295.0
16,081,480.0
$712,741
7
3,216,295.0
16,081,480.0
$712,741
8
3.216,295.0
16,081,480.0
$712,741
9
3,216,295.0
16,081,480.0
$712,741
10
3,216,295.0
16,081,480.0
$712,741
11
3,216,295.0
16,081,480.0
$712,741
12
3,216,295.0
16,081,480.0
$712,741
13
3,216,295.0
16,081,480.0
$712,741
14
3,216,295.0
16,081,480.0
$712,741
15
3,216,295.0
16,081,480.0
$712,741
16
3,216,295.0
16,081,480.0
$712,741
1?
3,216,295.0
16,081,480.0
$712,741
18
3,216,295.0
16,081,480.0
$712,741
19
3,216,295.0
16,081,480.0
$712,741
20
3,216,295.0
16,081,480.0
$712,741
21
3,216,295.0
16,081,480.0
$712,741
22
3,216,295.0
16,081,480.0
$712,741
23
3,216,295.0
16,081,480.0
$712,741
24
3,216,295.0
16,061,480.0
$712,741
25
3,216,295.0
16,081,480.0
$712,741
26
3,216,295.0
16,081,480.0
$712,741
27
3,216,295.0
16,081,480.0
$712,741
28
3,216,295.0
16,081,480.0
$712,741
29
3,216,295,0
16,081,480.0
$712,741
30
3,216,295.0
16,081,480.0
$712,741
31
3,216,295.0
16,081,480.0
$712,741
32
3,216,295.0
16,081,480.0
$712,741
33
3,216,295.0
16,081,480.0
$712,741
34
3,216,295.0
16,081,480.0
$712,741
35
3,216,295.0
16,081,480.0
$712,741
36
3,216,295.0
16,081,480.0
$712,741
3?
3,216,295.0
16,081,480.0
$712,741
38
3,216,295.0
16,081,480.0
$712,741
39
3,216,295.0
16,081,480.0
$712,741
40
3,216,295.0
16,081,480.0
$712,741
41
3,216,295.0
16,081,480.0
$712,741
42
3,216,295.0
16,081,480.0
$712,741
43
3,216,295.0
16,081,480.0
$712,741
44
3,216,295.0
16,081,480.0
$712,741
45
3,216,295.0
16,081,480.0
$712,741
46
3,216,295.0
16,081,480.0
$712,741
47
3,216,295.0
16,081,480.0
$712,741
48
3,216,295.0
16,081,480.0
$712,741
49
3,216,295.0
16,081,480.0
$712,741
50
3,216,295.0
16,081,480.0
$712,741
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 12 FLUX STANDARD = 2
SCENARIO = 1 THICKNESS(in meters) = 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pel/sec)
CpCf/sec)
COST
1
476,006.1
1,019,749.0
$3,519,421
2
476,006.1
1,019,749.0
$39,430
3
476,006.1
1,019,749.0
*69,991
4
476,006.1
1,019,749.0
539,430
5
476,006.1
1,019,749.0
$39,430
6
476,006.1
1,019,749.0
$39,430
7
476,006.1
1,019,749.0
$39,430
8
476,006.1
1,019,749.0
$39,430
9
476,006.1
1,019,749.0
$39,430
10
476,006.1
1,019,749.0
$39,430
11
476,006.1
1,019,749.0
$39,430
12
476,006.1
1,019,749.0
$39,430
13
476,006.1
1,019,749.0
$39,430
14
476,006.1
1,019,749.0
$39,430
15
476,006.1
1,019,749.0
$39,430
16
476,006.1
1,019,749.0
$39,430
17
476,006.1
1,019,749.0
$39,430
18
476,006.1
1,019,749.0
$39,430
19
476,006.1
1,019,749.0
$39,430
20
476,006.1
1,019,749.0
$39,430
21
476,006.1
1,019,749.0
$39,430
22
476,006.1
1,019,749.0
$39,430
23
476,006.1
1,019,749.0
$39,430
24
476,006.1
1,019,749.0
$39,430
25
476,006.1
1,019,749.0
$39,430
26
476,006.1
1,019,749.0
$39,430
27
476,006,1
1,019,749.0
$39,430
28
476,006,1
1,019,749.0
*39,430
29
476,006.1
1,019,749.0
$39,430
30
476,006.1
1,019,749.0
$39,430
31
476,006.1
1,019,749.0
$39,430
32
476,006.1
1,019,749.0
$39,430
33
476,006.1
1,019,749.0
$39,430
34
476,006.1
1,019,749.0
$39,430
35
476,006.1
1,019,749.0
$39,430
36
476,006.1
1,019,749.0
$39,430
37
476,006.1
1,019,749.0
$39,430
38
476,006.1
1,019,749.0
$39,430
39
476,006.1
1,019,749.0
$39,430
40
476,006.1
1,019,749.0
$39,430
41
476,006.1
1,019,749.0
$39,430
42
476,006.1
1,019,749.0
$39,430
43
476,006.1
1,019,749.0
$39,430
44
476,006.1
1,019,749.0
$39,430
45
476,006.1
1,019,749.0
$39,430
46
476,006.1
1,019,749.0
$39,430
47
476,006.1
1,019,749.0
$39,430
48
476,006.1
1,019,749.0
$39,430
49
476,006.1
1,019,749.0
$39,430
50
476,006.1
1,019,749.0
$39,430
-------
APPEN01X 10 CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 13 FLUX STANDARD - 2
SCENARIO « 1 IHICKNESSCift meters) ¦ 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO C0BTR0U
ANNUAL
YEAR
(pci/sec)
(pCi/sec)
COST
1
814,036.0
1,318,877.0
$4,541,790
2
8?4,036.0
1,318,877.0
$50,997
3
814,036.0
1,318,877.0
$50,997
4
814,036.0
1,318,877.0
$50,997
5
814,036.0
1,318,877.0
$50,997
6
814,036.0
1,318,877.0
$50,997
7
814,036.0
1,318,877.0
$50,997
8
814,036.0
1,318,877.0
$50,997
9
814,036.0
1,318,877.0
$50,997
10
814,036.0
1,318,877.0
$50,997
11
814,036.0
1,318,877.0
$50,997
12
814,036.0
1,318,877.0
$50,997
13
814,036.0
1,318,877.0
$50,997
14
814,036.0
1,318,877.0
$50,997
15
814,036.0
1,318,877.0
$50,997
16
814,036.0
1,318,877.0
$50,997
17
814,036.0
1,318,877.0
$50,997
18
814,036.0
1,318,877.0
$50,997
19
814,036.0
1,318,877.0
$50,997
20
814,036.0
1,318,877.0
$50,997
21
814,036.0
1,318,877.0
$50,997
22
814,036.0
1,318,877.0
$50,997
23
814,036.0
1,318,877.0
$50,997
24
814,036.0
1,318,877.0
$50,997
25
814,036.0
1,318,877.0
$50,997
26
814,036.0
1,318,877.0
$50,997
27
814,036.0
1,318,877.0
$50,997
28
814,036.0
1,318,877.0
$50,997
29
814,036.0
1,318,877.0
$50,997
30
814,036.0
1,318,877.0
$50,997
31
814,036.0
1,318,877.0
$50,997
32
814,036.0
1,318,877.0
$50,997
33
814,036.0
1,318,877.0
$50,997
34
814,036.0
1,318,877.0
$50,997
35
814,036.0
1,318,877.0
$50,997
36
814,036.0
1,318,877.0
$50,997
37
814,036,0
1,318,877.0
$50,997
38
814,036.0
1,318,877.0
$50,997
39
814,036.0
1,318,877.0
$50,997
40
814,036.0
1,318,877.0
$50,997
41
814,036.0
1,318,877.0
$50,997
42
814,036.0
1,318,877.0
$50,997
43
814,036.0
1,318,877.0
$50,997
44
814,036.0
1,318,877.0
$50,997
45
814,036.0
1,318,877.0
$50,997
46
814,036.0
1,318,877.0
$50,997
47
814,036.0
1,318,877.0
$50,997
48
814,036.0
1,318,877.0
$50,997
49
814,036.0
1,318,877.0
$50,997
50
814,036.0
1,318,877.0
$50,997
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 14 FLUX STANDARD = 2
SCENARIO * 1 THICKNESSCin meters) « 1,054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
1,421,334.0
2,146,276.0
$7,385,325
2
737,686.8
3,688,433.0
$6,473,889
3
737,686.8
3,688,433.0
$154,915
4
737,686.8
3,688,433.0
$154,915
5
737,686.8
3,688,433.0
$154,915
6
737,686.8
3,688,433.0
$154,915
7
737,686.8
3,688,433.0
$154,915
8
737,686.8
3,688,433.0
$154,915
9
737,686.8
3,688,433.0
$154,915
10
737,686.8
3,688,433.0
$154,915
11
737,686.8
3,688,433.0
$154,915
12
737,686.8
3,688,433.0
$154,915
13
737,686.8
3,688,433.0
$154,915
14
737,686.8
3,688,433.0
$154,915
15
737,686.8
3,688,433.0
$154,915
16
737,686.8
3,688,433.0
$154,915
17
737,686.8
3,688,433.0
$154,915
18
737,686.8
3,688,433.0
$154,915
19
737,686.8
3,688,433.0
$154,915
20
737,686.8
3,688,433.0
$154,915
21
737,686.8
3,688,433.0
$154,915
22
737,686.8
3,688,433.0
$154,915
23
737,686.8
3,688,433.0
$154,915
24
737,686.8
3,688,433.0
$154,915
25
737,686.8
3,688,433.0
$154,915
26
737,686.8
3,688,433.0
$154,915
27
737,686.8
3,688,433.0
$154,915
28
737,686.8
3,688,433.0
$154,915
29
737,686.8
3,688,433.0
$154,915
30
737,686.8
3,688,433.0
$154,915
31
737,686.8
3,688,433.0
$154,915
32
737,686.8
3,688,433.0
$154,915
33
737,686.8
3,688,433.0
$154,915
34
737,686.8
3,688,433.0
$154,915
35
737,686.8
3,688,433.0
$154,915
36
737,686.8
3,688,433.0
$154,915
37
737,686.8
3,688,433.0
$154,915
38
737,686.8
3,688,433.0
$154,915
39
737,686.8
3,688,433.0
$154,915
40
737,686.8
3,688,433.0
$154,915
41
737,686.8
3,688,433.0
$154,915
42
737,686.8
3,688,433.0
$154,915
43
737,686.8
3,688,433.0
$154,915
44
737,686.8
3,688,433.0
$154,915
45
737,686.8
3,688,433.0
$154,915
46
737,686.8
3,688,433.0
$154,915
47
737,686.8
3,688,433.0
$154,915
48
737,686.8
3,688,433.0
$154,915
49
737,686.8
3,688,433.0
$154,915
50
737,686.8
3,688,433.0
$154,915
-------
APPEND 11 TO CHAPTER 9
EFFECTS Of CONTROLS FOR STACK 5 FLUX STANDARD = 2
SCENARIO = 2 THICKNESS*in meters) = .995
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCf/sec)
-------
APPEND IX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 6 FLUX STANDARD * 2
SCENARIO • 2 TH!CKNESS{in meters) = 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCi/sec)
tpCi/sec)
COST
1
8,345,288.0
0.0
SO
2
1,627,573.0
8,137,861.0
$38,486,910
3
1,627,573.0
8,137,861.0
$433,433
4
1,627,573.0
8,137,861.0
$433,433
5
1,627,573.0
8,137,861.0
$433,433
6
1,627,573.0
8,137,861.0
$433,433
7
1,627,573.0
8,137,861.0
$433,433
a
1,627,573.0
8,137,861.0
$433,433
9
1,627,573.0
8,137,861.0
$433,433
10
1,627,573.0
8,137,861.0
$433,433
11
1,627,573.0
8,137,861.0
$433,433
12
1,627,573.0
8,137,861.0
$433,433
13
1,627,573.0
8,137,861.0
$433,433
14
1,627,573.0
8,137,861.0
$433,433
15
1,627,573.0
8,137,861.0
$433,433
16
1,627,573.0
8,137,861.0
$433,433
17
1,627,573.0
8,137,861.0
$433,433
18
1,627,573.0
8,137,861.0
$433,433
19
1,627,573.0
8,137,861.0
$433,433
20
1,627,573.0
8,137,861.0
$433,433
21
1,627,573.0
8,137,861.0
$433,433
22
1,627,573.0
8,137,861.0
$433,433
23
1,627,573.0
8,137,861.0
$433,433
24
1,627,573.0
8,137,861.0
$433,433
25
1,627,573.0
8,137,861.0
$433,433
26
1,627,573.0
8,137,861.0
$433,433
27
1,627,573.0
8,137,861.0
$433,433
28
1,627,573.0
8,137,861.0
$433,433
29
1,627,573.0
8,137,861.0
$433,433
30
1,627,573.0
8,137,861.0
$433,433
31
1,627,573.0
8,137,861.0
$433,433
32
1,627,573.0
8,137,861.0
$433,433
33
1,627,573.0
8,137,861.0
$433,433
34
1,627,573.0
8,137,861.0
$433,433
35
1,627,573.0
8,137,861.0
$433,433
36
1,627,573.0
8,137,861.0
$433,433
37
1,627,573.0
8,137,861.0
$433,433
38
1,627,573.0
8,137,861.0
$433,433
39
1,627,573.0
8,137,861.0
$433,433
40
1,627,573.0
8,137,861.0
$433,433
41
1,627,573.0
8,137,861.0
$433,433
42
1,627,573.0
8,137,861.0
$433,433
43
1,627,573.0
8,137,861.0
$433,433
44
1,627,573.0
8,137,861.0
$433,433
45
1,627,573.0
8,137,861.0
$433,433
46
1,627,573.0
8,137,861.0
$433,433
47
1,627,573.0
8,137,861.0
$433,433
48
1,627,573.0
8,137,861.0
$433,433
49
1,627,173.0
8,137,861.0
$433,433
50
1,627,573.0
8,137,861.0
$433,433
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK ?
SCENARIO = 2
EMISSIONS REMAINING
AFTER CONTROLS
YEAR (pCS/sec)
FLUX STANDARD » 2
THICKHESSCin meters) = 1.054
REDUCTION IN EMISSIONS
DUE TO CONTROLS ANNUAL
(pCt/see) COST
1
1,475,431.0
7,377,153.0
$37,895,730
2
1,475,431.0
7,377,153.0
$426,823
3
1,475,431.0
7,377,153.0
$426,823
4
1,475,431,0
7,377,153.0
$426,823
5
1,475,431.0
7,377,153.0
$426,823
6
1.475,431.0
7,377,153.0
$426,823
7
1,475,431.0
7,377,153.0
$426,823
8
1,475,431.0
7,377,153.0
$426,823
9
1,475,431.0
7,377,153.0
$426,823
10
1,475,431.0
7,377,153.0
$426,823
11
1,475,431.0
7,377,153.0
$426,823
12
1,475,431.0
7,377,153.0
$426,823
13
1,475,431.0
7,377,153.0
$426,823
14
1,475,431.0
7,377,153.0
$426,823
15
1,475,431.0
7,377,153.0
$426,823
16
1,475,431.0
7,377,153.0
$426,823
17
1,475,431.0
7,377,153.0
$426,823
18
1,475,431.0
7,377,153.0
$426,823
19
1,475,431.0
7,377,153.0
$426,823
20
1,475,431.0
7,377,153.0
$426,823
21
1,475,431.0
7,377,153.0
$426,823
22
1,475,431.0
7,377,153.0
$426,823
23
1,475,431.0
7,377,153.0
$426,823
24
1,475,431.0
7,377,153.0
$426,823
25
1,475,431.0
7,377,153.0
$426,823
26
1,475,431.0
7,377,153.0
$426,823
27
1,475,431.0
7,377,153.0
$426,823
28
1,475,431.0
7,377,153.0
$426,823
29
1,475,431.0
7,377,153.0
$426,823
30
1,475,431.0
7,377,153.0
$426,823
31
1,475,431.0
7,377,153.0
$426,823
32
1,475,431.0
7,377,153.0
$426,823
33
1,475,431.0
7,377,153.0
$426,823
34
1,475,431.0
7,377,153.0
$426,823
35
1,475,431.0
7,377,153.0
$426,823
36
1,475,431.0
7,377,153.0
$426,823
37
1,475,431.0
7,377,153.0
$426,823
38
1,475,431.0
7,377,153.0
$426,823
39
1,475,431.0
7,377,153.0
$426,823
40
1,475,431.0
7,377,153.0
$426,823
41
1,475,431.0
7,377,153.0
$426,823
42
1,475,431.0
7,377,153.0
$426,823
43
1,475,431.0
7,377,153.0
$426,823
44
1,475,431.0
7,377,153.0
$426,823
45
1,475,431.0
7,377,153.0
$426,823
46
1,475,431.0
7,377,153.0
$426,823
47
1,475,431.0
7,377,153.0
$426,823
48
1,475,431.0
7,377,153.0
$426,823
49
1,475,431.0
7,377,153.0
$426,823
50
1,475,431.0
7,377,153.0
$426,823
-------
APPENDIX TO CHAPTER 9
EFFECTS Of CONTROLS FOR STACK 8 FLUX STANDARD = 2
SCENARIO = 2 THICKNESS?irt meters) » 2.344
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
{
(pCf/sec)
(pCi/sec)
COST
1
1,248,388.0
0.0
$0
2
1,248,388.0
0.0
so
3
1,248,388.0
0.0
so
4
1,248,388.0
0.0
so
5
1,248,388.0
0.0
$0
6
1,248,388.0
0.0
$0
7
1,248,388.0
0.0
so
8
1,248,388.0
0.0
so
9
1,248,388.0
0.0
so
10
1,248,388.0
0.0
so
11
1,248,388.0
0.0
so
12
1,248,388.0
0.0
so
13
1,248,388.0
0.0
so
14
1,248,388.0
0.0
so
15
1,248,388.0
0.0
so
16
1,248,388.0
0.0
so
17
1,248,388.0
0.0
so
18
1,248,388.0
0.0
so
19
1,248,388.0
0.0
so
20
1,248,388.0
0.0
so
21
1,248,388.0
0.0
so
22
1,248,388.0
0.0
$0
23
1,248,388.0
0.0
so
24
1,248,388.0
0.0
$0
25
1,248,388.0
0.0
so
26
1,248,388.0
0.0
so
27
1,248,388.0
0.0
so
28
1,248,388.0
0.0
so
29
1,248,388.0
0.0
$0
30
1,248,388.0
0,0
so
31
1,248,388.0
0.0
so
32
1,248,388.0
0.0
so
33
1,248,388.0
0.0
so
34
1,248,388.0
0.0
so
35
1,248,388.0
0.0
so
36
1,248,388.0
0.0
so
37
1,248,388.0
0.0
so
38
1,248,388.0
0.0
so
39
1,248,388.0
0.0
so
40
1,248,388.0
0.0
so
41
1,248,388.0
0.0
so
42
1,248,388.0
0.0
so
43
1,248,388.0
0.0
so
44
1,248,388.0
0.0
so
45
1,248,388.0
0.0
so
46
1,248,388.0
0.0
so
47
1,248,388.0
0.0
so
48
1,248,388.0
0.0
so
49
1,248,388.0
0.0
so
50
1,248,388.0
0.0
so
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 9 FLUX STANDARD = 2
SCENARIO = 2 rmcKUBSSCin meters) = 1.378
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAS
CpCf/sec)
(pCi/sec)
COST
1
2,041,902.0
0.0
SO
2
2,088,362.0
0.0
SO
3
2,136,292.0
0.0
SO
4
2,185,900.0
0.0
$0
5
2,237,451.0
0.0
SO
6
2,291,285.0
0.0
$0
7
2,347,873.0
0.0
SO
a
486,211.5
