FF3 ff% A
IF IPli
B&i J^
TVA
U.S. Environmental
Protection Agency
Off ice of Research
and Development
Tennessee
Valley
Authority
Industrial Environmental Research
Laboratory
Research Triangle Park, NC 277 1 1
Office of Agricultural and
Chemical Development
Muscle Shoals, AL 35660
EPA-600/7-78
April 1978
TVAY-122
070

POTENTIAL ABATEMENT
PRODUCTION AND MARKETING
OF BYPRODUCT SULFURIC ACID
IN THE U.S.
Interagency
Energy-Environment
Research and Development
Program Report

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                  RESEARCH REPORTING SERIES


 Research reports of the Office of Research and Development, U.S. Environmental
 Protection Agency, have been grouped into nine series. These nine broad cate-
 gories were established to facilitate further development and application of en-
 vironmental technology Elimination of traditional grouping was  consciously
 planned to foster technology transfer and a maximum interface in related fields.
 The nine series are:

     1. Environmental Health  Effects Research

     2. Environmental Protection Technology

     3. Ecological Research

     4. Environmental Monitoring

     5. Socioeconomic Environmental Studies

     6. Scientific and Technical  Assessment Reports (STAR)

     7. Interagency Energy-Environment Research and Development

     8. "Special" Reports

     9. Miscellaneous Reports

 This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
 RESEARCH AND  DEVELOPMENT series. Reports in this series result from the
 effort funded under the 17-agency  Federal Energy/Environment Research and
 Development Program. These studies relate to EPA's mission to protect the public
 health and welfare from adverse effects of pollutants associated with energy sys-
 tems. The goal of the Program is to assure the rapid development  of domestic
 energy supplies in an environmentally-compatible manner by providing the nec-
 essary environmental data and control technology. Investigations include analy-
 ses of the transport of energy-related pollutants and their health and ecological
 effects; assessments  of, and development of,  control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
 mental issues.
                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for  publication. Approval does not signify that the contents necessarily reflect
the  views and policies of the Government, nor does mention of trade names or
commercial products  constitute endorsement or recommendation  for use.

This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.

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                                            EPA-600/7-78-070
                                                   April 1978
POTENTIAL ABATEMENT PRODUCTION
    AND MARKETING  OF BYPRODUCT
        SULFURIC ACID IN THE U.S.
                             by

                  J.I. Bucy, R.L. Torstrick, W.L. Anders,
                     J.L. Nevins, and P.A. Corrigan

                     Tennessee Valley Authority
               Office of Agricultural and Chemical Development
                  National Fertilizer Development Center
                     Muscle Shoals, Alabama 35660
              EPA Interagency Agreement D8-E721-BJ (TV-41967A)
                    Program Element No. EHE624A
                 EPA Project Officer: Charles J. Chatlynne

                Industrial Environmental Research Laboratory
                  Office of Energy, Minerals, and Industry
                   Research Triangle Park, N.C. 27711
                          Prepared for

               U.S. ENVIRONMENTAL PROTECTION AGENCY
                   Office of Research and Development
                       Washington, D.C. 20460

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                                 ABSTRACT


     Air quality regulations require control of sulfur oxides emissions from
power boilers.  Recovery of sulfur in useful form would avoid waste disposal
and conserve natural sulfur and natural gas used to mine sulfur.   Market-
ability of byproducts is an uncertainty.  This U.S. Environmental Protection
Agency-sponsored study was conducted by the Tennessee Valley Authority to
evaluate market potential for sulfur and sulfuric acid byproducts.  A cost
model was developed to estimate the least-cost compliance method from three
alternatives:  (1) selecting a clean fuel strategy, (2) selecting a limestone-
throwaway scrubbing technology, or (3) selecting a sulfuric acid or sulfur-
producing scrubbing technology.  For plants where production of byproducts
was the economic choice, a market simulation model was used to evaluate dis-
tribution of byproducts in competition with existing markets.  Significant
amounts of sulfuric acid could be produced from sulfur oxides in power plant
flue gas and sold in competitive markets.

     This report was submitted by the Tennessee Valley Authority, Office of
Agricultural and Chemical Development, in fulfillment of Energy Accomplish-
ment Plan 80 BBJ under terms of Interagency Agreement EPA-IAG D8-E721 with
the Environmental Protection Agency.  Work was completed as of June 1977.
                                     ii

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                                 CONTENTS
Abstract ..............................   ii
Figures  ..............................   vi
Tables ...............................
Abbreviations, Glossary, and General Conversion Factors   ......   X

Executive Summary  .........................   XV

Introduction  ............................      1
  Objectives of Phase III Study  ..................      2
  Phase I Model  ..........................      3
  The Expanded Model ........................      3
  Program and Scope  ........................      6

Elemental S and H2S04 Industry ...................      7
  Domestic Consumption of S  ....................      7
  Organization of Frasch S Production, Distribution, and Handling   .     10
  S Price History  .........................     12
  S Reserves  ............................     15
  Impact of Environmental Regulations on S Production   .......     15
    Frasch S Production  ......................     15
    Recovered S Production .....................     16
    Byproduct ^864 Production at Smelters .............     16
    H£S04 Production in S-Burning Acid Plants  ...........     16
  Domestic Consumption of ^SO^  ..................     17
End Use Analysis of S and ^SO^ in Fertilizer Production  ......     19
  Phosphate Fertilizer Market  ...................     19
    Phosphate Consumption Patterns .................     20
    Phosphate Production and Trade Patterns  ............     22
    Future Supply Patterns .....................     24
    Implications for the S Market  .................     26