2,431,058.0
S11,578,160
9
486,211.5
2,431,058.0
$101,419
10
486,211.5
2,431,058,0
$101,419
11
486,211.5
2,431,058.0
$101,419
12
486,211.5
2,431,058.0
$101,419
13
486,211.5
2,431,058.0
$101,419
14
486,211.5
2,431,058.0
$101,419
15
486,211.5
2,431,058.0
$101,419
16
486,211.5
2,431,058,0
$101,419
17
486,211.5
2,431,058.0
$101,419
18
486,211.5
2,431,058.0
$101,419
19
486,211.5
2,431,058.0
$101,419
20
486,211.5
2,431,058.0
$101,419
21
486,211.5
2,431,058,0
$101,419
22
486,211.5
2,431,058.0
$101,419
23
486,211.5
2,431,058.0
$101,419
24
486,211.5
2,431,058.0
$101,419
25
486,211.5
2,431,058.0
$101,419
26
486,211.5
2,431,058.0
$101,419
27
486,211.5
2,431,058.0
$101,419
28
486,211.5
2,431,058.0
$101,419
29
486,211.5
2,431,058.0
$101,419
30
486,211.5
2,431,058.0
$101,419
31
486,211.5
2,431,058.0
$101,419
32
486,211.5
2,431,058.0
$101,419
33
486,211.5
2,431,058.0
$101,419
34
486,211.5
2,431,058.0
$101,419
35
486,211.5
2,431,058.0
$101,419
36
486,211.5
2,431,058.0
$101,419
37
486,211.5
2,431,058.0
$101,419
38
486,211.5
2,431,058.0
$101,419
39
486,211.5
2,431,058.0
$101,419
40
486,211.5
2,431,058.0
$101,419
41
486,211.5
2,431,058.0
$101,419
42
486,211.5
2,431,058.0
$101,419
43
486,211.5
2,431,058.0
$101,419
44
486,211.5
2,431,058.0
$101,419
45
486,211.5
2,431,058.0
$101,419
46
486,211.5
2,431,058.0
$101,419
47
486,211.5
2,431,058.0
$101,419
48
486,211.5
2,431,058.0
$101,419
49
486,211.5
2,431,058.0
$101,419
50
486,211.5
2,431,058.0
$101,419
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 10 FLUX STANDARD * 2
SCENARIO = 2 THICKNESS(in meters) « .779
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
86,530.8
432,654.1
$1,617,673
2
86,530.8
432,654.1
$24,004
3
86,530.8
432,654.1
$24,004
4
86,530.8
432,654.1
$24,004
5
86,530.8
432,654.1
$24,004
6
86,530.8
432,654.1
$24,004
7
86,530.8
432,654.1
$24,004
8
86,530.8
432,654.1
$24,004
9
86,530.8
432,654.1
$24,004
10
86,530.8
432,654.1
$24,004
11
86,530.8
432,654.1
$24,004
12
86,530.8
432,654.1
$24,004
13
86,530.8
432,654.1
$24,004
14
86,530.8
432,654,1
$24,004
15
86,530.8
432,654.1
$24,004
16
86,530.8
432,654.1
$24,004
17
86,530.8
432,654.1
$24,004
18
86,530.8
432,654.1
$24,004
19
86,530.8
432,654.1
$24,004
20
86,530.8
432,654.1
$24,004
21
86,530.8
432,654.1
$24,004
22
86,530.8
432,654.1
$24,004
23
86,530.8
432,654.1
$24,004
24
86,530.8
432,654.1
$24,004
25
86,530.8
432,654.1
$24,004
26
86,530.8
432,654.1
$24,004
27
86,530.8
432,654.1
$24,004
28
86,530.8
432,654.1
$24,004
29
86,530.8
432,654.1
$24,004
30
86,530.8
432,654.1
$24,004
31
86,530.8
432,654.1
$24,004
32
86,530.8
432,654.1
$24,004
33
86,530.8
432,654.1
$24,004
34
86,530.8
432,654.5
$24,004
35
86,530.8
432,654.1
$24,004
36
86,530.8
432,654.1
$24,004
37
86,530.8
432,654.1
$24,004
38
86,530.8
432,654.1
$24,004
39
86,530.8
432,654.1
$24,004
40
86,530.8
432,654,1
$24,004
41
86,530.8
432,654.1
$24,004
42
86,530.8
432,654.1
$24,004
43
86,530.8
432,654.1
$24,004
44
86,530.8
432,654.1
$24,004
45
86,530.8
432,654.1
$24,004
46
86,530.8
432,654.1
$24,004
47
86,530.8
432,654.1
$24,004
48
86,530.8
432,654.1
$24,004
49
86,530.8
432,654.1
$24,004
50
86,530.8
432,654.1
$24,004
-------
APPENDIK TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 12 FLUX STANDARD » 2
SCENARIO a 2 THICKNESS(in meters) a 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER COMTROLS
DUE TO CONTROLS
AKNUAL
(pCi/sec)
(pci/see)
COST
1
1,495,756.0
0.0
$0
2
1,495,756.0
0.0
$0
3
1,495,756.0
0.0
so
4
1,495,756.0
0.0
so
5
1,495,756.0
0,0
so
6
1,495,756.0
0.0
so
7
1,495,756.0
0.0
so
8
1,495,756.0
0.0
so
9
1,495,756.0
0.0
so
10
1,495,756.0
0.0
so
11
1,495,756.0
0.0
so
12
1,495,756.0
0.0
so
13
1,495,756.0
0.0
so
14
1,495,756.0
0.0
so
15
1,495,756.0
0.0
so
16
1,495,756.0
0.0
so
17
1,495,756.0
0.0
so
18
1,495,756.0
0.0
so
19
1,495,756.0
0.0
so
20
1,495,756.0
0.0
so
21
1,495,756.0
0.0
so
22
1,495,756.0
0.0
$0
23
1,495,756.0
0.0
so
24
1,495,756.0
0.0
so
25
1,495,756.0
0.0
so
26
1,495,756.0
0.0
so
27
1,495,756.0
0.0
$0
28
1,495,756.0
0.0
so
29
1,495,756.0
0.0
$0
30
1,495,756.0
0.0
so
31
1,495,756.0
0.0
so
32
1,495,756.0
0.0
so
33
1,495,756.0
0.0
so
34
1,495,756.0
0.0
so
35
1,495,756.0
0.0
so
36
1,495,756.0
0.0
so
37
1,495,756.0
0.0
so
38
1,495,756.0
0.0
so
39
1,495,756.0
0.0
so
40
1,495,756.0
0.0
so
41
1,495,756.0
0.0
so
42
1,495,756.0
0.0
so
43
1,495,756.0
0.0
so
44
1,495,756.0
0.0
so
45
1,495,756.0
0.0
so
46
1,495,756.0
0.0
so
47
1,495,756.0
0.0
so
48
1,495,756.0
0.0
so
49
1,495,756.0
0.0
so
50
1,495,756.0
0.0
so
-------
APPENDIX ¥0 CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 11 FLUX STANDARD = 2
SCENARIO = 2 THICKNESSCirt meters) = .814
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DOE TO CONTROLS
ANNUAL
YEAR
CpCi/sec)
(pCi/sec)
COST
t
15,396,670.0
0.0
$0
2
15,747,700.0
0.0
SO
3
3,216,295.0
16,081,480.0
850,212,090
4
3,216,295.0
16,081,480.0
$712,741
5
3,216,295.0
16,081,480.0
$712,741
6
3,216,295.0
16,081,480.0
$712,741
7
3,216,295.0
16,081,480.0
$712,741
8
3,216,295.0
16,081,480.0
$712,741
9
3,216,295.0
16,081,480.0
$712,741
10
3,216,295.0
16,081,480.0
$712,741
11
3,216,295.0
16,081,480.0
$712,741
12
3,216,295.0
16,081,480.0
$712,741
13
3,216,295.0
16,081,480.0
$712,741
14
3,216,295.0
16,081,480.0
$712,741
15
3,216,295.0
16,081,480.0
$712,741
16
3,216,295.0
16,081,480.0
$712,741
17
3,216,295.0
16,081,480.0
$712,741
18
3,216,295.0
16,081,480.0
$712,741
19
3,216,295.0
16,081,480.0
$712,741
20
3,216,295.0
16,081,480.0
$712,741
21
3,216,295.0
16,081,480.0
$712,741
22
3,216,295.0
16,081,480.0
$712,741
23
3,216,295.0
16,081,480.0
$712,741
24
3,216,295.0
16,081,480.0
$712,741
25
3,216,295.0
16,081,480.0
$712,741
26
3,216,295.0
16,081,480.0
$712,741
27
3,216,295.0
16,081,480.0
$712,741
28
3,216,295.0
16,081,480.0
$712,741
29
3,216,295.0
16,081,480.0
$712,741
30
3,216,295.0
16,081,480.0
$712,741
31
3,216,295.0
16,081,480.0
$712,741
32
3,216,295.0
16,081,480.0
$712,741
33
3,216,295.0
16,081,480.0
$712,741
34
3,216,295.0
16,081,480.0
$712,741
35
3,216,295.0
16,081,480.0
$712,741
36
3,216,295.0
16,081,480.0
$712,741
37
3,216,295.0
16,081,480.0
$712,741
38
3,216,295.0
16,081,480.0
$712,741
39
3,216,295.0
16,081,480.0
$712,741
40
3,216,295.0
16,081,480.0
$712,741
41
3,216,295.0
16,081,480.0
$712,741
42
3,216,295.0
16,081,480.0
$712,741
43
3,216,295.0
16,081,480.0
$712,741
44
3,216,295.0
16,081,480.0
$712,741
45
3,216,295.0
16,081,480.0
$712,741
46
3,216,295.0
16,081,480.0
$712,741
47
3,216,295.0
16,081,480.0
$712,741
48
3,216,295.0
16,081,480.0
$712,741
49
3,216,295.0
16,081,480.0
$712,741
SO
3,216,295.0
16,081,480.0
$712,741
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 13 FLUX STANDARD - 2
SCENARIO = 2 THlCKNESSCin meters) = 1.054
EMISSIONS REMAINING REDUCTION IN EMISSIONS
AFTER CONTROLS DUE TO CONTROLS ANNUAL
YEAR (pCi/sec) (pCi/sec) COST
1
2,132,913.0
0.0
so
2
2,132,913.0
0.0
so
3
2,132,913.0
0.0
so
4
2,132,913.0
0.0
to
5
2,132,913.0
0.0
so
6
2,132,913.0
0.0
so
7
2,132,913.0
0.0
so
8
2,132,913.0
0.0
so
9
2,132,913.0
0.0
so
10
2,132,913.0
0.0
so
11
2,132,913.0
0.0
so
12
2,132,913.0
0.0
so
13
2,132,913.0
0.0
so
14
2,132,913.0
0.0
so
15
2,132,913.0
0.0
so
16
2,132,913.0
0.0
$0
17
2,132,913.0
0.0
so
18
2,132,913.0
0.0
so
19
2,132,913.0
0.0
$0
20
2,132,913.0
0.0
so
21
2,132,913.0
0.0
so
22
2,132,913.0
0.0
so
23
2,132,913.0
0.0
so
24
2,132,913.0
0.0
so
25
2,132,913.0
0.0
so
26
2,132,913.0
0.0
so
27
2,132,913.0
0.0
so
28
2,132,913.0
0.0
$0
29
2,132,913.0
0.0
so
30
2,132,913.0
0.0
so
31
2,132,913.0
0.0
so
32
2,132,913.0
0.0
so
33
2,132,913.0
0.0
so
34
2,132,913.0
0.0
so
35
2,132,913.0
0.0
so
36
2,132,913.0
0.0
so
37
2,132,913.0
0.0
so
38
2,132,913.0
0.0
so
39
2,132,913.0
0.0
so
40
2,132,913.0
0.0
so
41
2,132,913.0
0.0
so
42
2,132,913.0
0.0
so
43
2,132,913.0
0.0
so
44
2,132,913.0
0.0
so
45
2,132,913.0
0.0
so
46
2,132,913.0
0.0
so
47
2,132,913.0
0.0
so
48
2,132,913.0
0.0
so
49
2,132,913.0
0.0
so
50
2,132,913.0
0.0
so
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 14 FLUX STANDARD * 2
SCENARIO * 2 THICKNESS? »r> meters) ¦ 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec}
COST
1
3,567,610.0
0.0
$0
2
737,686.8
3,688,433.0
$13,776,220
3
737,686.8
3,688,433.0
§154,915
4
737,686.8
3,688,433.0
$154,915
5
737,686.8
3,688,433.0
$154,915
6
737,686.8
3,688,433.0
$154,915
7
737,686.8
3,688,433.0
$154,915
8
737,686.8
3,688,433.0
$154,915
9
737,686.8
3,688,433.0
$154,915
10
737,686.8
3,688,433,0
$154,915
11
737,686.8
3,688,433.0
$154,915
12
737,686.8
3,688,433.0
$154,915
13
737,686.8
3,688,433.0
$154,915
14
737,686.8
3,688,433.0
$154,915
15
737,686.8
3,688,433.0
$154,915
16
737,686.8
3,688,433.0
$154,915
17
737,686.8
3,688,433.0
$154,915
18
737,686.8
3,688,433.0
$154,915
19
737,686.8
3,688,433.0
$154,915
20
737,686.8
3,688,433.0
$154,915
21
737,686.8
3,688,433.0
$154,915
22
737,686.8
3,688,433.0
$154,915
23
737,686.8
3,688,433.0
$154,915
24
737,686.8
3,688,433.0
$154,915
25
737,686.8
3,688,433.0
$154,915
26
737,686.8
3,688,433.0
$154,915
27
737,686.8
3,688,433.0
$154,915
28
737,686.8
3,688,433.0
$154,915
29
737,686.8
3,688,433.0
$154,915
30
737,686.8
3,688,433.0
$154,915
31
737,686.8
3,688,433.0
$154,915
32
737,686.8
3,688,433.0
$154,915
33
737,686.8
3,688,433.0
$154,915
34
737,686.8
3,688,433.0
$154,915
35
737,686.8
3,688,433.0
$154,915
36
737,686.8
3,688,433.0
$154,915
37
737,686.8
3,688,433.0
$154,915
38
737,686.8
3,688,433.0
$154,915
39
737,686.8
3,688,433.0
$154,915
40
737,686.8
3,688,433.0
$154,915
41
737,686.8
3,688,433.0
$154,915
42
737,686.8
3,688,433.0
$154,915
43
737,686.8
3,688,433.0
$154,915
44
737,686.8
3,688,433.0
$154,915
45
737,686.8
3,688,433.0
$154,915
46
737,686.8
3,688,433.0
$154,915
47
737,686.8
3,688,433.0
$154,915
48
737,686.8
3,688,433.0
$154,915
49
737,686.8
3,688,433.0
$154,915
50
737,686.8
3,688,433.0
$154,915
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 1 FLUX STANDARD « 6
SCENARIO = 1 THICKNESSCin meters) = .385
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 2 FLUX STANDARD = 6
SCENARIO « 1 THICKNESSCin meters) = .385
EMISSIONS REMAINING
REDUCTION IK EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCl/sec>
(pCi/sec)
COST
1
1,235,009.0
361,758.9
$852,614
2
1,229,134.0
409,002.3
$91,304
3
1,223,062.0
457,827.8
$240,901
4
1,216,763.0
508,474.0
$46,429
5
1,210,200.0
561,244.8
$264,900
6
1,203,322.0
616,552.8
$56,025
7
1,196,057.0
674,966.1
$296,885
8
1,160,500.0
1,160,501.0
$1,434,479
9
1,160,500.0
1,160,501.0
$81,277
10
1,160,500.0
1,160,501.0
$81,277
11
1,160,500.0
1,160,501.0
$81,277
12
1,160,500.0
1,160,501.0
$81,277
13
1,160,500.0
1,160,501.0
$81,277
14
1,160,500.0
1,160,501.0
$81,277
15
1,160,500.0
1,160,501.0
$81,277
16
1,160,500.0
1,160,501.0
$81,277
17
1,160,500.0
1,160,501.0
$81,277
18
1,160,500.0
1,160,501.0
$81,277
19
1,160,500.0
1,160,501.0
$81,277
20
1,160,500.0
1,160,501.0
$81,277
21
1,160,500.0
1,160,501.0
$81,277
22
1,160,500.0
1,160,501.0
$81,277
23
1,160,500.0
1,160,501.0
$81,277
24
1,160,500.0
1,160,501.0
$81,277
25
1,160,500.0
1,160,501.0
$81,277
26
1,160,500.0
1,160,501.0
$81,277
27
1,160,500.0
1,160,501.0
$81,277
28
1,160,500.0
1,160,501.0
$81,277
29
1,160,500.0
1,160,501.0
$81,277
30
1,160,500.0
1,160,501.0
$81,277
31
1,160,500.0
1,160,501.0
$81,277
32
1,160,500.0
1,160,501.0
$81,277
33
1,160,500.0
1,160,501.0
$81,277
34
1,160,500.0
1,160,501.0
$81,277
35
1,160,500.0
1,160,501.0
$81,277
36
1,160,500.0
1,160,501.0
$81,277
37
1,160,500.0
1,160,501.0
$81,277
38
1,160,500.0
1,160,501.0
$81,277
39
1,160,500.0
1,160,501.0
$81,277
40
1,160,500.0
1,160,501.0
$81,277
41
1,160,500.0
1,160,501.0
$81,277
42
1,160,500.0
1,160,501.0
$81,277
43
1,160,500.0
1,160,501.0
$81,277
44
1,160,500.0
1,160,501.0
$81,277
45
1,160,500.0
1,160,501.0
$81,277
46
1,160,500.0
1,160,501.0
$81,277
47
1,160,500.0
1,160,501.0
$81,277
48
1,160,500.0
1,160,501.0
$81,277
49
1,160,500.0
1,160,501.0
$81,277
50
1,160,500.0
1,160,501.0
$81,277
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 3 FLUX STANDARD « &
SCENARIO = 1 THlCKNESSO'n meters) » .333
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
354,356.6
291,323.3
$4,635,814
2
354,356.6
291,323.3
$141,610
3
354,356.6
291,323.3
$141,610
4
354,356.6
291,323.3
$141,610
5
354,356.6
291,323.3
$141,610
6
354,356.6
291,323.3
$141,610
7
354,356.6
291,323.3
$141,610
8
354,356.6
291,323.3
$141,610
9
354,356.6
291,323.3
$141,610
10
354,356.6
291,323.3
$141,610
11
354,356.6
291,323.3
$141,610
12
354,356.6
291,323.3
$141,610
13
354,356.6
291,323.3
$141,610
14
354,356.6
291,323.3
$141,610
15
354,356.6
291,323.3
$141,610
16
354,356.6
291,323.3
$141,610
17
354,356.6
291,323.3
$141,610
18
354,356.6
291,323.3
$141,610
19
354,356.6
291,323.3
$141,610
20
354,356.6
291,323.3
$141,610
21
354,356.6
291,323.3
$141,610
22
354,356.6
291,323.3
$141,610
23
354,356.6
291,323.3
$141,610
24
354,356.6
291,323.3
$141,610
25
354,356.6
291,323.3
$141,610
26
354,356.6
291,323.3
$141,610
2?
354,356.6
291,323.3
$141,610
28
354,356,6
291,323.3
$141,610
29
354,356.6
291,323.3
$141,610
30
354,356.6
291,323.3
$141,610
31
354,356.6
291,323.3
$141,610
32
354,356.6
291,323.3
$141,610
33
354,356.6
291,323.3
$141,610
34
354,356.6
291,323.3
$141,610
35
354,356.6
291,323.3
$141,610
36
354,356.6
291,323.3
$141,610
3?
354,356.6
291,323.3
$141,610
38
354,356.6
291,323.3
$141,610
39
354,356.6
291,323.3
$141,610
40
354,356.6
291,323.3
$141,610
41
354,356.6
291,323.3
$141,610
42
354,356.6
291,323.3
$141,610
43
354,356.6
291,323.3
$141,610
44
354,356.6
291,323.3
$141,610
45
354,356.6
291,323.3
$141,610
46
354,356.6
291,323.3
$141,610
47
354,356.6
291,323.3
$141,610
48
354,356.6
291,323.3
$141,610
49
354,356.6
291,323.3
$141,610
SO
354,356.6
291,323.3
$141,610
-------
APPENOiX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 4 FLUX STANDARD = 6
SCENARIO = 1 THICKNESS(in meters) » .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
3,528,548.0
1,217,779.0
$3,103,321
2
2,779,089.0
2,779,090.0
$6,541,975
3
2,779,089.0
2,779,090.0
$246,010
4
2,779,089.0
2,779,090.0
$246,010
5
2,779,089.0
2,779,090.0
$246,010
6
2,779,089.0
2,779,090.0
$246,010
7
2,779,089.0
2,779,090.0
$246,010
8
2,779,089.0
2,779,090.0
$246,010
9
2,779,089.0
2,779,090.0
$246,010
10
2,779,089.0
2,779,090.0
$246,010
11
2,779,089.0
2,779,090.0
$246,010
12
2,779,089.0
2,779,090.0
$246,010
13
2,779,089.0
2,779,090.0
$246,010
14
2,779,089.0
2,779,090,0
$246,010
15
2,779,089.0
2,779,090.0
$246,010
16
2,779,089.0
2,779,090.0
$246,010
17
2,779,089.0
2,779,090.0
$246,010
18
2,779,089.0
2,779,090.0
$246,010
19
2,779,089.0
2,779,090.0
$246,010
20
2,779,089.0
2,779,090.0
$246,010
21
2,779,089.0
2,779,090.0
$246,010
22
2,779,089.0
2,779,090.0
$246,010
23
2,779,089.0
2,779,090.0
$246,010
24
2,779,089.0
2,779,090.0
$246,010
25
2,779,089.0
2,779,090.0
$246,010
26
2,779,089.0
2,779,090.0
$246,010
27
2,779,089.0
2,779,090.0
$246,010
28
2,779,089.0
2,779,090.0
$246,010
29
2,779,089.0
2,779,090.0
$246,010
30
2,779,089.0
2,779,090.0
$246,010
31
2,779,089.0
2,779,090.0
$246,010
32
2,779,089.0
2,779,090.0
$246,010
33
2,779,089.0
2,779,090.0
$246,010
34
2,779,089.0
2,779,090.0
$246,010
35
2,779,089.0
2,779,090.0
$246,010
36
2,779,089.0
2,779,090.0
$246,010
37
2,779,089.0
2,779,090.0
$246,010
38
2,779,089.0
2,779,090,0
$246,010
39
2,779,089.0
2,779,090.0
$246,010
40
2,779,089.0
2,779,090.0
$246,010
41
2,779,089.0
2,779,090.0
$246,010
42
2,779,089.0
2,779,090.0
$246,010
43
2,779,089.0
2,779,090.0
$246,010
44
2,779,089.0
2,779,090.0
$246,010
45
2,779,089.0
2,779,090.0
$246,010
46
2,779,089.0
2,779,090.0
$246,010
47
2,779,089.0
2,779,090.0
$246,010
48
2,779,089.0
2,779,090.0
$246,010
49
2,779,089.0
2,779,090.0
$246,010
50
2,779,089.0
2,779,090.0
$246,010
-------
APPEND!X TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 5
SCENARIO = 1
FLUX STANDARD - 6
THJCKNESS(in meters)
.385
YEAR
EMISSIONS REMAINING
AFTER CONTROLS
(pCi/sec)
REDUCTION IN EMISSIONS
DUE TO CONTROLS ANNUAL
CpCi/see) COST
1
5,416,056.0
1,479,084.0
83,483,082
2
5,404,475.0
1,572,200.0
$238,847
3
5,392,733.0
1,666,614.0
$518,745
4
5,380,822.0
1,762,389.0
$137,726
5
5,368,730.0
1,859,620.0
$543,930
6
5,356,448.0
1,958,376.0
$151,884
7
5,343,961.0
2,058,781.0
$571,147
8
5,331,256.0
2,160,940.0
$166,738
9
5,318,316.0
2,264,987.0
$600,966
10
5,305,124.0
2,371,062.0
$182,426
11
5,291,658.0
2,479,343.0
$634,008
12
5,277,893.0
2,590,023.0
$199,164
13
5,263,803.0
2,703,323.0
*671,273
14
5,249,352.0
2,819,517.0
$217,249
15
4,974,273.0
4,974,273.0
$6,667,811
16
4,974,273.0
4,974,273.0
$357,865
17
4,974,273.0
4,974,273.0
$357,865
18
4,974,273.0
4,974,273.0
$357,865
19
4,974,273.0
4,974,273.0
$357,865
20
4,974,273.0
4,974,273.0
$357,865
21
4,974,273.0
4,974,273.0
$357,865
22
4,974,273.0
4,974,273.0
$357,865
23
4,974,273.0
4,974,273.0
$357,865
24
4,974,273.0
4,974,273.0
$357,865
25
4,974,273.0
4,974,273.0
$357,865
26
4,974,273.0
4,974,273.0
$357,865
27
4,974,273.0
4,974,273.0
$357,865
28
4,974,273.0
4,974,273.0
$357,865
29
4,974,273.0
4,974,273.0
$357,865
30
4,974,273.0
4,974,273.0
$357,865
31
4,974,273.0
4,974,273.0
$357,865
32
4,974,273.0
4,974,273.0
$357,865
33
4,974,273.0
4,974,273.0
$357,865
34
4,974,273.0
4,974,273.0
$357,865
35
4,974,273.0
4,974,273.0
$357,865
36
4,974,273.0
4,974,273.0
$357,865
37
4,974,273.0
4,974,273.0
$357,865
38
4,974,273.0
4,974,273.0
$357,865
39
4,974,273.0
4,974,273.0
$357,865
40
4,974,273.0
4,974,273.0
$357,865
41
4,974,273.0
4,974,273.0
$357,865
42
4,974,273.0
4,974,273.0
$357,865
43
4,974,273.0
4,974,273.0
$357,865
44
4,974,273.0
4,974,273.0
$357,865
45
4,974,273.0
4,974,273.0
$357,865
46
4,974,273.0
4,974,273.0
$357,865
47
4,974,273.0
4,974,273.0
$357,865
48
4,974,273.0
4,974,273.0
$357,865
49
4,974,273.0
4,974,273.0
$357,865
50
4,974,273.0
4,974,273.0
$357,865
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 6 FLUX STANDARD « 6
SCENARIO a 1 THlCKNESS(in meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
BUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
6,215,071.0
2,130,217.0
$5,271,046
2
4,882,716.0
4,882,717.0
$11,563,100
3
4,882,716.0
4,882,717.0
*433,433
4
4,882,716.0
4,882,717.0
$433,433
5
4,882,716.0
4,882,717.0
$433,433
6
4,882,716.0
4,882,717.0
$433,433
7
4,882,716.0
4,882,717.0
$433,433
8
4,882,716.0
4,882,717.0
$433,433
9
4,882,716,0
4,882,717.0
$433,433
10
4,882,716.0
4,882,717.0
$433,433
11
4,882,716.0
4,882,717.0
$433,433
12
4,882,716.0
4,882,717.0
$433,433
13
4,882,716.0
4,882,717.0
$433,433
14
4,882,716.0
4,882,717.0
$433,433
15
4,882,716.0
4,882,717.0
$551,851
16
4,882,716.0
4,882,717.0
$433,433
17
4,882,716.0
4,882,717.0
$433,433
18
4,882,716.0
4,882,717.0
$433,433
19
4,882,716.0
4,882,717.0
$433,433
20
4,882,716,0
4,882,717.0
$433,433
21
4,882,716.0
4,882,717.0
$433,433
22
4,882,716.0
4,882,717,0
$433,433
23
4,882,716.0
4,882,717.0
$433,433
24
4,882,716.0
4,882,717.0
$433,433
25
4,882,716.0
4,882,717.0
$433,433
26
4,882,716.0
4,882,717.0
$433,433
27
4,882,716.0
4,882,717.0
$433,433
28
4,882,716.0
4,882,717.0
$433,433
29
4,882,716.0
4,882,717.0
$433,433
30
4,882,716.0
4,882,717.0
$433,433
31
4,882,716.0
4,882,717.0
$433,433
32
4,882,716.0
4,882,717.0
$433,433
33
4,882,716.0
4,882,717.0
$433,433
34
4,882,716.0
4,882,717.0
$433,433
35
4,882,716.0
4,882,717.0
$433,433
36
4,882,716.0
4,882,717.0
$433,433
37
4,882,716.0
4,882,717.0
$433,433
38
4,882,716.0
4,882,717.0
$433,433
39
4,882,716.0
4,882,717.0
$433,433
40
4,882,716.0
4,882,717.0
$433,433
41
4,882,716.0
4,882,717.0
$433,433
42
4,882,716.0
4,882,717.0
$433,433
43
4,882,716.0
4,882,717.0
$433,433
44
4,882,716.0
4,882,717.0
$433,433
45
4,882,716.0
4,882,717.0
$433,433
46
4,882,716.0
4,882,717.0
*433,433
47
4,882,716.0
4,882,717.0
$433,433
48
4,882,716.0
4,882,717.0
$433,433
49
4,882,716.0
4,882,717.0
$433,433
50
4,882,716.0
4,882,717.0
$433,433
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 7 FLUX STANDARD a 6
SCENARIO = 1 THICKNESS*in meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
{pCi/sec}
tpCi/sec)
COST
1
4,426,291.0
4,426,293.0
$16,437,950
2
4,426,291.0
4,426.293.0
$549,788
3
4,426,291.0
4,426,293.0
8426,823
4
4,426,291.0
4,426,293.0
$426,823
5
4,426,291.0
4,426,293.0
8426,823
6
4,426,291.0
4,426,293.0
$426,823
7
4,426,291.0
4,426,293.0
$426,823
8
4,426,291.0
4,426,293.0
$426,823
9
4,426,291.0
4,426,293.0
$426,823
10
4,426,291.0
4,426,293.0
$426,823
11
4,426,291.0
4,426,293.0
$426,823
12
4,426,291.0
4,426,293.0
$426,823
13
4,426,291.0
4,426,293.0
$426,823
14
4,426,291.0
4,426,293.0
$426,823
IS
4,426,291.0
4,426,293.0
$426,823
16
4,426,291.0
4,426,293.0
$426,823
1?
4,426,291.0
4,426,293.0
$426,823
18
4,426,291,0
4,426,293.0
$426,823
19
4,426,291.0
4,426,293.0
$426,823
20
4,426,291.0
4,426,293.0
$426,823
21
4,426,291.0
4,426,293.0
$426,823
22
4,426,291.0
4,426,293.0
$426,823
23
4,426,291.0
4,426,293.0
$426,823
24
4,426,291.0
4,426,293.0
$426,823
25
4,426,291.0
4,426,293.0
$426,823
26
4,426,291.0
4,426,293.0
$426,823
27
4,426,291.0
4,426,293.0
$426,823
28
4,426,291.0
4,426,293.0
$426,823
29
4,426,291.0
4,426,293.0
$426,823
30
4,426,291.0
4,426,293.0
$426,823
31
4,426,291.0
4,426,293.0
$426,823
32
4,426,291.0
4,426,293.0
$426,823
33
4,426,291.0
4,426,293.0
$426,823
34
4,426,291.0
4,426,293.0
$426,823
35
4,426,291.0
4,426,293.0
$426,823
36
4,426.291.0
4,426,293.0
$426,823
3?
4,426,291.0
4,426,293.0
$426,823
38
4,426,291.0
4,426,293.0
$426,823
39
4,426,291.0
4,426,293.0
$426,823
40
4,426,291.0
4,426,293.0
$426,823
41
4,426,291.0
4,426,293.0
$426,823
42
4,426,291.0
4,426,293.0
$426,823
43
4,426,291.0
4,426,293.0
$426,823
44
4,426,291.0
4,426,293.0
$426,823
45
4,426,291.0
4,426,293.0
$426,823
46
4,426,291.0
4,426,293.0
$426,823
47
4,426,291.0
4,426,293.0
$426,823
48
4,426,291.0
4,426,293.0
$426,823
49
4,426,291.0
4,426,293.0
$426,823
50
4,426,291.0
4,426,293.0
$426,823
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 8 FLUX STANDARD « 6
SCENARIO * 1 THICKNESS?in meters) » 1.021
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DOE TO CONTROLS
ANNUAL
YEAR
(pCf/sec)
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 9 FLUX STANDARD « 6
SCENARIO = 1 THICKNESSOn meters} = .533
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCf/sec)
(pCi/see)
COST
1
1,537,234.0
504,667.4
$1,565,006
2
1,530,636.0
557,725.8
$49,588
3
1,523,828.0
612,463.9
$356,993
4
1,516,782.0
669,117.9
$58,680
S
1,509,461.0
727,990.0
$388,441
6
1,501,815.0
789,469.8
$69,201
7
1,493,778.0
854,095.0
$429,750
8
1,458,635.0
1,458,635.0
$2,296,933
9
1,458,635.0
1,458,635.0
$101,419
10
1,458,635.0
1,458,635.0
$101,419
11
1,458,635.0
1,458,635.0
$101,419
12
1,458,635.0
1,458,635.0
$101,419
13
1,458,635.0
1,458,635.0
$101,419
14
1,458,635.0
1,458,635.0
$101,419
15
1,458,635.0
1,458,635.0
$101,419
16
1,458,635.0
1,458,635.0
$101,419
17
1,458,635.0
1,458,635.0
$101,419
18
1,458,635.0
1,458,635.0
$101,419
19
1,458,635.0
1,458,635.0
$101,419
20
1,458,635.0
1,458,635.0
$101,419
21
1,458,635.0
1,458,635.0
$101,419
22
1,458,635.0
1,458,635.0
$101,419
23
1,458,635.0
1,458,635.0
$101,419
24
1,458,635.0
1,458,635.0
$101,419
25
1,458,635.0
1,458,635.0
$101,419
26
1,458,635.0
1,458,635.0
$101,419
27
1,458,635.0
1,458,635.0
$101,419
28
1,458,635.0
1,458,635.0
$101,419
29
1,458,635.0
1,458,635.0
$101,419
30
1,458,635.0
1,458,635.0
$101,419
31
1,458,635.0
1,458,635.0
$101,419
32
1,458,635.0
1,458,635.0
$101,419
33
1,458,635.0
1,458,635.0
$101,419
34
1,458,635.0
1,458,635.0
$101,419
35
1,458,635.0
1,458,635.0
$101,419
36
1,458,635.0
1,458,635,0
$101,419
37
1,458,635.0
1,458,635.0
$101,419
38
1,458,635.0
1,458,635.0
$101,419
39
1,458,635.0
1,458,635.0
$101,419
40
1,458,635.0
1,458,635.0
$101,419
41
1,458,635.0
1,458,635.0
$101,419
42
1,458,635.0
1,458,635.0
$101,419
43
1,458,635.0
1,458,635.0
$101,419
44
1,458,635.0
1,458,635.0
$101,419
45
1,458,635.0
1,458,635.0
$101,419
46
1,458,635.0
1,458,635.0
$101,419
47
1,458,635.0
1,458,635.0
$101,419
48
1,458,635.0
1,458,635.0
$101,419
49
1,458,635.0
1,458,635.0
$101,419
50
1,458,635.0
1,458,635.0
$101,419
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 10 FLUX STANDARD ¦ 6
SCENARIO « 1 THICICNESStin meters) = .333
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/see)
(pCi/sec)
COST
1
241,192.0
277,992.9
$785,422
2
241,192.0
277,992.9
$24,004
3
241,192.0
277,992.9
$24,004
4
241,192.0
277,992.9
$24,004
5
241,192.0
277,992.9
$24,004
6
241,192.0
277,992.9
$24,004
7
241,192,0
277,992.9
$24,004
8
241,192.0
277,992,9
$24,004
9
241,192.0
277,992.9
$24,004
10
241,192.0
277,992.9
$24,004
11
241,192.0
277,992.9
$24,004
12
241,192.0
277,992.9
$24,004
13
241,192.0
277,992.9
$24,004
14
241,192.0
277,992.9
$24,004
15
241,192.0
277,992.9
$24,004
16
241,192.0
277,992.9
$24,004
17
241,192.0
277,992.9
$24,004
18
241,192.0
277,992,9
$24,004
19
241,192.0
277,992.9
$24,004
20
241,192.0
277,992.9
$24,004
21
241,192.0
277,992.9
$24,004
22
241,192.0
277,992.9
$24,004
23
241,192,0
277,992.9
$24,004
24
241,192.0
277,992.9
$24,004
25
241,192.0
277,992.9
$24,004
26
241,192.0
277,992.9
$24,004
2?
241,192.0
277,992.9
$24,004
28
241,192,0
277,992.9
$24,004
29
241,192.0
277,992.9
$24,004
30
241,192,0
277,992,9
$24,004
31
241,192.0
277,992.9
$24,004
32
241,192.0
277,992.9
$24,004
33
241,192.0
277,992.9
$24,004
34
241,192.0
277,992.9
$24,004
35
241,192.0
277,992.9
$24,004
36
241,192.0
277,992.9
$24,004
37
241,192.0
277,992.9
$24,004
38
241,192.0
277,992,9
$24,004
39
241,192.0
277,992.9
$24,004
40
241,192.0
277,992.9
$24,004
41
241,192.0
277,992.9
$24,004
42
241,192.0
277,992.9
$24,004
43
241,192.0
277,992.9
$24,004
44
241,192.0
277,992.9
$24,004
45
241,192,0
277,992.9
$24,004
46
24f,192.0
277,992.9
$24,004
47
241,192.0
277,992.9
$24,004
48
241,192.0
277,992.9
$24,004
49
241,192.0
277,992.9
$24,004
50
241,192.0
277,992.9
$24,004
-------
appendix to CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 11 FLUX STANDARD = 6
SCENARIO - 1 THICKNESS?in meters) = .333
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
10,304,620.0
5,092,054.0
S10.492.430
2
10,212,840.0
5,534,859.0
$470,067
3
9,268,822.0
10,028,950.0
$12,462,450
4
9,268,822.0
10,028,950.0
$712,741
5
9,268,822.0
10,028,950.0
$712,741
6
9,268,822.0
10,028,950.0
8712,741
7
9,268,822.0
10,028,950.0
$712,741
8
9,268,822.0
10,028,950.0
$712,741
9
9,268,822.0
10,028,950.0
$712,741
10
9,268,822.0
10,028,950.0
8712,741
11
9,268,822.0
10,028,950.0
$712,741
12
9,268,822.0
10,028,950.0
$712,741
13
9,268,822.0
10,028,950.0
$712,741
14
9,268,822.0
10,028,950.0
$712,741
15
9,268,822.0
10,028,950.0
$712,741
16
9,268,822.0
10,028,950.0
$712,741
1?
9,268,822.0
10,028,950.0
$712,741
18
9,268,822.0
10,028,950.0
$712,741
19
9,268,822.0
10,028,950.0
$712,741
20
9,268,822.0
10,028,950.0
$712,741
21
9,268,822.0
10,028,950.0
$712,741
22
9,268,822.0
10,028,950.0
$712,741
23
9,268,822.0
10,028,950,0
$712,741
24
9,268,822.0
10,028,950.0
$712,741
25
9,268,822.0
10,028,950.0
$712,741
26
9,268,822.0
10,028,950.0
$712,741
27
9,268,822.0
10,028,950.0
$712,741
28
9,268,822.0
10,028,950.0
$712,741
29
9,268,822.0
10,028,950.0
$712,741
30
9,268,822.0
10,028,950.0
$712,741
31
9,268,822.0
10,028,950.0
$712,741
32
9,268,622.0
10,028,950.0
$712,741
33
9,268,822.0
10,028,950.0
$712,741
34
9,268,822.0
10,028,950.0
$712,741
35
9,268,822.0
10,028,950.0
$712,741
36
9,268,822.0
10,028,950.0
$712,741
37
9,268,822.0
10,028,950.0
$712,741
38
9,268,822.0
10,028,950.0
$712,741
39
9,268,822.0
10,028,950.0
$712,741
40
9,268,822.0
10,028,950.0
$712,741
41
9,268,822.0
10,028,950.0
$712,741
42
9,268,822.0
10,028,950.0
$712,741
43
9,268,822.0
10,028,950.0
$712,741
44
9,268,822.0
10,028,950.0
$712,741
45
9,268,822.0
10,028,950.0
$712,741
46
9,268,822.0
10,028,950.0
$712,741
47
9,268,822.0
10,028,950.0
$712,741
48
9,268,822.0
10,028,950.0
$712,741
49
9,268,822.0
10,028,950.0
$712,741
50
9,268,822.0
10,028,950.0
$712,741
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 12 FLUX STANDARD * 6
SCENARIO * 1 THICKNESS*tn meters! = .408
EMISSIONS REMAINING
REDUCTION IM EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
-------
APPENDIX TO CHAPTER 9
EFfECTS Of CONTROLS FOR STACK 13 fUSX STANDARD - 6
SCENARIO « 1 THICKNESSCin meters) - .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pci/see)
(pCi/sec)
COST
1
1.341,587.0
791,326.3
$1,978,028
2
1,341,587.0
791,326.3
450,997
3
1,341,567.0
791,326.3
$50,997
4
1,341,587.0
791,326.3
$50,997
5
1,341,587.0
791,326.3
$50,997
6
1,341,587.0
791,326.3
$50,997
7
1,341,587.0
791,326.3
$50,997
8
1,341,587.0
791,326.3
$50,997
9
1,341,587.0
791,326.3
$50,997
10
1,341,587.0
791,326.3
$50,997
11
1,341,587.0
791,326.3
$50,997
12
1,341,587.0
791,326.3
$50,997
13
1,341,587.0
791,326.3
$50,997
14
1,341,587.0
791,326.3
$50,997
15
1,341,587.0
791,326.3
$50,997
16
1,341,587.0
791,326.3
$50,997
17
1,341,587.0
791,326.3
$50,997
18
1,341,587.0
791,326.3
$50,997
19
1,341,587.0
791,326.3
$50,997
20
1,341,587.0
791,326.3
$50,997
21
1,341,587.0
791,326.3
*50,997
22
1,341,587.0
791,326.3
$50,997
23
1,341,587.0
791,326.3
$50,997
24
1,341,587.0
791,326.3
$50,997
25
1,341,587.0
791,326.3
$50,997
26
1,341,587.0
791,326.3
$50,997
27
1,341,587.0
791,326.3
$50,997
28
1,341,587.0
791,326.3
$50,997
29
1,341,587.0
791,326.3
$50,997
30
1,341,587.0
791,326,3
$50,997
31
1,341,587.0
791,326.3
$50,997
32
1,341,587.0
791,326.3
$50,997
33
1,341,587.0
791,326.3
$50,997
34
1,341,587.0
791,326.3
$50,997
35
1,341,587.0
791,326.3
$50,997
36
1,341,587.0
791,326.3
$50,997
37
1,341,587.0
791,326.3
$50,997
38
1,341,587.0
791,326.3
$50,997
39
1,341,587.0
791,326.3
$50,997
40
1,341,587.0
791,326.3
$50,997
41
1,341,587.0
791,326.3
$50,997
42
1,341,587.0
791,326.3
$50,997
43
1,341,587.0
791,326.3
$50,997
44
1,341,587.0
791,326.3
$50,997
45
1,341,587.0
791,326.3
$50,997
46
1,341,587.0
791,326.3
$50,997
47
1,341,587.0
791,326.3
$50,997
48
1.341,587.0
791,326.3
$50,997
49
1,341,587.0
791,326.3
$50,997
50
1,341,587.0
791,326.3
$50,997
-------
APPEKOIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 14 FLUX STANDARD « 6
SCENARIO * 1 THICKNESSCin meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
t
2,279,844.0
1,287,766.0
$3,213,185
2
2,213,060.0
2,213,060.0
$2,857,951
3
2,213,060.0
2,213,060.0
*154,915
4
2,213,060.0
2,213,060.0
$154,915
5
2,213,060.0
2,213,060.0
$154,915
6
2,213,060.0
2,213,060.0
$154,915
7
2,213,060.0
2,213,060.0
$154,915
8
2,213,060.0
2,213,060.0
$154,915
9
2,213,060.0
2,213,060.0
$154,915
10
2,213,060.0
2,213,060.0
$154,915
11
2,213,060.0
2,213,060.0
$154,915
12
2,213,060.0
2,213,060.0
$154,915
13
2,213,060.0
2,213,060.0
$154,915
14
2,213,060.0
2,213,060.0
$154,915
15
2,213,060.0
2,213,060.0
$154,915
16
2,213,060.0
2,213,060.0
$154,915
17
2,213,060.0
2,213,060.0
$154,915
18
2,213,060.0
2,213,060.0
$154,915
19
2,213,060.0
2,213,060.0
$154,915
20
2,213,060.0
2,213,060.0
$154,915
21
2,213,060.0
2,213,060.0
$154,915
22
2,213,060.0
2,213,060.0
$154,915
23
2,213,060.0
2,213,060.0
$154,915
24
2,213,060.0
2,213,060.0
$154,915
25
2,213,060.0
2,213,060.0
$154,915
26
2,213,060.0
2,213,060.0
$154,915
27
2,213,060.0
2,213,060.0
$154,915
28
2,213,060.0
2,213,060.0
$154,915
29
2,213,060.0
2,213,060.0
$154,915
30
2,213,060.0
2,213,060.0
$154,915
31
2,213,060.0
2,213,060.0
$154,915
32
2,213,060.0
2,213,060.0
$154,915
33
2,213,060.0
2,213,060.0
$154,915
34
2,213,060.0
2,213,060.0
$154,915
35
2,213,060.0
2,213,060.0
$154,915
36
2,213,060.0
2,213,060.0
$154,915
37
2,213,060.0
2,213,060.0
$154,915
38
2,213,060.0
2,213,060.0
$154,915
39
2,213,060.0
2,213,060.0
$154,915
40
2,213,060.0
2,213,060.0
$154,915
41
2,213,060.0
2,213,060.0
$154,915
42
2,213,060.0
2,213,060.0
$154,915
43
2,213,060.0
2,213,060.0
$154,915
44
2,213,060.0
2,213,060.0
$154,915
45
2,213,060.0
2,213,060.0
$154,915
46
2,213,060.0
2,213,060.0
$154,915
47
2,213,060.0
2,213,060.0
$154,915
48
2,213,060.0
2,213,060.0
$154,915
49
2,213,060.0
2,213,060.0
$154,915
50
2,213,060.0
2,213,060.0
$154,915
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 1 FLUX STANDARD - 2
SCENARIO = 2 TKlCKNESSCin meters) = .995
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
1,932,166.0
0.0
SO
2
409,857.9
2,049,289.0
$6,462,955
3
409,857.9
2,049,289.0
$76,405
4
409,857.9
2,049,289.0
$76,405
5
409,857.9
2,049,289.0
$76,405
6
409,857.9
2,049,289.0
$76,405
7
409,857.9
2,049,289.0
$76,405
8
409,857.9
2,049,289.0
$76,405
9
409,857.9
2,049,289.0
$76,405
to
409,857.9
2,049,289.0
$76,405
11
409,857.9
2,049,289.0
$76,405
12
409,857.9
2,049,289.0
$76,405
13
409,857.9
2,049,289.0
$76,405
14
409,857.9
2,049,289.0
$76,405
15
409,857.9
2,049,289.0
$76,405
16
409,857.9
2,049,289.0
$76,405
1?
409,857.9
2,049,289.0
$76,405
18
409,857.9
2,049,289.0
$76,405
19
409,857.9
2,049,289.0
$76,405
20
409,857.9
2,049,289.0
$76,405
21
409,857.9
2,049,289.0
$76,405
22
409,857.9
2,049,289.0
$76,405
23
409,857.9
2,049,289.0
$76,405
24
409,857.9
2,049,289.0
$76,405
25
409,857.9
2,049,289.0
$76,405
26
409,857.9
2,049,289.0
$76,405
27
409,857.9
2,049,289.0
$76,405
28
409,857.9
2,049,289.0
$76,405
29
409,857.9
2,049,289.0
$76,405
30
409,857.9
2,049,289.0
$76,405
31
409,857.9
2,049,289.0
$76,405
32
409,857.9
2,049,289.0
$76,405
33
409,857.9
2,049,289.0
$76,405
34
409,857.9
2,049,289.0
$76,405
35
409,857.9
2,049,289.0
$76,405
36
409,857.9
2,049,289.0
$76,405
37
409,857.9
2,049,289.0
$76,405
38
409,857.9
2,049,289.0
$76,405
39
409,857.9
2,049,289.0
$76,405
40
409,857.9
2,049,289.0
$76,405
41
409,857.9
2,049,289.0
$76,405
42
409,857.9
2,049,289.0
$76,405
43
409,857.9
2,049,289.0
$76,405
44
409,857.9
2,049,289.0
$76,405
45
409,857.9
2,049,289.0
$76,405
46
409,857.9
2,049,289.0
$76,405
47
409,857.9
2,049,289.0
$76,405
48
409,857.9
2,049,289.0
$76,405
49
409,857.9
2,049,289.0
$76,405
50
409,857.9
2,049,289.0
$76,405
-------
APPEKOIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 2 FLUX STANDARD « 2
SCENARIO = 2 THICKNESS(in meters} « .995
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
1,596,768.0
0.0
SO
2
1,638,136.0
0.0
SO
3
1,680,890.0
0.0
SO
4
1,725,237.0
0.0
SO
5
1,771,445.0
0.0
SO
6
1,819,875.0
0.0
$0
7
1,871,023.0
0.0
SO
8
386,833.5
1,934,167.0
$6,911,243
9
386,833.5
1,934,167.0
$81,277
10
386,833.5
1,934,167.0
$81,277
tt
386,833.5
1,934,167.0
$81,277
12
386,833.5
1,934,167.0
$81,277
13
386,833.5
1,934,167.0
$81,277
14
386,833.5
1,934,167.0
$81,277
15
386,833.5
1,934,167.0
$81,277
16
386,833.5
1,934,167.0
$81,277
17
386,833.5
1,934,167.0
$81,277
18
386,833.5
1,934,167.0
$81,277
19
386,833.5
1,934,167.0
$81,277
20
386,833.5
1,934,167.0
$81,277
21
386,833.5
1,934,167.0
$81,277
22
386,833.5
1,934,167.0
$81,277
23
386,833.5
1,934,167.0
$81,277
24
386,833.5
1,934,167.0
$81,277
25
386,833.5
1,934,167.0
$81,277
26
386,833.5
1,934,167.0
$81,277
27
386,833.5
1,934,167.0
$81,277
28
386,833.5
1,934,167.0
$81,277
29
386,833.5
1,934,167.0
$81,277
30
386,833.5
1,934,167.0
$81,277
31
386,833.5
1,934,167.0
$81,277
32
386,833.5
1,934,167.0
$81,277
33
386,833.5
1,934,167.0
$81,277
34
386,833.5
1,934,167.0
$81,277
35
386,833.5
1,934,167.0
$81,277
36
386,833.5
1,934,167.0
$81,277
37
386,833.5
1,934.167.0
$81,277
38
386,833.5
1,934,167.0
$81,277
39
386,833,5
1,934,167.0
$81,277
40
386,833.5
1,934,167.0
$81,277
41
386,833.5
1,934,167.0
$81,277
42
386,833.5
1,934,167.0
$81,277
43
386,833.5
1,934,167.0
$81,277
44
386,833.5
1,934,167.0
$81,277
45
386,833.5
1,934,167.0
$81,277
46
386,833.5
1,934,167.0
$81,277
47
386,833.5
1,934,167.0
$81,277
48
386,833.5
1,934,167.0
$81,277
49
386,833.5
1,934,167.0
$81,277
50
386,833.5
1,934,167.0
$81,277
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 3 FLUX STANDARD - 2
SCENARIO = 2 THICKNESSO'n rosters) » .333
EMISSIONS REHASHING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec>
(pCf/sec)
COST
1
354,356.6
291,323.3
$4,635,814
2
354,356.6
291,323.3
>141,610
3
354,356.6
291,323.3
$141,610
4
354,356.6
291,323.3
$141,610
5
354,356.6
291,323.3
$141,610
6
354,356.6
291,323.3
$141,610
7
354,356.6
291,323.3
$141,610
8
354,356.6
291,323.3
$141,610
9
354,356.6
291,323.3
$141,610
10
354,356.6
291,323.3
$141,610
11
354,356.6
291,323.3
$141,610
12
354,356.6
291,323.3
$141,610
13
354,356.6
291,323.3
$141,610
14
354,356.6
291,323.3
$141,610
15
354,356.6
291,323.3
$141,610
16
354,356.6
291,323.3
$141,610
17
354,356.6
291,323.3
$141,610
18
354,356.6
291,323.3
$141,610
19
354,356.6
291,323.3
$141,610
20
354,356.6
291,323.3
$141,610
21
354,356.6
291,323.3
$141,610
22
354,356.6
291,323.3
$141,610
23
354,356.6
291,323.3
$141,610
24
354,356.6
291,323.3
$141,610
25
354,356.6
291,323.3
$141,610
26
354,356.6
291,323.3
$141,610
27
354,356.6
291,323.3
$141,610
28
354,356.6
291,323.3
8141,610
29
354,356.6
291,323.3
$141,610
30
354,356.6
291,323.3
$141,610
31
354,356.6
291,323.3
$141,610
32
354,356.6
291,323.3
$141,610
33
354,356.6
291,323.3
$141,610
34
354,356.6
291,323.3
$141,610
35
354,356.6
291,323.3
$141,610
36
354,356.6
291,323.3
$141,610
37
354,356.6
291,323.3
$141,610
38
354,356.6
291,323.3
$141,610
39
354,356.6
291,323.3
$141,610
40
354,356.6
291,323.3
$141,610
41
354,356.6
291,323.3
$141,610
42
354,356.6
291,323.3
$141,610
43
354,356.6
291,323.3
$141,610
44
354,356.6
291,323.3
$141,610
45
354,356.6
291,323.3
$141,610
46
354,356.6
291,323.3
$141,610
47
354,356.6
291,323.3
$141,610
48
354,356.6
291,323.3
$141,610
49
354,356.6
291,323.3
$141,610
50
354,356.6
291,323.3
$141,610
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 4 FlUX STANDARD = 2
SCENARIO = 2 TKICKHESSCSn meters) = 1.054
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
CpCi/see)
COST
t
4,746,327.0
0.0
SO
2
926,363.2
4,631,816.0
$21,934,520
3
926,363.2
4,631,816.0
$246,010
4
926,363.2
4,631,816.0
$246,010
5
926,363.2
4,631,816.0
$246,010
6
926,363.2
4,631,816.0
$246,010
7
926,363.2
4,631,816.0
$246,010
8
926,363.2
4,631,816.0
$246,010
9
926,363.2
4,631,816.0
$246,010
to
926,363.2
4,631,816.0
$246,010
11
926,363.2
4,631,816.0
$246,010
12
926,363.2
4,631,816.0
$246,010
13
926,363.2
4,631,816,0
$246,010
14
926,363.2
4,631,816.0
$246,010
15
926,363.2
4,631,816.0
$246,010
16
926,363.2
4,631,816.0
$246,010
1?
926,363.2
4,631,816.0
$246,010
18
926,363.2
4,631,816.0
$246,010
19
926,363.2
4,631,816.0
$246,010
20
926,363.2
4,631,816.0
$246,010
21
926,363.2
4,631,816.0
$246,010
22
926,363.2
4,631,816.0
$246,010
23
926,363.2
4,631,816.0
$246,010
24
926,363.2
4,631,816.0
$246,010
25
926,363.2
4,631,816.0
$246,010
26
926,363.2
4,631,816.0
$246,010
27
926,363.2
4,631,816.0
$246,010
28
926,363.2
4,631,816.0
$246,010
29
926,363.2
4,631,816.0
$246,010
30
926,363.2
4,631,816.0
$246,010
31
926,363.2
4,631,816.0
$246,010
32
926,363.2
4,631,816.0
$246,010
33
926,363.2
4,631,816.0
$246,010
34
926,363.2
4,631,816.0
$246,010
35
926,363.2
4,631,816.0
$246,010
36
926,363.2
4,631,816.0
$246,010
37
926,363.2
4,631,816.0
$246,010
38
926,363.2
4,631,816.0
$246,010
39
926,363.2
4,631,816.0
$246,010
40
926,363.2
4,631,816.0
$246,010
41
926,363.2
4,631,816.0
$246,010
42
926,363.2
4,631,816.0
$246,010
43
926,363.2
4,631,816.0
$246,010
44
926,363.2
4,631,816.0
$246,010
45
926,363.2
4,631,816.0
$246,010
46
926,363.2
4,631,816.0
$246,010
47
926,363.2
4,631,816.0
$246,010
48
926,363.2
4,631,816.0
$246,010
49
926,363.2
4,631,816.0
$246,010
50
926,363.2
4,631,816.0
$246,010
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 1 FLUX STANDARD - 6
SCENARIO * 2 THICKNESS(in meters) = .385
EMISSIONS REMAINING
REDUCTION IK EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCi/see)
CpCS/sec)
COST
1
1,932,166.0
0.0
$0
2
1,229,574.0
1,229,574.0
$2,835,224
3
1,229,574.0
1,229,574.0
$76,405
4
1,229,574.0
1,229,574.0
$76,405
5
1,229,574.0
1,229,574.0
$76,405
6
1,229,574.0
1,229,574.0
$76,405
7
1,229,574.0
1,229,574.0
$76,405
8
1,229,574.0
1,229,574.0
$76,405
9
1,229,574.0
1,229,574.0
$76,405
10
1,229,574.0
1,229,574.0
$76,405
11
1,229,574.0
1,229,574.0
$76,405
12
1,229,574.0
1,229,574.0
$76,405
13
1,229,574.0
1,229,574.0
$76,405
14
1,229,574.0
1,229,574.0
$76,405
15
1,229,574.0
1,229,574.0
$76,405
16
1,229,574.0
1,229,574.0
$76,405
17
1,229,574.0
1,229,574,0
$76,405
18
1,229,574.0
1,229,574.0
$76,405
19
1,229,574.0
1,229,574.0
$76,405
20
1,229,574.0
1,229,574.0
$76,405
21
1,229,574.0
1,229,574.0
$76,405
22
1,229,574.0
1,229,574.0
$76,405
23
1,229,574.0
1,229,574.0
$76,405
24
1,229,574.0
1,229,574.0
$76,405
25
1,229,574.0
1,229,574.0
$76,405
26
1,229,574.0
1,229,574.0
$76,405
27
1,229,574.0
1,229,574.0
$76,405
28
1,229,574.0
1,229,574.0
$76,405
29
1,229,574.0
1,229,574.0
$76,405
30
1,229,574.0
1,229,574.0
$76,405
31
1,229,574.0
1,229,574.0
$76,405
32
1,229,574.0
1,229,574.0
$76,405
33
1,229,574.0
1,229,574.0
$76,405
34
1,229,574.0
1,229,574.0
$76,405
35
1,229,574.0
1,229,574.0
$76,405
36
1,229,574.0
1,229,574.0
$76,405
37
1,229,574.0
1,229,574.0
$76,405
38
1,229,574.0
1,229,574.0
$76,405
39
1,229,574.0
1,229,574.0
$76,405
40
1,229,574.0
1,229,574.0
$76,405
41
1,229,574.0
1,229,574.0
$76,405
42
1,229,574,0
1,229,574.0
$76,405
43
1,229,574.0
1,229,574.0
$76,405
44
1,229,574.0
1,229,574.0
$76,405
45
1,229,574.0
1,229,574.0
$76,405
46
1,229,574.0
1,229,574.0
$76,405
47
1,229,574.0
1,229,574.0
$76,405
48
1,229,574.0
1,229,574.0
$76,405
49
1,229,574.0
1,229,574.0
$76,405
50
1,229,574.0
1,229,574.0
$76,405
-------
mpmom to chapter 9
EFFECTS OF CONTROLS FOR STACK 2 FLUX STANDARD * 6
SCENARIO ¦ 2 THICKNESS(in meters) ¦ .385
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
{pCi/sec)
(pCi/sec)
COST
1
1,596,768.0
0.0
$0
2
1,638,136.0
0.0
$0
3
1,680,890,0
0.0
$0
4
1,725,237.0
0.0
$0
5
1,771,445.0
0.0
$0
6
1,819,875.0
0.0
$0
7
1,871,023.0
0.0
so
a
1,160,500.0
1,160,501.0
$3,052,193
9
1,160,500.0
1,160,501.0
$81,277
10
1,160,500.0
1,160,501.0
$81,277
11
1,160,500.0
1,160.501.0
$81,277
12
1,160,500.0
1,160,501.0
$81,277
13
1,160,500.0
1,160,501.0
$81,277
14
1,160,500.0
1,160,501.0
$81,277
15
1,160,500.0
1,160,501.0
$81,277
16
1,160,500.0
1,160,501.0
$81,277
17
1,160,500.0
1,160,501.0
$81,277
18
1,160,500.0
1,160,501.0
$81,277
19
1,160,500.0
1,160,501.0
$81,277
20
1,160,500.0
1,160,501.0
$81,277
21
1,160,500-0
1,160,501.0
$81,277
22
1,160,500.0
1,160,501.0
$81,277
23
1,160,500.0
1,160,501.0
$81,277
24
1,160,500.0
1,160,501.0
$81,277
25
1,160,500.0
1,160,501.0
$81,277
26
1,160,500.0
1,160,501.0
$81,277
27
1,160,500.0
1,160,501.0
$81,277
28
1,160,500.0
1,160,501.0
$81,277
29
1,160,500.0
1,160,501.0
$81,277
30
1,160,500.0
1,160,501.0
$81,277
31
1,160,500.0
1,160,501.0
$81,277
32
1,160,500.0
1,160,501.0
$81,277
33
1,160,500.0
1,160,501.0
$81,277
34
1,160,500.0
1,160,501.0
$81,277
35
1,160,500.0
1,160,501.0
$81,277
36
1,160,500.0
1,160,501.0
$81,277
37
1,160,500.0
1,160,501.0
$81,277
38
1,160,500.0
1,160,501.0
$81,277
39
1,160,500.0
1,160,501.0
$81,277
40
1,160,500.0
1,160,501.0
$81,277
41
1,160,500.0
1,160,501.0
$81,277
42
1,160,500.0
1,160,501.0
$81,277
43
1,160,500.0
1,160,501.0
$81,277
44
1,160,500.0
1,160,501.0
$81,277
45
1,160,500.0
1,160,501.0
$81,277
46
1,160,500.0
1,160,501.0
$81,277
47
1,160,500.0
1,160,501.0
$81,277
48
1,160,500.0
1,160,501.0
$81,277
49
1,160,500.0
1,160,501.0
$81,277
50
1,160,500.0
1,160,501.0
$81,277
-------
APPENDIX TO CHAPTER 9
EFFECTS Of CONTROLS FOR STACK 3
SCENARIO = 2
FLUX STANDARD = 6
THICKNESSCin meters)
.333
YEAR
EMISSIONS REMAINING
AFTER CONTROLS
(pCi/sec)
REDUCTION IN EMISSIONS
DUE TO CONTROLS ANNUAL
(pCi/sec) COST
1
354.356.6
291,323.3
$4,635
814
2
354,356.6
291,323.3
$141
610
3
354,356.6
291,323.3
$141
610
4
354,356.6
291,323.3
$141
610
5
354,356.6
291,323.3
$141
610
6
354,356.6
291,323.3
$141
610
7
354,356.6
291,323.3
$141
610
8
354,356.6
291,323.3
$141
610
9
354,356.6
291,323.3
$141
610
10
354,356.6
291,323.3
$141
610
11
354,356.6
291,323.3
$141
610
12
354,356.6
291,323.3
$141
610
13
354,356.6
291,323.3
$141
610
14
354,356.6
291,323.3
$141
610
15
354,356.6
291,323.3
$141
610
16
354,356.6
291,323.3
$141
610
17
354,356.6
291,323.3
$141
610
18
354,356.6
291,323.3
$141
610
19
354,356.6
291,323.3
$141
610
20
354,356.6
291,323.3
$141
610
21
354,356.6
291,323.3
$141
610
22
354,356.6
291,323.3
$141
610
23
354,356.6
291,323.3
$141
610
24
354,356.6
291,323.3
$141
610
25
354,356.6
291,323.3
$141
610
26
354,356.6
291,323.3
$141
610
27
354,356.6
291,323.3
$141
610
28
354,356.6
291,323.3
$141
6W
29
354,356.6
291,323.3
$141
610
30
354,356.6
291,323.3
$141
610
31
354,356.6
291,323.3
$141
610
32
354,356.6
291,323.3
$141
610
33
354,356.6
291,323.3
$141
610
34
354,356.6
291,323.3
$141
610
35
354,356.6
291,323.3
$141
610
36
354,356.6
291,323.3
$141
610
37
354,356.6
291,323.3
$141
610
38
354,356.6
291,323.3
$141
610
39
354,356.6
291,323.3
$141
610
40
354,356.6
291,323.3
$141
610
41
354,356.6
291,323.3
$141
610
42
354,356.6
291,323.3
$141
610
43
354,356.6
291,323.3
$141
610
44
354,356.6
291,323.3
$141
610
45
354,356,6
291,323.3
$141
610
46
354,356.6
291,323.3
$141
610
47
354,356.6
291,323.3
$141
610
48
354,356.6
291,323.3
$141
610
49
354,356.6
291,323.3
$141
610
50
354,356.6
291,323.3
$141
610
-------
APPCMDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 4 FLUX STANDARD - 6
SCENARIO = 2 THlCKNESSCin meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
CpCt/sec)
CpCi/sec)
COST
1
4,746,327.0
0.0
so
2
2,779,089.0
2,779,090.0
$9,566,817
3
2,779,089.0
2,779,090.0
$246,010
4
2,779,089.0
2,779,090.0
$246,010
5
2,779,089.0
2,779,090.0
$246,010
6
2,779,089.0
2,779,090.0
$246,010
7
2,779,089.0
2,779,090.0
$246,010
8
2,779,089.0
2,779,090.0
$246,010
9
2,779,089.0
2,779,090.0
$246,010
10
2,779,089.0
2,779,090.0
$246,010
11
2,779,089.0
2,779,090.0
$246,010
12
2,779,089.0
2,779,090.0
$246,010
13
2,779,089.0
2,779,090.0
$246,010
14
2,779,089.0
2,779,090.0
$246,010
15
2,779,089.0
2,779,090.0
$246,010
16
2,779,089.0
2,779,090.0
$246,010
1 r
2,779,089.0
2,779,090.0
$246,010
18
2,779,089.0
2,779,090.0
$246,010
19
2,779,089.0
2,779,090.0
$246,010
20
2,779,089.0
2,779,090.0
$246,010
21
2,779,089.0
2,779,090.0
$246,010
22
2,779,089.0
2,779,090.0
$246,010
23
2,779,089.0
2,779,090.0
$246,010
24
2,779,089.0
2,779,090.0
$246,010
25
2,779,089.0
2,779,090.0
$246,010
26
2,779,089.0
2,779,090.0
$246,010
27
2,779,089.0
2,779,090.0
$246,010
28
2,779,089.0
2,779,090.0
$246,010
29
2,779,089.0
2,779,090.0
$246,010
30
2,779,089.0
2,779,090.0
$246,010
31
2,779,089.0
2,779,090.0
$246,010
32
2,779,089.0
2,779,090.0
$246,010
33
2,779,089.0
2,779,090.0
$246,010
34
2,779,089.0
2,779,090.0
$246,010
35
2,779,089.0
2,779,090.0
$246,010
36
2,779,089.0
2,779,090.0
$246,010
37
2,779,089.0
2,779,090.0
$246,010
38
2,779,089.0
2,779,090.0
$246,010
39
2,779,089.0
2,779,090.0
$246,010
40
2,779,089.0
2,779,090.0
$246,010
41
2,779,089.0
2,779,090.0
$246,010
42
2,779,089.0
2,779,090.0
$246,010
43
2,779,089.0
2,779,090.0
$246,010
44
2,779,089.0
2,779,090.0
$246,010
45
2,779,089.0
2,779,090.0
$246,010
46
2,779,089.0
2,779,090.0
$246,010
47
2,779,089.0
2,779,090.0
$246,010
48
2,779,089.0
2,779,090.0
$246,010
49
2,779,089.0
2,779,090.0
$246,010
50
2,779,089.0
2,779,090.0
$246,010
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 5 FLUX STANDARD = 6
SCENARIO = 2 THICKNESS(in meters) - .385
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
CpCf/see)
COST
1
6,895,139.0
0.0
$0
2
6,976,675.0
0.0
$0
3
7,059,347.0
0.0
$0
4
7,143,211.0
0.0
$0
5
7,228,350.0
0.0
$0
6
7,314,824.0
0.0
so
7
7,402,742.0
0.0
$0
8
7,492,196.0
0.0
so
9
7,583,303.0
0.0
$0
10
7,676,186.0
0.0
so
11
7,771,001.0
0.0
$0
12
7,867,916.0
0.0
$0
13
7,967,126.0
0.0
so
14
8,068,868.0
0.0
$0
15
4,974,273.0
4,974,273.0
$13,308,340
16
4,974,273.0
4,974,273.0
$357,865
17
4,974,273.0
4,974,273.0
$357,865
18
4,974,273.0
4,974,273.0
$357,865
19
4,974,273.0
4,974,273.0
$357,865
20
4,974,273.0
4,974,273.0
$357,865
21
4,974,273.0
4,974,273.0
$357,865
22
4,974,273.0
4,974,273.0
$357,865
23
4,974,273.0
4,974,273.0
$357,865
24
4,974,273.0
4,974,273.0
$357,865
25
4,974,273.0
4,974,273.0
$357,865
26
4,974,273.0
4,974,273.0'
$357,865
27
4,974,273.0
4,974,273.0
$357,865
28
4,974,273.0
4,974,273.0
$357,865
29
4,974,273.0
4,974,273.0
£357,865
30
4,974,273.0
4,974,273.0
$357,865
31
4,974,273.0
4,974,273.0
$357,865
32
4,974,273.0
4,974,273.0
$357,865
33
4,974,273.0
4,974,273.0
$357,865
34
4,974,273.0
4,974,273.0
$357,865
35
4,974,273.0
4,974,273.0
$357,865
3d
4,974,273.0
4,974,273.0
$357,865
37
4,974,273.0
4,974,273.0
$357,865
38
4,974,273.0
4,974,273.0
$357,865
39
4,974,273.0
4,974,273.0
$357,865
40
4,974,273.0
4,974,273.0
$357,865
41
4,974,273.0
4,974,273.0
$357,865
42
4,974,273.0
4,974,273.0
$357,865
43
4,974,273.0
4,974,273.0
$357,865
44
4,974,273.0
4,974,273.0
$357,865
45
4,974,273.0
4,974,273.0
$357,865
46
4,974,273.0
4,974,273.0
$357,865
47
4,974,273.0
4,974,273.0
$357,865
48
4,974,273.0
4,974,273.0
$357,865
49
4,974,273.0
4,974,273.0
$357,865
50
4,974,273.0
4,974,273.0
$357,865
-------
AWENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 6 FLUX STANDARD * 6
SCENARIO * 2 THICKNESSCin meters) * .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
8,345,288,0
0.0
$0
2
4,882,716.0
4,882,717.0
$16,696,870
3
4,882,716.0
4,882,717.0
$433,433
4
4,882,716.0
4,882,717.0
$433,433
5
4,882,716.0
4,882,717.0
$433,433
6
4,882,716.0
4,882,717.0
$433,433
7
4,882,716.0
4,882,717.0
$433,433
8
4,882,716.0
4,882,717.0
$433,433
9
4,882,716.0
4,882,717.0
$433,433
10
4,882,716.0
4,882,717.0
$433,433
11
4,882,716.0
4,882,717.0
$433,433
12
4,882,716.0
4,882,717.0
$433,433
13
4,882,716.0
4,882,717.0
$433,433
14
4,882,716.0
4,882,717.0
$433,433
15
4,882,716.0
4,882,717.0
$433,433
16
4,882,716.0
4,882,717.0
$433,433
17
4,882,716.0
4,882,717.0
$433,433
18
4,882,716.0
4,882,717.0
$433,433
19
4,882,716.0
4,882,717.0
$433,433
20
4,882,716.0
4,882,717.0
$433,433
21
4,882,716.0
4,882,717.0
$433,433
22
4,882,716.0
4,882,717.0
$433,433
23
4,882,716.0
4,882,717.0
$433,433
24
4,882,716.0
4,882,717.0
$433,433
25
4,882,716.0
4,882,717.0
$433,433
26
4,882,716.0
4,882,717.0
$433,433
27
4,882,716.0
4,882,717.0
$433,433
28
4,882,716.0
4,882,717.0
$433,433
29
4,882,716.0
4,882,717.0
$433,433
30
4,882,716.0
4,882,717.0
$433,433
31
4,882,716.0
4,882,717.0
$433,433
12
4,882,716.0
4,882,717.0
$433,433
33
4,882,716.0
4,882,717.0
$433,433
34
4,882,716.0
4,882,717.0
$433,433
35
4,882,716.0
4,882,717.0
$433,433
36
4,882,716.0
4,882,717.0
$433,433
37
4,882,716.0
4,882,717.0
$433,433
38
4,882,716.0
4,882,717.0
$433,433
39
4,882,716.0
4,882,717.0
$433,433
40
4,882,716.0
4,882,717.0
$433,433
41
4,882,716.0
4,882,717.0
$433,433
42
4,882,716.0
4,882,717.0
$433,433
43
4,882,716.0
4,882,717.0
$433,433
44
4,882,716.0
4,882,717.0
$433,433
45
4,882,716.0
4,882,717.0
$433,433
46
4,882,716.0
4,882,717.0
$433,433
47
4,882,716.0
4,882,717.0
$433,433
48
4,882,716.0
4,882,717.0
$433,433
49
4,882,716.0
4,882,717.0
$433,433
50
4,882,716.0
4,882,717.0
$433,433
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 7 FLUX STANDARD « 6
SCENARIO = 2 THICICNESSO'n meters) » .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
4,426,291.0
4,426,293.0
$16,437,950
2
4.426,291.0
4,426,293.0
$426,823
3
4,426,291.0
4,426,293.0
$426,823
4
4,426,291.0
4,426,293.0
$426,823
S
4,426,291.0
4,426,293.0
$426,823
6
4,426,291.0
4,426,293.0
$426,823
7
4,426,291.0
4,426,293.0
$426,823
a
4,426,291.0
4,426,293.0
$426,823
9
4,426,291.0
4,426,293.0
$426,823
10
4,426,291.0
4,426,293.0
$426,823
11
4,426,291.0
4,426,293.0
$426,823
12
4,426,291,0
4,426,293.0
$426,823
13
4,426,291.0
4,426,293.0
$426,823
14
4,426,291.0
4,426,293.0
$426,823
15
4,426,291.0
4,426,293.0
$426,823
16
4,426,291.0
4,426,293.0
$426,823
17
4,426,291.0
4,426,293.0
$426,823
18
4,426,291.0
4,426,293.0
$426,823
19
4,426,291.0
4,426,293.0
$426,823
20
4,426,291.0
4,426,293.0
$426,823
21
4,426,291.0
4,426,293.0
$426,823
22
4,426,291.0
4,426,293.0
$426,823
23
4,426,291.0
4,426,293.0
$426,823
24
4,426,291.0
4,426,293.0
$426,823
25
4,426,291.0
4,426,293.0
$426,823
26
4,426,291.0
4,426,293.0
$426,823
27
4,426,291.0
4,426,293.0
$426,823
28
4,426,291.0
4,426,293.0
$426,823
29
4,426,291.0
4,426,293.0
$426,823
30
4,426,291.0
4,426,293.0
$426,823
31
4,426,291.0
4,426,293.0
$426,823
32
4,426,291.0
4,426,293.0
$426,823
33
4,426,291.0
4,426,293.0
$426,823
34
4,426,291.0
4,426,293.0
$426,823
35
4,426,291.0
4,426,293.0
$426,823
36
4,426,291.0
4,426,293.0
$426,823
37
4,426,291.0
4,426,293.0
$426,823
38
4,426,291.0
4,426,293.0
$426,823
39
4,426,291.0
4,426,293.0
$426,823
40
4,426,291.0
4,426,293.0
$426,823
41
4,426,291.0
4,426,293.0
$426,823
42
4,426,291.0
4,426,293.0
$426,823
43
4,426,291.0
4,426,293.0
$426,823
44
4,426,291.0
4,426,293.0
$426,823
45
4,426,291.0
4,426,293.0
$426,823
46
4,426,291.0
4,426,293.0
$426,823
4?
4,426,291.0
4,426,293.0
$426,823
48
4,426,291.0
4,426,293.0
$426,823
49
4,426,291.0
4,426,293.0
$426,823
50
4,426,291.0
4,426,293.0
$426,823
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 8 FLUX STANDARD = 6
SCENARIO - 2 THICKNESSCin maters) = 1-021
EMISSIONS REMAIN IMG
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
i
(pCi/sec)
(pCi/secJ
COST
1
1,248,385.0
0.0
so
2
1,248,388.0
0.0
$0
3
1,248,388.0
0.0
*0
4
1,248,388.0
0.0
$0
5
1,248,388.0
0.0
$0
6
1,248,388.0
0.0
so
7
1,248,388.0
0.0
$0
8
1,248,388.0
0.0
so
9
1,248,388.0
0.0
$0
10
1,248,388.0
0.0
so
11
1,248,388.0
0.0
so
12
1,248,388.0
0.0
so
13
1,248,388.0
0.0
so
14
1,248,388.0
0.0
so
15
1,248,388.0
0.0
so
16
1,248,388.0
0.0
so
17
1,248,388.0
0.0
$0
18
1,248,388.0
0.0
so
19
1,248,388.0
0.0
so
20
1,248,388.0
0.0
$0
21
1,248,388.0
0.0
so
22
1,248,388.0
0.0
so
23
1,248,388.0
0.0
so
24
1,248,388.0
0.0
so
25
1,248,388.0
0.0
so
26
1,248,388.0
0.0
so
27
1,248,388.0
0.0
so
28
1,248,388.0
0.0
so
29
1,248,388.0
0.0
so
30
1,248,388.0
0.0
so
31
1,248,388.0
0.0
so
32
1,248,388.0
0.0
so
33
1,248,388.0
0.0
so
34
1,248,388.0
0.0
so
35
1,248,388.0
0.0
so
36
1,248,388.0
0.0
so
37
1,248,388.0
0.0
so
38
1,248,388.0
0.0
so
39
1,248,388.0
0.0
so
40
1,248,388.0
0.0
so
41
1,248,388.0
0.0
so
42
1,248,388.0
0.0
so
43
1,248,388.0
0.0
so
44
1,248,388.0
0.0
so
45
1,248,388.0
0.0
so
46
1,248,388.0
0.0
so
47
1,248,388.0
0.0
so
48
1,248,388.0
0.0
so
49
1,248,388.0
0.0
so
50
1,248,388.0
0.0
so
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 9 FLUX STANDARD = 6
SCENARIO = 2 THICKNESSCin meters) = .533
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
YEAR
(pCi/sec)
(pCi/sec)
COST
1
2,041,902.0
0.0
$0
2
2,088,362.0
0.0
$0
3
2,136,292.0
0.0
$0
4
2,185,900.0
0.0
so
S
2,237,451.0
0.0
so
6
2,291,285.0
0.0
so
7
2,347,873.0
0.0
$0
8
1,458,635.0
1,458,635.0
54,910,701
9
1,458,635.0
1,458,635.0
$101,419
10
1,458,635.0
1,458,635.0
5101,419
11
1,458,635.0
1,458,635.0
5101,419
12
1,458,635.0
1,458,635.0
5101,419
13
1,458,635.0
1,458,635.0
5101,419
14
1,458,635.0
1,458,635.0
5101,419
15
1,458,635.0
1,458,635.0
$101,419
16
1,458,635.0
1,458,635.0
$101,419
17
1,458,635.0
1,458,635.0
$101,419
18
1,458,635.0
1,458,635.0
$101,419
19
1,458,635.0
1,458,635.0
$101,419
20
1,458,635.0
1,458,635.0
$101,419
21
1,458,635.0
1,458,635.0
$101,419
22
1,458,635.0
1,458,635.0
$101,419
23
1,458,635.0
1,458,635.0
$101,419
24
1,458,635.0
1,458,635.0
$101,419
25
1,458,635.0
1,458,635.0
$101,419
26
1,458,635.0
1,458,635.0
$101,419
27
1,458,635.0
1,458,635.0
$101,419
28
1,458,635.0
1,458,635.0
$101,419
29
1,458,635.0
1,458,635.0
$101,419
30
1,458,635.0
1,458,635.0
$101,419
31
1,458,635,0
1,458,635.0
$101,419
32
1,458,635.0
1,458,635.0
$101,419
33
1,458,635.0
1,458,635.0
$101,419
34
1,458,635.0
1,458,635.0
$101,419
35
1,458,635.0
1,458,635.0
$101,419
36
1,458,635.0
1,458,635.0
$101,419
3?
1,458,635.0
1,458,635.0
$101,419
38
1,458,635.0
1,458,635.0
$101,419
39
1,458,635.0
1,458,635.0
$101,419
40
1,458,635.0
1,458,635.0
$101,419
41
1,458,635.0
1,458,635.0
$101,419
42
1,458,635.0
1,458,635.0
$101,419
43
1,458,635.0
1,458,635.0
$101,419
44
1,458,635.0
1,458,635.0
$101,419
45
1,458,635.0
1,458,635.0
$101,419
46
1,458,635.0
1,458,635.0
$101,419
47
1,458,635.0
1,458,635.0
$101,419
48
1,458,635.0
1,458,635.0
$101,419
49
1,458,635.0
1,458,635.0
$101,419
50
1,458,635.0
1,458,635.0
$101,419
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS F08 STACK 10 FLUX STANDARD * 6
SCENARIO = 2 THSCKNESSCin meters) - .333
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
TEAR
(pCf/sec)
(pCi/sec)
COST
1
241,192.0
277,992,9
$785,422
2
241,192.0
277,992.9
$24,004
3
241,192.0
277,992.9
$24,004
4
241,192.0
277,992.9
$24,004
5
241,192.0
277,992.9
S24,004
6
241,192.0
277,992.9
$24,004
7
241,192.0
277,992.9
$24,004
8
241,192.0
277,992.9
$24,004
9
241,192.0
277,992.9
$24,004
10
241,192.0
277,992.9
$24,004
11
241,192.0
277,992.9
$24,004
12
241,192.0
277,992.9
$24,004
13
241,192.0
277,992.9
$24,004
14
241,192.0
277,992.9
$24,004
15
241,192.0
277,992.9
$24,004
16
241,192.0
277,992.9
$24,004
17
241,192.0
277,992.9
$24,004
18
241,192.0
277,992.9
$24,004
19
241,192.0
277,992.9
$24,004
20
241,192.0
277,992.9
$24,004
21
241,192.0
277,992.9
$24,004
22
241,192.0
277,992.9
$24,004
23
241,192.0
277,992.9
$24,004
24
241,192.0
277,992.9
$24,004
25
241,192.0
277,992.9
$24,004
26
241,192.0
277,992.9
$24,004
27
241,192.0
277,992.9
$24,004
28
241,192.0
277,992.9
$24,004
29
241,192.0
277,992.9
$24,004
30
241,192.0
277,992.9
$24,004
31
241,192.0
277,992.9
$24,004
32
241,192.0
277,992.9
$24,004
33
241,192.0
277,992.9
$24,004
34
241,192,0
277,992.9
$24,004
35
241,192.0
277,992.9
$24,004
36
241,192,0
277,992.9
$24,004
37
241,192.0
277,992.9
$24,004
38
241,192.0
277,992.9
$24,004
39
241,192.0
277,992.9
$24,004
40
241,192.0
277,992.9
$24,004
41
241,192.0
277,992.9
$24,004
42
241,192.0
277,992.9
$24,004
43
241,192.0
277,992.9
$24,004
44
241,192.0
277,992.9
$24,004
45
241,192.0
277,992.9
$24,004
46
241.192.0
277,992.9
$24,004
47
241,192.0
277,992.9
$24,004
48
241,192.0
277,992.9
$24,004
49
241,192.0
277,992.9
$24,004
50
241,192.0
277,992.9
$24,004
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 11 FLUX STANDARD * 6
SCENARIO - 2 THlCKNESS(in meters} = .333
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
VEAR
(pCi/sec)
(pCf/sec)
COST
1
15,396,670.0
0.0
SO
2
15,747,700.0
0.0
$0
3
9,268,822.0
10,028,950.0
$23,536,680
4
9,268,822.0
10,028,950.0
*712,741
5
9,268,822.0
10,028,950.0
$712,741
6
9,268,822.0
10,028,950.0
$712,741
7
9,268,822.0
10,028,950.0
$712,741
8
9,268,822.0
10,028,950.0
$712,741
9
9,268,822.0
10,028,950.0
$712,741
10
9,268,822.0
10,028,950.0
$712,741
11
9,268,822.0
10,028,950.0
$712,741
12
9,268,822.0
10,028,950.0
$712,741
13
9,268,822.0
10,028,950.0
$712,741
14
9,268,822.0
10,028,950.0
$712,741
15
9,268,822.0
10,028,950.0
$712,741
16
9,268,822.0
10,028,950.0
$712,741
1?
9,268,822.0
10,028,950.0
$712,741
18
9,268,822.0
10,028,950.0
$712,741
19
9,268,822.0
10,028,950.0
$712,741
20
9,268,822.0
10,028,950.0
$712,741
21
9,268,822.0
10,028,950.0
$712,741
22
9,268,822.0
10,028,950.0
$712,741
23
9,268,822.0
10,028,950.0
$712,741
24
9,268,822.0
10,028,950.0
$712,741
25
9,268,822.0
10,028,950.0
$712,741
26
9,268,822.0
10,028,950.0
$712,741
27
9,268,822.0
10,028,950.0
$712,741
28
9,268,822.0
10,028,950.0
$712,741
29
9,268,822.0
10,028,950.0
$712,741
30
9,268,822.0
10,028,950.0
$712,741
31
9,268,822.0
10,028,950.0
$712,741
32
9,268,822.0
10,028,950.0
$712,741
33
9,268,822.0
10,028,950.0
$712,741
34
9,268,822.0
10,028,950.0
$712,741
35
9,268,822.0
10,028,950.0
$712,741
36
9,268,822.0
10,028,950.0
$712,741
37
9,268,822.0
10,028,950.0
$712,741
38
9,268,822.0
10,028,950.0
$712,741
39
9,268,822.0
10,028,950.0
$712,741
40
9,268,822.0
10,028,950.0
$712,741
41
9,268,822.0
10,028,950.0
$712,741
42
9,268,822.0
10,028,950.0
$712,741
43
9,268,822.0
10,028,950.0
$712,741
44
9,268,822.0
10,028,950.0
$712,741
45
9,268,822.0
10,028,950.0
$712,741
46
9,268,822.0
10,028,950.0
$712,741
47
9,268,822.0
10,028,950.0
$712,741
48
9,268,822.0
10,028,950.0
$712,741
49
9,268,822.0
10,028,950.0
$712,741
50
9,268,822.0
10,028,950.0
$712,741
-------
APPENDIX To CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 12 FLUX STANDARD - 6
SCENARIO = 2 THICKNESSCin meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
CpCi/secJ
(pCi/sec)
COST
1
1,495,756.0
0.0
$0
2
1,495,756.0
0.0
$0
3
1,495,756.0
0.0
$0
4
1,495,756.0
0.0
$0
5
1,495,756.0
0.0
so
6
1,495,756.0
0.0
so
7
1,495,756.0
0.0
$0
8
1,495,756.0
0.0
so
9
1,495,756.0
0.0
so
10
1,495,756.0
0.0
so
11
1,495,756.0
0.0
so
12
1,495,756.0
0.0
so
13
1,495,756.0
0.0
so
14
1,495,756.0
0.0
so
15
1,495,756.0
0.0
so
16
1,495,756.0
0.0
so
1?
1,495,756.0
0.0
so
18
1,495,756.0
0.0
so
19
1,495,756.0
0,0
so
20
1,495,756.0
0.0
$0
21
1,495,756.0
0.0
$0
22
1,495,756.0
0.0
so
23
1,495,756.0
0.0
so
24
1,495,756.0
0.0
so
25
1,495,756.0
0.0
so
26
1,495,756.0
0.0
$0
2?
1,495,756.0
0.0
$0
28
1,495,756.0
0,0
*0
29
1,495,756.0
0.0
so
30
1,495,756.0
0.0
$0
31
1,495,756.0
0.0
$0
32
1,495,756,0
0.0
so
33
1,495,756.0
0.0
$0
34
1,495,756.0
0.0
so
35
1,495,756.0
0.0
so
36
1,495,756.0
0.0
so
3?
1,495,756.0
0.0
so
38
1,495,756.0
0.0
so
39
1,495,756.0
0.0
so
40
1,495,756.0
0.0
so
41
1,495,756.0
0.0
so
42
1,495,756.0
0.0
so
43
1,495,756.0
0.0
so
44
1,495,756.0
0.0
$0
45
1,495,756.0
0.0
so
46
1,495,756.0
0.0
so
47
1,495,756.0
0.0
so
48
1,495,756,0
0.0
so
49
1,495,756.0
0.0
so
50
1,495,756.0
0.0
so
-------
APPENDIX TO CHAPTER 9
EFFECTS OP CONTROLS FOR STACK 13 FLUX STANDARD - 6
SCENARIO = 2 THICKNESStin meters) = .408
EMISSIONS REMAINING
REDUCTION IN EHISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
J
(pCi/sec)
(pCi/sec)
COST
1
2,132,913.0
0.0
$0
2
2,132,913.0
0,0
so
3
2,132,913.0
0.0
so
4
2,132,913.0
0.0
$0
5
2,132,913.0
0.0
$0
6
2,132,913.0
0.0
$0
7
2,132,913.0
0.0
so
8
2,132,913.0
0.0
so
9
2,132,913.0
0.0
so
10
2,132,913.0
0.0
so
11
2,132,913.0
0.0
so
12
2,132,913.0
0.0
so
13
2,132,913.0
0.0
so
14
2,132,913.0
0.0
so
15
2,132,913.0
0.0
so
16
2,132,913.0
0.0
so
17
2,132,913.0
0.0
so
18
2,132,913.0
0.0
so
19
2,132,913.0
0.0
so
20
2,132,913.0
0.0
so
21
2,132,913.0
0,0
so
22
2,132,913.0
0.0
so
23
2,132,913.0
0.0
so
24
2,132,913.0
0.0
$0
25
2,132,913.0
0.0
so
26
2,132,913.0
0.0
so
27
2,132,913.0
0.0
so
28
2,132,913.0
0.0
so
29
2,132,913.0
0.0
so
30
2,132,913.0
0.0
so
31
2,132,913.0
0.0
so
32
2,132,913.0
0.0
so
33
2,132,913.0
0.0
so
34
2,132,913.0
0.0
so
35
2,132,913.0
0.0
so
36
2,132,913.0
0.0
so
37
2,132,913.0
0.0
so
38
2,132,913.0
0,0
so
39
2,132,913.0
0,0
so
40
2,132,913.0
0,0
so
41
2,132,913.0
0.0
so
42
2,132,913.0
0.0
$0
43
2,132,913.0
0.0
so
44
2,132,913.0
0.0
so
45
2,132,913.0
0,0
so
46
2,132,913.0
0.0
so
47
2,132,913.0
0.0
$0
48
2,132,913.0
0.0
so
49
2,132,913.0
0.0
so
50
2,132,913.0
0.0
so
-------
APPENDIX TO CHAPTER 9
EFFECTS OF CONTROLS FOR STACK 14 FLUX STANDARD = 6
SCENARIO - 2 THICKNESS(in meters) = .408
EMISSIONS REMAINING
REDUCTION IN EMISSIONS
AFTER CONTROLS
DUE TO CONTROLS
ANNUAL
TEAR
(pCi/sec)
(pCi/sec)
COST
1
3,567,610.0
0.0
$0
2
2,213,060.0
2,213,060.0
$5,988,147
3
2,213,060.0
2,213,060.0
$154,915
4
2,213,060.0
2,213,060.0
$154,915
S
2,213,060.0
2,213,060.0
$154,915
6
2,213,060.0
2,213,060.0
$154,915
7
2,213,060.0
2,213,060.0
$154,915
8
2,213,060.0
2,213,060.0
$154,915
9
2,213,060.0
2,213,060.0
$154,915
10
2,213,060.0
2,213,060.0
$154,915
11
2,213,060.0
2,213,060.0
$154,915
12
2,213,060.0
2,213,060.0
$154,915
13
2,213,060.0
2,213,060.0
$154,915
14
2,213,060.0
2,213,060.0
$154,915
15
2,213,060.0
2,213,060.0
$154,915
16
2,213,060.0
2,213,060.0
$154,915
17
2,213,060.0
2,213,060.0
$154,915
18
2,213,060.0
2,213,060.0
$154,915
19
2,213,060.0
2,213,060.0
$154,915
20
2,213,060.0
2,213,060.0
$154,915
21
2,213,060.0
2,213,060.0
$154,915
22
2,213,060.0
2,213,060.0
$154,915
23
2,213,060.0
2,213,060.0
$154,915
24
2,213,060.0
2,213,060.0
$154,915
25
2,213,060.0
2,213,060.0
$154,915
26
2,213,060.0
2,213,060.0
$154,915
27
2,213,060.0
2,213,060.0
$154,915
28
2,213,060.0
2,213,060.0
$154,915
29
2,213,060.0
2,213,060.0
$154,915
30
2,213,060.0
2,213,060.0
$154,915
31
2,213,060.0
2,213,060.0
$154,915
32
2,213,060.0
2,213,060.0
$154,915
33
2,213,060.0
2,213,060.0
$154,915
34
2,213,060.0
2,213,060.0
$154,915
35
2,213,060.0
2,213,060.0
$154,915
36
2,213,060.0
2,213,060.0
$154,915
37
2,213,060.0
2,213,060.0
$154,915
38
2,213,060.0
2,213,060.0
$154,915
39
2,213,060.0
2,213,060.0
$154,915
40
2,213,060.0
2,213,060.0
$154,915
41
2,213,060.0
2,213,060.0
$154,915
42
2,213,060.0
2,213,060.0
$154,915
43
2,213,060.0
2,213,060.0
$154,915
44
2,213,060.0
2,213,060.0
$154,915
45
2,213,060.0
2,213,060.0
$154,915
46
2,213,060.0
2,213,060.0
$154,915
4 7
2,213,060.0
2,213,060.0
$154,915
48
2,213,060.0
2,213,060.0
$154,915
49
2,213,060.0
2,213,060.0
$154,915
50
2,213,060.0
2,213,060.0
$154,915
-------
Appendix B:
-------
Appendix B: Description Of The Trade Forecasting Model
9.B.1 Introduction
Many uncertainties exist in forecasting the supply and demand of WPP A. The model that was
developed uses various supply, demand, and cost forecasts in an attempt to test the competitiveness
of the United States phosphate industry over the next 30 years. The data used includes:
1) Plant specific cost and capacity data for 32 plants in the U.S., Morocco, Tunisia, Senegal,
Israel, and Jordan. This data, from a study by Zellars-Williams, [ZE86] includes detailed
production costs and supply forecasts until 2005. The regions of the world covered by this
data include all regions that are significant net exporters of phosphoric acid and phosphate
fertilizers.
2) A consumption forecast by region through 2010 by Wharton Econometric Forecasting
Associates [WEFA88],
3) Freight forecasts by Zellars-Williams through 2005 from the major exporters to the major
importers.
4) Alternative rock mining costs from a U.S. Bureau of Mines study by R. Fantel, William
Stowasser and others [Fa85],
With the exception of WEFA's consumption forecast, all of the forecasts do not go beyond 2005.
Therefore some limited assumptions were made to extend the forecasts to the year 2018. Various
modifications to the data sources listed above were also necessary to reconcile the data sources. All
of these modifications and the operation of the model are described below.
WPP A is sold in several different forms. Some countries purchase the acid and domestically produce
various fertilizers, while other countries purchase finished fertilizers. For simplicity, the model
focuses only on the comparative cost of producing phosphoric acid and does not consider the cost of
producing specific fertilizers, such as diammonium phosphate and triple superphosphate.
The purpose of the model is to identify the low cost suppliers for each importing region over the next
thirty years. The model considers six regions: Latin America, Western Europe, Eastern Europe, South
Central Asia, East Asia, and Oceania. There are three exporting regions which are North America,
Africa, and West Asia. Below is a description of the calculations made for the years 1985, 1990,
1995, 2000, 2005, and 2018.
9-BI
-------
9.B.2 Model Structure
The model begins by comparing the quantity of phosphoric acid each importing region needs to
import to satisfy its demand and the cost of each exporting plant. The appropriate transportation cost
is added into the plants' production cost to represent the final cost for that particular exporting
country. The model ranks suppliers for each importing region, from the lowest to the highest cost
supplier. The supply is then distributed in each region, beginning with the lowest cost supplier, until
all demand is satisfied. In this way each supplier is assumed to maximize profits by first supplying
those regions where its costs are the lowest.
Several alterations were made to the data that is used in the model. First, the Zellars-Williams supply
forecast included Turkey in its Western Europe figures, whereas the WEFA consumption forecast
included Turkey in its Asian figures. In addition, WEFA and Zeliars-Wiliiams organized Asian
supply and demand differently. Section 9.B.3 describes how the data was modified.
WEFA's consumption figures were extended to 2018 by taking the 2010 figures and using the WEFA
1.9 percent annual growth rate forecast for consumption until 2010.
The Zeliars-Wiliiams supply forecast was extremely conservative, predicting increases only where
firm plans had been announced at the time the forecast was made. As a result, many regions showed
only very slight increases after 1995 despite highly favorable production conditions. Under Zeliars-
Wiliiams' cautious supply forecast, world supply increases from 34 million metric tons In 1985 to 3?
million in 1995 and drops to 34 million in 2005. In comparison, WEFA's consumption forecast
increases from 33 million in 1985 to 38.5 in 1995 to 45.6 million in 2005. Zellars-Williams'
consumption forecast is even higher, 59.8 million in 2005 [ZE86]. Consequently, Zeliars-Wiliiams*
supply forecast was revised to increase at a rate comparable to the increase in world demand. More
detail on the assumptions made in revising their supply estimates are given in section 9.B.4.
Production capacities and costs for individual phosphoric acid plants were taken from a Zeliars-
Wiliiams' study [ZE86], All United States plants were included except for two: Arcadian's plant in
Geismar, Louisiana and Mississippi Chemical Co. plant in Pascagoula, Mississippi. Capacities for
these two plants were obtained from the Tennessee Valley Authority, [TVA88] and their costs were
assumed to be the same as those for Mobil's plant in Pasadena, Texas.
9-B2
-------
One Canadian plan! was included in the Zellars-Wtlltams* study, and a composite plant called Other
Canada was added lo represent all other Canadian production. Production capacity levels for Canada
were also obtained from the Tennessee Valley Authority, These two plants are included only because
all North American forecasts have Canada included in their figures.
Plant specific data was also available for Morocco, Tunisia, Senegal, Jordan, and Israel, which are
the major non-U.S. exporting nations. Two composite plants — Other Africa and Other West Asia
-- were added which represent the sum of the additional supply from plants in that region. These
composite plants are assumed to produce at the average cost for that region.
With some exceptions described in section 9.B.4, costs for all U.S. plants were projected out to 2018
from 2005 by continuing the rate of increase evident between 1985 and 2005. For non-U.S. plants
in which costs were declining (in constant dollars) between 1985 and 2005, costs were assumed to
remain the same as in 2005. This is reasonable because by 2005 the phosphate industries of non-
U.S. exporters will have fully matured and learning curve economies and economies of scale will be
achieved.
U.S. production capacities in 2018 were assumed to be the same as the Zellars-Williams forecasts for
2005. For specific plants in Zellars-Williams' projections, capacity increases before 2000 but beyond
2000 there are no increases or decreases. However, in Zellars-Williams' aggregate U.S. supply
forecasts for the year 2005, Zellars-Williams' estimated capacity for North America falls to 8,906,000
metric tons of capacity, though their plant specific data indicates capacity would be 12,087,000
metric tons. It is likely that Zellars-Williams kept plant specific capacities at this higher level to
avoid having to guess which plants might close by 2005. However, in their analysis they obviously
expect some closures among U.S. plants.
The model was run under two different cost scenarios for plants located in the U.S. which obtain
their rock from central Florida. In one case, costs were as forecasted by Zellars-Williams. In the
other case, production costs were increased to reflect higher rock costs in Florida, beginning in 1995,
as old low cost reserves become depleted and new, lower quality rock resources need to be developed.
To estimate the phosphate rock costs from new resources, rock cost estimates were taken from a U.S.
Bureau of Mines study by Stowasser, Fantel and Peterson which estimates the quantity of rock
available within certain ranges of cost [Fa85], The amount of rock needed in 2000 was calculated
from the supply forecast for WPPA, and from this the rock price was estimated and applied to plants
whose rock comes from the Central Florida pool. Some companies own phosphate rock reserves and
active mines that will still be operating after 1995. Data was available from Zellars-Williams in many
9-B3
-------
of these cases and Zeltars-Wiliiams' estimate of the cost to the company of mining its own rock was
used.
The second scenario of the mode! allowed for significantly higher rock mining costs for a variety of
U.S. plants. The U.S. plants were divided into two groups according to where their rock is supplied.
Plants receiving rock from central Florida were given rock costs in line with the Stowasser study
described earlier. The range of rock costs found in the Zellars-Williams cost data was maintained
but each plant's rock costs were increased by a similar proportion so that the average rock costs
corresponded to Stowasser's forecast. The exhaustion of cheaper rock begins in the 1995 period and
the full costs are attributed by the year 2000. The higher rock costs were incorporated into the total
WPPA costs by assuming 3.55 tons of rock are used per metric ton of WPPA produced.
9.B.3 Distribution of Exporters Total Supply
When distributing a plant's production among several regions, the model makes a few simple
assumptions. First, if supplier X can competitively supply four different regions and, for example,
X ranks third in all four regions, then each region receives an equal portion of supplier X's
production. If supplier X then appears fourth on another region's ranking, that region will receive
nothing from supplier X because X's production will have already been sold for that year.
In the non-U.S. net exporting regions, Africa and West Asia, domestic demand is assumed to be
supplied by the many other plants in those countries for which plant specific costs are not available.
Other excess capacity in those countries was assigned to composite plants called Other Africa or Other
West Asia. The cost attributed to this other production is the average of all the individual costs for
that region. This production is also available for export.
If supplier X is a non-U.S. producer, then all of its production will be exported.
For North America, a different assumption is made because cost data is available for all but two small
plants, and supply is expected to fall rather than increase. In the case where supplier X is a U.S.
plant and X is the third lowest cost supplier in four regions, the supply available from X is divided
by 6, with one share going to each of the four importing regions, and two shares going to the U.S.
market. The U.S. market always gets two shares, which assumes each producer continues to be
actively involved in the large U.S. market. This assumption is consistent with American producer's
past behavior.
9-B4
-------
9.B.4 Modifications to Zellars-Williams and WEFA Data
The Zellars-Wiiliams supply forecast was altered so that Turkey appeared in its West Asia figures.
Because Turkey has some indigenous phosphate rock supply, Turkey's supply was forecasted to
decline at only half the rate of decline forecast for Western Europe. Turkey's supply was then
subtracted from the Western European figure and added to the West Asia figure.
WEFA's consumption forecast included all of Asia in one figure, whereas Zellars-Wiiliams divided
Asia into East, West, and South Central. The following method was used to divide WEFA's Asian
consumption forecast. First, Turkey's consumption was calculated by taking their 1985 consumption
and using WEFA's annual growth rates to forecast their consumption. A growth rate of 2.1 percent
was used through 1995 and 1.9 percent was used thereafter. Next, Turkey's consumption figures
were added to Zellars-Wiiliams' West Asia consumption figures. Third, the percent of total Asian
consumption represented by each region of Asia was calculated using the Zellars-Wiiliams
consumption figures, which were constant for all of the forecasted years. These percentages were
then applied to the WEFA Asian consumption forecasts to derive the final subdivided Asian
consumption forecasts.
As explained earlier, Zellars-Wiiliams' supply forecast was modified to allow for new plant
construction that has not already been announced. Special attention was given to how the new supply
was distributed among existing producing countries. The regional trends in production levels
identified by Zellars-Wiiliams between 1985 and 1990 were projected to continue in future years.
Had the rate of growth between 1985 and 1990 been used, however, an unrealistically high supply
level would have been forecasted. Instead, the WEFA projected rate of growth of demand was used.
This assumes that, in the long run, supply and demand will grow at the same rate. Those regions
experiencing growth in capacity between 1985 and 1990 were assumed to continue to have high rates
of growth in the coming decade. These countries, such as Morocco, are also the countries that have
substantial demonstrated phosphate rock reserves. The specific steps to calculate each region's supply
are described below:
1) The increase in world supply between 1985 and 1990 was estimated and each region was
allocated its proportion of that supply. As in; (A-B)/C; where;
A=1990 regional forecast.
B=I985 regional forecast,
C=Net new world supply between 1985 and 1990.
2) The world supply of phosphoric acid after 1990 was estimated by using a 2.1 percent
annual growth rate until 1995 and 1.9 percent thereafter.
9-B5
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CHAPTER 10
COAL-FIRED BOILERS
-------
10. COAL-FIRED BOILERS
10.1 Introduction and Summary
On November 8, 1979 the Environmental Protection Agency listed radionuclides as a hazardous air
pollutant under the provisions of section 112 of the Clean Air Act. Subsequently, EPA investigated
the necessity of regulating coal-fired boilers in the utility and industrial sectors. These two types of
boilers account for approximately 90 percent of the heat generated by burning coal. The remaining
10 percent is generated by residential and commercial boilers for the purpose of space and water
heating. For this analysis, only coal-fired utility and industrial boilers will be considered.
The coal used to fire boilers contains radionuclides and their daughter products which are not
destroyed during combustion. Instead, the radionuclides attach themselves to particulate emissions
and are either removed from the exhaust with control devices or released into the air.
Currently, there are no Federal or state regulations specifically limiting the emissions of radionuclides
from coal-fired industrial boilers. However, air emissions from coal-burning facilities are regulated
by state and Federal guidelines designed to meet the ambient standards set forth by the Federal Clean
Air Act. These standards affect several pollutants emitted by coal-burning facilities, in particular
particles 10 microns or less in diameter (PM10), sulfur dioxide, oxides of nitrogen, CO and lead (40
CFR 50.6, 50.7, 50.8, 50.11, 50.12). Emissions of radionuclides are positively correlated to emissions
of particulate matter; therefore, regulations governing particulate matter emissions also control
radionuclide emissions. These regulations include: the PM10 ambient standard, prevention of
significant deterioration, new source performance standards, and state air quality implementation
plans.
10.2 Industry Profile
The main function of large coal-fired boilers in the utility sector is the generation of electricity.
Industry, however, depends upon coal-fired boilers for the production of process steam, space
heating, and other industrial purposes. Information on utility boilers is far more complete, accurate,
and accessible than that on industrial boilers. The furnaces and coal used by both sectors, and
therefore the emissions created, are highly similar. There are, however, some differences in the
boilers used.
10-1
-------
10,2.1 Demand
In 1982, approximately 20 percent of the United States' energy needs were met by burning coal. Of
the coal used, 74 percent was used to generate electricity and 24 percent was used by industry for
purposes other than the generation of electricity [EIA85], For both industrial and utility applications
bituminous, sub-bituminous, and lignite coals are used more often than anthracite coal. Although
natural gas, oil, and nuclear fission can be used to generate electricity, the combined use of these
energy sources in the generation of electricity has declined in recent years. It is expected that coal
will supply more than half of the electricity generated in the United States in the foreseeable future.
10.2.2 SudpIv
On average, the United States coal mines provide more than 16 million tons of coal per week. This
amount fluctuates greatly, ranging from 20 million tons per week to less than 10 million. Coal
production can decrease for a variety of reasons, ranging from weather to miners' strikes and
vacations [EIA87],
The three primary coal producing regions in the United States are the western, interior, and
Appalachian regions. In 1985, in terms of quantity of coal produced, the Appalachian region was
the most productive, followed by the western and interior regions. In that year, the Appalachian
region produced 427.2 million short tons of coal, valued at 13.8 billion dollars. The western region
produced 268.7 short tons of coal at a value of 3.9 billion dollars. Coal production in the interior
region in 1985 was 187.8 million short tons valued at 4.6 billion dollars [EIA87],
10.2.3 Industry Structure and Profile
In 1986, there were approximately 1200 coal-fired utility boilers in the United States, with a net
generating capacity of 305 giga-watts (GW) [EIA85]. There are three types of power plants designed
to operate and serve three load classes: base load, intermediate load, and peaking plants. Base load
power plants operate near full capacity most of the time. Intermediate load plants operate at varying
levels of capacity each day. Finally, peaking plants operate only during periods of high demand,
about 700-800 hours a year. Coal-fired utility boilers are primarily used in base and intermediate
load plants. Coal is rarely the primary fuel for a peaking plant.
10-2
-------
There are three general types of coal-firing utility boilers: stoker furnaces, cyclone furnaces, and
pulverized-eoaf furnaces. Stoker furnaces are usually small, older boilers ranging in capacity from
7.3 to 73 mega-watts (MW). Stoker furnaces require about 3.3 kg of coal per kilowatt-hour and are
less efficient than furnaces handling pulverized coal. Cyclone furnaces are high temperature
combustion chambers for burning crushed coal. As of 1974, only 9 percent of the coal-fired utility
boiler capacity was of the cyclone type, and no boilers of this kind have been ordered by utilities in
the past seven years [Co75]. Pulverized coal furnaces burn coal that has been pulverized to a fine
powder. A carefully proportioned mixture of pulverized coal and air is injected into the combustion
zone. The pulverized coal-fired boiler is now the most prevalent type of coal-burning unit in the
utility sector. There are two types of pulverized coal-fired boilers; dry bottom and wet bottom. Dry
bottom are the most prevalent, with 76 percent of the coal-firing utility boilers being of this type.
Of the remaining coal-firing utility boilers, 11 percent are pulverized wet bottom, 11 percent are
cyclone, and 2 percent are stoker. The amount and type of residue produced when coal is burned
differs with the type of furnace and coal used. As coal is burned, the minerals in the coal melt and
condense into a glass-like ash; the quantity of ash depends upon the mineral content of the coal. A
portion of the ash settles to the bottom of the boiler, bottom ash, and the remainder enters the flue,
fly ash. The distribution between bottom ash and fly ash depends upon the firing method, the ash
fusion temperature of the coal, and the type of boiler bottom, wet or dry. Table 10-1 displays the
percent of fly and bottom ash produced by various types of coal and furnaces.
Coal-fired industrial boilers are used primarily to produce process steam, generate electricity for the
industry's on-site use, and provide space and water heat. Boilers are used in almost all industries;
however, the primary users are smelters, steel, aluminum, and copper manufacturers, pulp and paper
manufacturers, and the chemical industry. There are three main types of boilers used in the
industrial sector. These are: water tube, fire tube, and cast iron. Water tube boilers heat the water
to a high-pressure, high-temperature steam by passing the water through tubes which are heated
externally by contact with high combustion gases. Fire tube and cast iron boilers heat the water by
transferring heat from the hot gases inside the tubes to circulating water outside the tubes. The only
difference between the two types is that cast iron is used in the construction of the tubes instead of
steel which is used in fire tube boilers. Table 10-2 displays the number and capacity of industrial
boilers in the United States. There are two main types of furnaces used for industrial coal-fired
boilers. These are the pulverized coal furnace and the stoker furnace, as described in the previous
text.
10-3
-------
Table: 10-1: Coal Ash Distribution by Boiler Type.
Percent Fiv Ash/Percent Bottom Ash
Furnace Type
Bituminous
Lignite
Anthracite
Pulverized Dry Bottom
80/20
35/65
85/15
Pulverized Wet Bottom
65/35
Cyclone
13.5/86.5
30/70
Stoker
60/40
35/65
5/95
SOURCE: [MeB6]
10-4
-------
Table 10-2; Numbers and Capacities of Industrial Boilers.
Unit Capacity (MW Thermal Input)
Boiler Type 0-3 3-15 15-30 30-75 >75
Water Tube Units
683
2,309
1,290
1,181
423
Total MW
835
22,225
27,895
50,825
59,930
Fire Tube Units
8,112
1,224
Total MW
5,650
7,780
Cast Iron Units
35,965
Total MW
6,330
SOURCE; [EPA81]
10-5
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10.3 Current Emissions, Risk Levels, ant! Feasible Control Methods
10.3.1 Introduction
Coal contains mineral matter, including small quantities of naturally occurring radionuclides. The
radionuclides of primary interest are uranium-238 and thorium-232 as well as their decay products,
Po-210 and Pb-210, Table 10-3 shows the uranium and thorium content in different types of coal.
In addition to the concentration of mineral matter, several other factors have substantial influence
upon the harmful emissions from coal-fired boilers. These factors include furnace design, capacity,
heat rate, and ash partitioning. Ash partitioning, or the proportion of ash that is fly ash versus
bottom ash, is a function of the firing method, type of coal, and type of furnace used.
10.3.2 Current Emissions and Estimated Risk
Measurements have shown that certain radionuclides are partitioned unequally between bottom and
fly ash {Be78, Wa82]. One explanation for this phenomenon is that certain elements are preferentially
concentrated on the particle surfaces, resulting in their depletion in the bottom ash and their
enrichment in the fly ash [Sm80). The highest concentration of the trace elements in fly ash is found
in .5 to 10 micrometer diameter particulates, the size range that can be inhaled and deposited in the
lung. These fine particles are less effectively removed by particulate control devices than larger
particles. Uranium is enriched in fly ash relative to bottom ash, particularly in particles less than 1
micron in diameter. Thorium, however, shows virtually no small particle enrichment and is only
slightly enriched in fly ash.
'0.3.3 Control Technologies
The National Ambient Air Quality Standards require air emission controls for virtually all coal-fired
utility boilers in the United States. There are four types of conventional control devices commonly
used for control of particulate matter in utility boilers: electrostatic precipitators (ESP), mechanical
collectors, wet scrubbers, and fabric filters. Particulate emissions from industrial boilers are
controlled by similar devices. In theory, ESP, wet scrubbers, and fabric filters are all capable of
greater than 99.8 percent collection efficiencies for ash as small as one micron in diameter. At
present, almost all collectors are at least 98 percent efficient during normal operation.
10-6
-------
Table 10-3; Typical Uranium and Thorium Concentrations in Coal,
Region/
Coal Rank
Uranium
Range Geometric
mean
(ppm) (ppm)
Thorium
Range
(ppm)
Geometric
mean
(ppm)
Pennsylvania
Anthracite
0.3-25
Appalachian
Bituminous <0.2-11
NR. 0.4-3
Bituminous NR
Bituminous 0.1-19
Illinois Basin
NR 0.3-5
Bituminous 0.2-43
Bituminous 0.2-59
Northern Great Plains
Bituminous
Subbituminous <0.2-3
Subbituminous <0.1-16
Lignite 0.2-13
Western
NR 0.3-3
Rocky Mountain
Bituminous
Subbituminous 0.2-24
Subbituminous 0.1-76
Bituminous 0.1-42
All Coals <0.1-76
1.2
1.0
1.3
1.1
1.2
1.3
1.4
1.7
0.7
i.O
1.2
1.0
0.8
1.9
1.4
1.3
1.4-2.8
2.0-48
1.8-9
NR
NR
0.5-0.7
<3-79
0.1-79
<2-8
0.1-42
0.3-14
0.6-6
<3-35
0.1-54
<0.2-18
<0.1-79
4.7
2.8
4.0
2.0
3.1
1.9
1.6
3
2.4
3.2
2.3
2.3
2.0
4.4
3.0
3.2
Note: lppm uranium-238 is equivalent to 0.33 pCi/g of coal.
Ippm thorium-232 is equivalent to 0.11 pCi/g of coal.
NR - Not reported.
SOURCE: [EPA88]
10-7
-------
The risk assessment of utility boilers is based on reference (actual) facilities selected to represent
large and typical utility boilers. The reference facilities were selected from a data base of almost one
thousand utility boilers maintained by the EPA's Office of Air Quality Planning and Standards
(OAQPS). The boilers in the data base account for virtually all of the coal used by utility boilers.
The risk assessment of industrial boilers is based on a single reference plant. The reference plant has
the largest estimated release of total particulates of the industrial boilers in OAQPS' data base of
about 500 industrial boilers [EPAS9], The coal-fired industrial boilers in the OAQPS data base
represent a stratified random sample of more than 2,000 industrial boilers located throughout the
United States. In selecting the reference utility boilers, the boilers in the data base were classified
according to the number of persons living within 50 kilometers of the plant. Urban plants were
defined as having 3,000,000 persons or more, suburban plants as having 800,000 to 3,000,000 persons,
rural plants as having 100,000 to 800,000 persons, and remote plants as having less than 100,000
persons. This classification shows 34 utility boilers located in urban areas, 234 located in suburban
areas, 567 located in rural areas, and 150 located in remote areas. For each location, the large
reference plant and the typical reference plant were chosen based on the estimate of total particulate
emissions. The large reference plants were used in the evaluation of the risks to nearby individuals
and the typical reference plants were used to evaluate the magnitude and distribution of the
population risk. Tables 10-4 and 10-5 give a summary of U-238 and Th-232 emission factors by
coal-fired utility boiler type and control technique.
10.4 Analysis of Benefits and Costs
10.4.1 Introduction
As already mentioned, there are currently several state and Federal regulations regarding the
emissions from coal-fired boilers. Therefore, any cost-benefit analysis would be of further specific
regulations and more stringent controls. In order to determine the amount of further regulations
necessary, the radionuclide related risks from coal-fired emissions must first be assessed. Several
assumptions were made in carrying out risk calculations in order to lend conservatism to the results.
Food input parameters were computed for the food growing capabilities of each population category.
For urban and remote utility boilers it was assumed that individuals residing in the fallout region
of these plants also supplied all of their own meat and milk. In the case of suburban utilities, it was
assumed that half of the ingested fruit and vegetables were grown at home and that the remainder
of the fruits and vegetables as well as the meat and milk were supplied regionally. For urban
utilities, it was assumed that everything was supplied regionally and nothing was grown at home.
10-8
-------
Table 10-4: U-238 Emission Factors for Coal-Fired Utility Boilers,
Emission Factor
Boiler Type/
Control
Average
(pCi/g)
Range
(pCi/g)
Emission Factor
Average Range
(pCi/MBTU) (pCi/MBTU)
Pulverized Drv Bottom
ESP
ESP/Scrubber
Scrubber
Pulverized Slag Bottom
Mechanical/ESP
Cvclone
ESP
Scrubber
6.55
7.1
5.6
0.004
1.5
13.9
3.3-9.2
0.005-3.0
0.017-37.5
295.3
22.5
73.7
68.0
1757.8
6.3-675.9
301.2-3214.3
Stoker
Fabric Filter
ESP
Unspecified
ESP
0.003
0.5
16.1
7-34.2
294
101.6-486.5
MBTU = million BTU.
SOURCE: [Me86]
10-9
-------
Table 10-5; Tb-232 Emission Factors for Coal-Fired Utility Boilers.
Emission Factor Emission Factor
Boiler Type/ Average Range Average Range
Control (pCi/g) (pCi/g) (pCi/MBTU) (pCi/MBTU)
Pulverized Drv Bottom
ESP
ESP/S crubber
Scrubber
Cvclone
ESP
Scrubber
3.0
7.14
2.78
1.8
2.09
0.6-5.3
1.5-2.68
170.0
22.7
36.5
40.8
170.0
50.3-180.7
110.2-229.7
StQk.gr
ESP
0.5
13,8
MBTU = million BTU.
SOURCE; [Me86]
10-10
-------
10-4-2 Least-Cost Control Technologies
Selection of particulate control devices for a particular utility is a function of several variables,
including boiler capacity, boiler type, inlet loading, fly ash characteristics, and inlet particle size
distribution. Virtually all coal-fired utility boilers in the United States are required to have air
emission controls in order to meet National Air Quality Standards (NAAQS). The least costly option
for increased control of radionuclide emissions is continued reliance on on-going measures taken to
conform to clean air act requirements for NAAQS and the precursors of acid rain. These tend to be
updated as new technologies become available. For example, the recent development of highly
temperature resistant fabrics has resulted in the increased use of fabric filters in the reduction of
boiler emissions. However, increased efficiency of control technologies will be expensive because
the current technologies comprised mainly of electrostatic precipitators (ESP), mechanical collectors,
wet scrubbers, and fabric filters are now at least 98 percent effective during normal operation,
10.4.3 Health and Other Benefits
Table 10-6 shows the estimated radiation dose rates from large coal-fired utility boilers for each
population category. Similar data is displayed in Table 10-7 for a reference coal-fired industrial
boiler. Tables 10-8 and 10-9 show the estimated distribution of the fatal cancer risk to the regional
populations from all coal-fired utility and industrial boilers.
10.4.4 Estimates of Benefits and Costs
Existing boilers can be retrofitted with additional electrostatic precipitators to reduce emissions to
the level prescribed for new sources (13 ng/J). Although a full evaluation of supplementary control
options and costs has not been performed for industrial boilers; it is known that existing boilers could
be retrofitted with ESPs. It is estimated that retrofitting ESPs at industrial boilers with heat inputs
over 2E+6 MBTU/hr would reduce particulate emissions by a factor of two. The cost and health
benefits are not known. With all coal-fired utility boilers operating with particulate emissions of 13
ng/J (0.03 lb/MBTU) of heat input, the current 12,500 million MBTU annual heat input would
result in about 0.17 billion kg of particulate releases. The source term and potential health impact
would therefore be reduced by about a factor of two. The estimate of the total deaths per year would
drop to 0,2. The EPA's office of Air Quality Planning and Standards has estimated the costs of
retrofitting all existing utility coal-fired boilers to meet the control level of 13ng/J to be about $13
billion in capital costs (1982 dollars) and about $3.4 billion in annual costs [RC83],
10-11
-------
Table 10-6: Estimated Radiation Dose Rates from Large Coal-Fired Utility Boilers.
Nearby Regional
Facility Organ Individuals Population
(mrem/y) (person-rem/y)
Remote
Bone Surface
1.1E+0
2.9E+1
Remainder
3.1E-I
4.4E+0
Gonads
2.7E-1
3.1E+0
Red Marrow
2.7E-1
—
Lung
I.6E+1
Rural
Bone Surface
1.2E+1
3.9E+1
Remainder
2.1E+0
5.6E+0
Red Marrow
1.SE+0
4.2E+0
Gonads
1.0E+0
2.0E+0
Lung
—
6.6E+0
Suburban
Gonads
5.2E-1
5.3E+0
Breast
4.9E-1
___
Remainder
4.1E-1
9.2E+0
Red Marrow
4.0E-1
7.9E+0
Lung
4.0E-1
1.9E+1
Bone Surface
—
5.9E+1
Urban
Gonads
3.5E-1
6.8E+0
Breast
3.2E-1
—
Remainder
2.7E-1
9.6E+0
Red Marrow
2.7E-1
—
Lung
2.6E-1
3.7E+1
Bone Surface
—
6.5E+1
SOURCE: [EPA88]
10-12
-------
Table 10-7: Estimated Radiation Dose Rates fro* tie Reference Coal-Fired Industrial Boiler.
Nearby Regional
Organ Individuals Population
(mrem/y) (person-rem/y)
Bone Surface 6.5E+0 5.6E+1
Remainder 9.0E-1 5.8E+0
Red Marrow 6.1E-1 ----
Lung ---- 2.1E+1
SOURCE: [EPA88]
10-13
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Table 10-8.* Estimated Distribution of the Fatal Cancer Risk to the regional (0-80kni) populations
from all Coal-Fired Utility Boilers.
Risk Number of
Interval Persons Deaths/y
1E-1 to 1E+0
0
0
1E-2 to 1E-1
0
0
1E-3 to 1E-2
0
0
1E-4 to 1E-3
0
0
1E-5 to 1E-4
0
0
1E-6 to 1E-5
1.3E+5
IE-3
Less than IE-6
2.4E+8
4E-1
Totals
2.4E+8
4E-1
SOURCE: [EPA88]
10-14
-------
Table 10-9: Estimated Distribution of the Fatal Cancer Risk to tie regional (0-80km) populations
from all Coal-Fired Industrial Boilers.
Risk Number of
Interval Persons Deaths/y
1E-1 to 1E+0
0
0
IE-2 to 1E-1
0
0
IE-3 to 1E-2
0
0
IE-4 to 1E-3
0
0
1E-5 to 1E-4
0
0
1E-6 to 1E-5
*
»
Less than 1E-6
2.4E+8
4E-1
Totals
2.4E+8
4E-1
* The results of the risk assessment of the model facility indicate that there may be individuals in
this risk interval. However, data are insufficient to provide quantitative estimates.
SOURCE: [EPA88]
10-15
-------
Figures published in the Federal Register predict the capital costs to utilities of retrofitting existing
coal-fired boilers to meet Clean Air Act requirements pertaining to criteria air pollutants to be
slightly higher. Capital improvement costs are estimated to be approximately $15 billion and the
subsequent operating costs are estimated to be approximately $3 billion a year [FR83],
10-16
-------
REFERENCES
Be78 Beck, H.L., Perturbation of the Natural Radiation Environment Due to the Utilization
of Coal as an Energy Source, Proceedings, DOE/UT Symposium on the Natural
Radiation Environment, Houston, TX, 1978.
Co75 Cowherd, C. et al,, Hazardous Emission Characteristics of Utility Boilers, NTIS PB-
245-915, 1975.
EIA85 Energy Information Agency, Department of Energy, Annual Energy Outlook, 1985,
Washington, D.C.
E1A87 Energy Information Agency, Department of Energy, Coal Data: A Reference,
Washington, D.C.; March 1987, page 14.
EPA81 Environmental Protection Agency, The Radiological Impact of Coal-fired Industrial
Boilers, EPA, Office of Radiation Programs, Washington, D.C., (Draft Report), 1981.
EPAS8 Risk Assessments, Vol. 2,EPA88
EPA89 U.S. Environmental Protection Agency, "Coal and Oil Combustion Study: Summary
and Results," draft report in preparation, Office of Air Quality, Planning and
Standards, Research Triangle Park, NC, scheduled for publication during 1989.
FR83 Federal Register, Volume 48 Number 67, April 6, 1983, page 15085, 15086.
Me86 Mead, R.C., B.K.. Post, and G.W. Brooks, "Summary of Trace Emissions from, and
Recommendations of Risk Assessment Methodologies for Coal and Oil Combustion
Sources", Radian No. 203-024-41, Radian Corporation, Research Triangte Park, N.C.,
1986.
RC83 Radian Corporation, Boiler Radionuclide Emissions Control: The Feasibility and Costs
of Controlling Coal-Fired Boiler Particulate Emissions, Prepared for the
Environmental Protection Agency, January 1983.
Sm80 Smith, R.D., The Trace Element Chemistry of Coal During Combustion and the
Emissions from Coal-Fired Plants, Progress in Energy and Combustion Science 6, 53-
119, 1980.
Wa$2 Wagner P. and Greiner N.R., Third Annual Report, Radioactive Emissions from Coal
Production and Utilization, October 1, 1980-September 30, 1981LA-9359 -PR, Los
Alamos National Laboratory, Los Alamos, N.M., 1982.
10-17
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CHAPTER 11
NRC-LICENSED FACIUTIES AND NON-DOE FEDERAL FACILITIES
-------
11. NRC-LICENSED FACILITIES AND NON-DOE FEDERAL FACILITIES
11.1 Introduction and Summary
This chapter covers Nuclear Regulatory Commission (NRC) licensed facilities that are not part of the
nuclear fuel cycle and federal facilities using radionuclides other than those owned or operated by
the Department of Energy (DOE), DOE facilities are discussed in chapters 6 and 7. The NRC and
the Agreement States licensees are classified into by-product, source material, and special nuclear
material categories. For purposes of this evaluation, these source categories are analyzed on the basis
of nine sub-categories:
o Hospitals,
o Radiopharmaceutical manufacturers,
o Research laboratories,
o Research reactors,
o Sealed source manufacturers,
o Non-LWR fuel fabricators,
o Source material licensees,
o Low-level waste incinerators, and
o Non-DOE Federal facilities.
The approximately 6,000 facilities which fall into these categories are located in 50 states. The
largest group consists of approximately 3,680 hospitals, which are licensed to handle
radiopharmaceuticals. The next largest group consists of about 1,500 research laboratories. The
information used for this evaluation was derived from literature search and review, and direct contact
with the licensees and the NRC. After developing information on the emissions for each facility or
facility class, an assessment was performed of the radiation dose and risk to the nearby and regional
populations. If the assessment resulted in a significant predicted risk, then supplementary control
options and costs were evaluated. Only two of the nine sub-categories warranted analysis of
supplementary controls after the assessment of risks was conducted. The combined risk for all nine
sub-categories is 2E-1 fatal cancers per year. The individual risk is also quite low, with all but two
of the facilities resulting in doses of less than 1 mrem/yr to the nearby resident.
11-1
-------
11.2 Industry Profile
Due to the large number and variety of sources, it is not feasible nor useful to develop a detailed
industry profile. A brief description of each sub-category follows. Over half of the hospitals in the
United States handle radiopharmaceuticals [AHA86], The most prevalent use is for radionuclide
imaging to aid in diagnosis of diseases. A smaller number of hospitals also use radionuclides for
therapeutic purposes. Two-thirds of hospitals using therapeutic amounts of radiopharmaceuticals are
located in urban areas.
Radiopharmaceutical manufacturers, which number about 120, fall into three sub-categories. There
are 15 large firms which manufacture the pharmaceuticals, 70 small- to medium-sized firms which
alter the chemical form of the nuclides, and 35 nuclear pharmacy operators which repackage the
material into convenient quantities for distribution.
There are approximately 1,500 research laboratories which use radionuclides in unsealed forms. Over
half of these laboratories are associated with academic institutions and the remainder with
government or private research facilities [CEN81,BAT83,NRC88]. The academic laboratories
frequently involve a large number of release points within a generalized area and use small amounts
of a large number of radionuclides. Twenty-nine radionuclides were identified as in use. One use
of radioactively-labeled chemicals is to trace dynamic processes.
There were 70 research and test reactors operating as of December, 1987. These reactors range in
power level from zero to 10,000 kilowatts and are generally operated by universities for use in
teaching and research. Although there are a number of different designs, the most common is the
General Atomics TRIGA reactor.
Sealed-source manufacturers take radionuclides in unsealed form and put them into permanently
sealed containers. There are two sub-categories of sealed source manufacturers - those that seal
tritium gas into seif-iuminous lights (three manufacturers) and those who utilize other radiation
sources (eight manufacturers which release more than exempt quantities of radionuclides).
Four facilities fabricate uranium fuel for research reactors or naval propulsion reactors. The process
is similar to that used in the uranium fuel cycle, whereby enriched UO2 is formed into pellets which
are stacked inside tubes and then bundled into fuel assemblies.
11-2
-------
Twelve NRC-licensed facilities were identified that handle relatively large amounts of thorium or
non-enriched uranium during the manufacture of a product. Nine of these facilities are currently
using thorium [M088]. An equal number of facilities are also licensed by the Agreement States. The
processes used by these facilities are varied and may include processing lower thorium-content alloys
into wire for lighting products, as well as scrap collection, glass production, and lens coating.
Airborne effluents are also produced by the incineration of low-level waste, primarily from hospitals
and research laboratories. It is estimated that there are about 100 incinerators in the United States.
The Non-DOE Federal facilities are composed of two groups of Department of Defense facilities --
thirteen nuclear shipyards and naval bases and two unlicensed research reactors located at Aberdeen,
Maryland and White Sands, New Mexico.
11.3 Current Emissions. Risk Levels, and Feasible Control Methods
11.3.1 Introduction
Due to the large number and variety of sources in this category, only a general description will be
provided here as to the nature of the emissions, how the risks were estimated, and feasible control
methods. Detailed descriptions and data can be found in the supporting documentation cited in the
references below. The individual sub-category and total risks for both the nearby and regional
populations are found in Table 1J-1. These fatal cancer risks are estimated using assumptions
concerning the facility emissions and release point characteristics, the proximity of nearby
individuals, the meteorology for the sites, and estimates of organ exposures in mrem/yr, resulting in
estimated risks of fatal cancer for both nearby and regional populations.
11 -3.2 Current Emissions and Estimated Risk Levels
Emissions data for the hospitals were derived from a survey of over 100 facilities and were used to
create a model facility [CRC87], The primary emissions are xenon and iodine, and the emission rates
range from 0.01 to 1.0 Ci/yr. The estimated risks were calculated for both urban and rural settings
and multiplied by the number of facilities of each type to generate a total risk of 6E-2 deaths per
year (d/yr).
The emissions for the radiopharmaceutical suppliers are based on data received directly from four
suppliers, including effluent data reported to the NRC for a nuclear reactor. Almost all the risk is
11-3
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Table 11-1 NRC Licensed and Non-DOE Facilities
Fatal Cancers Per Year
Category
Hospitals
Radiopharmaceutical
Manufacturers
Research Laboratories
Research Reactors
Sealed Source Manufacturers
Non-LWR Fuel Fabricator
Source Material Licensee
Low-level Waste
Non-DOE Federal Facilities
TOTAL
No. of Facilities
3680
Fatal Cancers
(d/yr)
120
1500
70
11
4
12
100
15
6000
6E-2
2E-2
8E-3
4E-2
2E-2
2E-4
1E-3
1E-3
1E-3
2E-1
11-4
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accounted for by the facility that operates the nuclear reactor. The total risk is obtained by summing
the risks from all sixteen facilities, and is estimated to be 2E-2 d/yr,
Emissions data were gathered from 46 research laboratories and compared to information from other
available sources [BAT83, CRC87]. Approximately forty-one percent of all laboratories have
emissions that are either zero or below the lower limits of detection of their monitoring equipment.
A model facility was developed using a weighted average of the remaining facilities by type and
multiplying by the number of facilities (622) having non-zero emissions. The total risk is estimated
to be 8E-3 d/yr.
Emissions data were collected for the four largest emitters among research and test reactors. The
resulting risks were extrapolated to the entire population based upon the contribution of the four
largest emitters to the total emissions. The ratio was calculated based on Ar-41 emissions which were
found to be fifty-nine percent of the total emissions for this sub-category. The total risk is estimated
to be 4E-2 d/yr.
A model sealed source facility was estimated based upon the average emissions of four non-tritium
manufacturers. Kr-85 is released in curie amounts and Co-60, Am-241, Ir-192, and Cf-252 in
microcurie amounts. The tritium lighting producers all submitted information on their effluents so
these data were used directly with site-specific information on meteorology. The total risk of 2E-
2 d/yr is equal to the sum of the estimated doses from the three lighting facilities and the product
of the total emissions of the model facility and the total number of facilities.
Operating reports were used for the emissions from non-LWR fuel fabricators. U-234 and U-235
are the nuclides which make the largest contribution to dose. Actual site characteristics, facility data,
and local meteorological data were utilized. Total risk for this category is estimated to be 2E-4 d/yr.
Two reference facilities to represent source material licensees were used for the estimate of thorium
and uranium emissions and their associated risks. The risk was obtained by multiplying the results
by the number of facilities in this category. The total risk for this category is estimated to be 1E-
3 d/yr.
Effluent data for 35 incinerators are available from a survey for the estimate of emissions from low-
level waste [CRC87], A model facility was created based upon these data. Data for the largest emitter
was also modified. The model facility is estimated to result in 1E-5 fatal cancers per year, while the
maximum emitter is estimated to result in 2E-4 fatal cancers per year. The total risk for this
11-5
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category, obtained by scaling up the risks from the model facility by a factor of 100, is estimated to
be IE-3 d/yr.
With respect to non-DOE federal facilities, a single model, was used to represent both Naval
shipyards and the two non-licensed research reactors in Maryland and New Mexico. The model was
based on emissions measured at the shipyards. Effluent monitoring at Department of Defense
shipyards and bases reveals few measurable radionuclide releases [Ma88]. The Navy estimates
maximum releases of noble gases to be 0.01 - 0.4 Ci/yr and of Co-60, 0.001 Ci/yr. An actual West-
coast shipyard was used as the model facility to estimate the risks based upon the above emission
rates. The risks from all DOD facilities is estimated to be 1E-3 d/yr.
The calculated risks summarized above are combined to provide an estimated baseline risk for the
active category of 2E-1 d/yr. The sub-category with the largest collective risk is hospitals.
11.3.3 Control Technologies
Depending upon the effluent stream type and characteristics, various emission control technologies
are currently in use. The most frequently used control systems consist of high efficiency particulate
air (HEPA) filters. These control devices are used by hospitals, radiopharmaceutical suppliers,
laboratories, sealed-source manufacturers, fuel fabricators, source material licensees, and non-DOE
federal facilities. Charcoal filters are used to capture iodine, decay traps are used to hold radioactive
gases until the short-lived products decay, desiccant columns are used by lighting manufacturers to
remove tritium, and one facility has installed a catalytic recombiner to convert tritium gas to tritiated
water. Waste incinerators utilize afterburners, venturi scrubbers, and gas scrubbers to remove
pollutants. Fuel fabricators are known to use gas scrubbers as well.
Only two of the nine sub-categories are estimated to have a high enough dose and resulting risk level
to warrant further evaluation of supplementary controls. For the sub-category of hospitals, it is not
possible to accurately estimate supplementary control costs due to the large number of facilities and
the lack of knowledge of current controls and configurations. One radiopharmaceutical manufacturer
is estimated to have releases resulting in a dose greater than 1 mrem/yr, but is already using charcoal
filters. The efficiency of this control technology can be enhanced via three methods: cooling the
effluent, reducing the humidity, or decreasing the flow rate. It is crudely estimated that the
increased control cost for this facility might be $350,000, which could achieve a 99 and 75 percent
reduction in radioiodine and noble, gases respectively. The associated risk reduction would be from
8E-3 to 3E-3 d/yr. The second facility that is estimated to have releases resulting in doses greater
11-6
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than i mrem/yr is a sealed source manufacturer, which would require a catalytic recombiner to
achieve a 99 percent reduction in emissions. The estimated cost of this control is between $1.7 and
$7.0 million. This would result in a reduction of the risk by 4E-3 d/yr. However, because the doses
and risks associated with facilities in this category are not accurately known, the total number of
necessary controls cannot be ascertained,
11,4 Analysis of Benefits and Costs
Only two of the nine sub-categories are projected to have releases resulting in doses high enough to
warrant evaluation of supplementary controls. Moreover, these sub-categories contained only a few
sources which resulted in significant doses. However, this conclusion is based on incomplete data.
Table 11-2 presents the costs of the controls. The estimated benefit of supplementary controls for
the facility "D" radiopharmaceutical manufacturer is 1.5E-2 d/yr, assuming a capital cost of $350,000.
This translates into a net present value between $320,000 and $350,000 and an annualized cost
ranging from $3,200 to $3,500.
The total number of cancer deaths averted are also presented in Table 11-2. The total number of
fatal cancers averted due to supplementary controls for the Sealed Source facility "C" is estimated to
be 4E-1 over the course of a century, A wide range of costs was considered since an engineering
study of the specific requirements was not performed. The study that was completed gave "low-
cost" and "high-cost" estimates. The net present value ranges from $1,550,000 to $7,000,000 and the
annualized payment ranges from $20,000 to $70,000,
11-5 Industry Cost and Economic Impact
Industry costs and economic impact for this category can only be roughly approximated. The 6,000
facilities are not well characterized and emission data are incomplete.
Most of the sources in the several industries considered in this chapter are not likely to require
supplementary controls. For the two sources that may require supplementary controls, the costs to
one, Radiopharmaceutical "D", are under half a million dollars and will avert 1.5 cancer deaths per
century. The cost for the other, Sealed Source "C", is over 11,5 million and will avert 0.4 cancer
deaths per century.
11-7
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Table 11-2
Costs and Benefits for Controls on the Two Sources for which Controls are Required
Net
NPV of
Cancer
Social
Control
Deaths
Discount
Cost
Averted
Facility
Rate (%)
($/cent)
(d/cent)
Radio-
0
350,000
1.5E+0
pharmaceutical
:
"D"
1
346,000
1.5E+0
5
333,000
1.5E+0
10
318,000
1.5E+0
Sealed Source
0
1,700,000
4.0E-1
"C"
low-cost
1
1,683,000
4.0E-I
5
1,619,000
4.0E-1
10
1,545,000
4.0E-1
Sealed Source
0
7,000,000
4.0E-1
"C"
high-cost
1
6,931,000
4.0E-1
5
6,667,000
4.0E-1
10
6,364,000
4.0E-1
11-8
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Should either of these sources be controlled, any economic effects would be localized to the firm and
its immediate customers and suppliers.
As an alternative approach, a survey conducted by the Nuclear Regulatory Commission [NRC81 ] can
be used to estimate impacts associated with regulatory options under consideration. Approximately
3,000 facilities licensed to possess radionuclides were surveyed and about half responded. Doses
caused by each of these facilities were estimated using compliance procedures from [EPA89(A)].
Based on this analysis capital costs of $5 million and operating costs of $2 million/yr are estimated
for a three mrem/yr standard; capital costs of $25 million and annual operating costs of $12
million/yr for a one mrem/yr standard; and capital costs of $60 million and annual operating costs
of $35 million/yr for a 0.3 mrem/yr standard.
11-9
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REFERENCES
AHA86 American Hospital Association, Annual Survey of Hospitals, Chicago: Illinois, 1986.
BAT83 Batteile, Inc., An Economic Study of the Radionuclides Industry, Washington, D.C.,
for the U.S. Nuclear Regulatory Commission, NUREG/CR-2048, 1981.
CEN81 Centaur Associates, Inc., An Economic Study of the Radionuclides Industry,
Washington, D. C., for the U. S. Nuclear Regulatory Commission, NUREG/CR-2048,
198-1.
CRC87 Council of Radiation Control Program Directors (CRCPD), Inc., Compilation of State-
by-stale Low-level Radioactive Waste Information, for U. S. Department of Energy,
Frankfort: Kentucky, DOE/ID/12377, 1987.
EFA89 Risk Assessments, Vol. 2.
EPA89(A) Environmental Protection Agency, Background Information Document: Procedures
Approved for Demonstrating Compliance With 40CFR Part 61, Subpart I, January 1989.
Ma88 Manengo, J.J., et al., Environmental Monitoring and Disposal of Radioactive Wastes
from U. S. Naval Nuclear Powered Ships and Their Support Facilities 1987, Naval
Nuclear Propulsion Program, NT-88-1, Washington: D.C., 1988.
Mo88 Moriarty, M., personal communication, U. S. Nuclear Regulatory Commission,
Washington: D. C., 1988.
NCR89 Screening Techniques for Determining Compliance with Environmental Standards,
NCRP Commentary No. 3; Revision of January 1989.
NRC81 A Survey of Radioactive Releases from By-Product Material Facilities, J.R. Cook,
U.S.N.R.C., August 1981, [NUREG-0819].
NRC88 Nuclear Regulatory Commission, An Economic Study of the Radionuclides Industry,
Washington, D. C., 1988.
11-10
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CHAPTER 12
SURFACE URANIUM MINES
-------
12, SURFACE URANIUM MINES
12.1 Introduction and Summary
Surface uranium mines represent a depressed segment of a declining industry which serves a small
number of potential customers. They face declining demand for their output and price competition
from both underground mines and foreign producers. All but two of the hundreds of surface
uranium mines that operated from the 1950s to the early 1980s are currently inactive.
Controls on surface mines to reduce particulate radionuclide emissions and radon fluxes consist of
applying a layer of cover over the top of the closed mine area. The costs of this procedure are
measured in thousands or millions of dollars per mine.
12.2 Industry Profile
12.2.1 Introduction
Surface uranium mines are a subset of the U.S. uranium mining industry. Uranium is also produced
by underground mines which are discussed in Chapter 2. Uranium is used to produce electricity and
nuclear weapons. Chapters 1,3, and 4 also discuss aspects of the uranium industry. The number of
active surface uranium mines has sharply declined in recent years due to competition from
underground mines and foreign producers, and to declines in demand for uranium for both of its
uses.
12.2.2 Demand for Uranium
Uranium is an input to two industries: nuclear power production and nuclear weapon production
[EPA89], The demand for uranium from ore for these industries is currently in decline. The demand
for fuel for nuclear reactors must either be more or less constant or slightly on the increase. Since
the military has made no recent purchases of uranium, their demand has neither increased or
decreased.
Uranium is used as a fuel in nuclear power plants, after being milled and enriched. Although there
was rapid growth in this segment of the electric power industry from the late 1950s to the early
1980s, recent years have seen a total and abrupt stop in construction of new units. The factors
contributing to this decline included escalating costs, a general decline in the growth rate of the
12-1
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power generation industry, and increasing public concern for safety. Also, the financing and
management of some plants under construction led to severe financial problems. Some plants were
abandoned in mid-construction, while others were completed, but have not yet been commissioned.
The only demand for uranium by the U.S. nuclear power industry in the near future will be to fuel
existing power plants including those waiting to be commissioned. This source of demand will
decline as plants age and are decommissioned.
The second source of demand for uranium is the production of nuclear weapons which use uranium
as an input. Currently, weapons production reactors are closed due to problems with safety and with
past improper waste storage practices that have been discovered to pose a threat to nearby
populations. When these plants reopen, there will be a continuous, but not very large, demand for
uranium.
12.2.3 Supply of Uranium
Surface uranium mines currently operate at a small percentage of their overall capacity. (See Figure
12-1.) As recently as 1980 they produced 20,8 million pounds of UjOg from 50 mines, In 1986, they
produced about 2 million pounds of U-jOg from four mines. In 1988, there were two active surface
uranium mines [EPA89], All the mines studied in this chapter with respect to emission control are
currently inactive. Some are unreclaimed and others are reclaimed. The mines studied are located
in South Dakota, Wyoming, Colorado, Arizona, and Texas [EPA89], As illustrated by Table 12-1,
surface mining took place in other states as well, but not to the same extent.
A major problem facing surface uranium mines is competition from underground mines and foreign
producers. Table 12-2 demonstrates that underground mining is especially dominant when prices are
low, in the S30/lb. range. Table 12-3 illustrates the international competitive situation, especially
for reasonably assured reserves (RAR). The U.S. is not competitive with Australia at lower price
levels.
12-2
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Figure 12-1: Uranium Production
U.S Open-Pit Mines and Total Output
1E"6 LB U308
50
40
30
20
10
1950
1955
1960
1965
1970
1980
1975
1985
Year
Open-Pit 1 Total U308 Output
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Table 12-1:
Number of Significant Production Surface Uranium Mines by State.
Number Capable Number Capable
of Producing of Producing
State 1,000 to 100,000 T/yr over 100,000 T/yr
Arizona
37
1
California
1
0
Colorado
12.
4
Idaho
1
0
Montana
1
0
Nevada
1
0
New Mexico
3
5
North Dakota
10
0
Oregon
1
1
South Dakota
33
2
Texas
19
25
Utah
6
0
Washington
3
2
Wyoming
66
31
Source: [EPA89]
S2-4
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Table 12-2: Reasonably Assured Resources by Mining Method at the End of 1986 in the U.S.
(million pounds of U3Og).
Forward Cost Category
Mining Method
$30/lb
$50/lb
SI 00/lb
Underground mining
216
549
881
Open-pit Mining
45
326
503
In Situ Leaching
61
143
2^->
Others
1
18
24
Total
322
1036
1630
Source: [SC89]
12-5
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Table 12-3:
United States and Selected Foreign Uranium Resources as of End of 1986.
TOTAL RESERVES
Reasonably Assured Resources* Estimated Additional Resources*
Country
$30/lb
$50/1 b
S30/lb
$5G/lb
United States
322
1036
1350
2370
Canada
416
603
268
528
Australia
1201
1347
668
998
* Million Pounds U3°8
Source: [SC89J
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12.3 Current Emissions, Risk Levels, and Feasible Control Methods
For all regions, the total number of fatal cancers per year due to radon releases from inactive
uranium surface mines is estimated to be 3E-2 and the total fatal cancers per year due to particulate
emissions from inactive uranium surface mines is estimated to be 2E-2 [EPA89]. These risks are
spread across a large geographic area.
Specific studies were done on actual representative mines. They considered the emissions, the
lifetime risk to the most exposed individual, and the annual risk to the regional populations within
80 km, of the mine sites. The highest lifetime individual risk reported was 5E-5 [EPA89]. The
highest annual regional risk was 1E-3, associated with the Wright-MeCrady mine in Texas [EPA89].
The method proposed for reducing both radon and particulate emissions is to cover the sites with dirt.
It was assumed that 15 cm of cover would effectively reduce particulate emissions to background
levels [SC89], The amounts of cover required to reduce radon fluxes vary, depending on the initial
flux rates and the control standard. The alternative rule considered was to cover sources to limit
emissions to 40 pCi/m /sec. This assumes 0.2 meters of dirt is applied to the surface of the mines.
This application of dirt eliminates particulate emissions while reducing radon emissions. The capital
cost for this alternative is $15 million, or $0.8 million on an annualized basis [SC89],
12.4 Analysis of Benefits
The alternative approach discussed in the preceding paragraph would reduce maximum individual
risk of fatal cancer to 2E-5, while the incidence of fatal cancer to the 80 km population would fall
by 2E-2 to a level of 4E-3 [SC89],
12.5 Industry Cost and Economic Impact Analysis
The risks of cancer deaths induced by surface mines emissions are relatively low, while the costs of
control are in the millions of dollars. Were controls implemented, the economic effects would fail
on the owners of closed mines. There are no customers of these mines to whom the owners could pass
the costs of controls. The second round effects are harder to designate, since they depend on what
financial entity is affected and its ability to stay in business after paying the costs. Since the owners
of these mines are often large energy companies, it is unlikely that they will go out of business due
to a single expenditure of 10 million dollars. Work forces will not be affected, because operations
at these mines have already been curtailed.
12-7
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REFERENCES
EPA89 Risk Assessments, Vol. 2.
SC89 SC&A, Inc., "Radiological Monitoring at Inactive Surface Uranium Mines," prepared
for the U.S. Environmental Protection Agency, Office of Radiation Programs,
Washington, D.C., February 1989,
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