Analysis of the Potential Demand for Abatement Byproduct  ^804  ...     29
  The Existing S-Burning Acid Plants in the U.S ...........     29
  The Impact of Abatement Acid ...................     32
  Production Costs for H2S04 ....................     32
  The Demand Curve for Abatement Acid  ...............     33
Analysis of the Potential Supply of Byproduct ^864 from Smelters   .     37
  End Uses for Byproduct Acid   ...................     37
  1978 Production Potential     ...................     37
                                     111

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SC>2 Emission Regulations and Applications	                  45
  SIP	I'.'.'.'.'.!!    45
  Federal NSPS	    45
  Trends in Establishing SIP	    46
  Emission Control Regulations  for Fossil-Fired Power  Generators  .  .    46
    Units of the Regulation	    46
    Application of the Regulations   	    47
  Emission Compliance Alternatives   	    48

Characteristics of the Power Utility Industry  	    49
  Fossil Fuels  	    49
    Historical Consumption and  Characteristics  	    50
    Projected 1978 Consumption  and Characteristics  	    51
  Power Plant Characteristics  	    53
    Plant Location	    53
    Plant Size	    53
  Boiler Characteristics   	    61
    Boiler Size	    61
    Boiler Capacity  Factors  	    63
    Boiler Heat Rates	    66

Scrubbing Cost Generator   	    69
  Procedure  for Utilizing FPC  Data to Estimate Compliance Status  .  .    69
    FPC Form 67 Data Projections	    69
    Compliance Test	    70
    Compliance Status  of Power  Plants 	    72
  Development of  the Scrubbing  Cost  Generator  	    72
    Background	    72
    Investment Scaling Procedure   	    74
    Revenue  Requirement  Scaling Procedure  	    76
    Output of the  Scrubbing  Cost  Generator	    80
    Supply Curve  for Abatement  Acid	    82

Abatement Byproduct  Acid Distribution-Transportation System 	    85
   Standard Point  Location  Code   	    85
  Distribution Cost  Generation   	    85

Market  Simulation Model  Theory   	    91
  Economic Theory 	    91
    Multidimensional Equilibrium  Model  	    93

Results and  Analysis	    95
  Plants Out of Compliance in  1978	    95
    ACFL	    95
  Results and Analysis of  Byproduct  Smelter  Acid Market  	    97
  Results and Analysis of  Power Plant Abatement Acid Market 	    97
    Scrubbing Cost Generator Prescreen  	    97
    Compliance Strategies  Selected by Power  Plants in  Model Runs  .  .    99
    Operating Profile  for  Power Plants Associated with Compliance
      Strategies Proposed for 1978	    106
                                    IV

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  Results and Analysis of Demand Points for Abatement Byproduct Acid .  108
    Best Candidates for Purchasing Abatement Byproduct Acid	108
  Supplementary Analysis 	  112
    Summary of S02 Emissions Control Strategies to Meet Compliance . .  112
    Clean Fuel Demand Curve	112
    Power Plant Supply Curve Based on Incremental Cost for Production
     of Abatement Acid	115
    Transportation Cost Analysis 	  115
    Impact of Barge Transportation 	  115
    Sensitivity of the S Price	120
  Other Uses of the Model	121
    Investment Costs 	  121
    Operating Costs	121
    Change in Regulations	123
    Evaluation of Other Abatement Products 	  123
    Use of Transportation Model	123
    Social Cost Consideration	124
  Conclusions	  126
  Recommendations	129

References	131

Appendices
  A   Basic System Flow Diagram	133
  B   A Mathematical Statement of Model	139
  C   The End-Use Input Requirements for S and H2S04	143
  D   Frasch S Production	145
  E   S Storage Terminal Operation 	  151
  F   Production, Storage, and Retrofit of Emission Controls to
       H2S04 Plants Using Elemental S	  155
  G   Demand Schedule for H2S04 Plants 	  169
  H   Byproduct 1^504 Production from Smelter Gases Including
       Estimates of Retrofit Tail Gas Cleanup and Limestone
       Neutralization	173
  I   ^SO^ Transportation Rates from Western Smelters to Eastern
       Terminals	181
  J   Projection of Steam Plant Data Base, 1978	183
  K   Variable Cost of Limestone and Sludge Disposal 	  189
  L   Specific Supply Points for Sale of Byproduct Smelter Acid  ...  193
  M   Scrubbing Versus Clean Fuel When ACFL is $0.70/MBtu
       Heat Input	199
  N   Feedstock Analysis for S-Burning H2S04 Plants in Model Runs. . .  203
  0   Size and Ownership of S-Burning Acid Plants	221
  P   Acid Plants Out of Compliance, Retrofit Cost, and Candidates
       for Purchase of Byproduct Acid	225
  Q   Power Plants and Acid Plants Affected by a Reduction of
       $20/Ton in S Price	227

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                                    FIGURES
Number                                                                    Page

 S-l     Flow diagram  for major system design requirements  	   xxi
 S-2     The supply  cost  curve for abatement acid	xxiii
 S-3     Abatement byproduct H2S04 demand curve (Eastern States)  . .  .   xxv
 S-4     Flow diagram  of  freight rate generation model	xxvi
 S-5     Geographic  distribution of assumed supply and demand for
          western and  Canadian acid in zero ACFL model run	xxxii
    1     Flow diagram  for major system design requirements  	     5
    2     Geographic  distribution of S terminals 	    13
    3     U.S. phosphate supply - demand outlook 	    27
    4     Geographic  distribution of S-burning acid plants (1978)  ...    30
    5     Amortized value of maintenance and capital outlays for new
           H2S04 plants (assuming 11% interest and 5% compound
           maintenance)  	    34
    6     Abatement byproduct l^SO^ demand curve (Eastern States)  ...    36
    7     Geographic  distribution of smelter byproduct acid plants in
           37 Eastern States and 11 Western States 	    39
    8     Abatement byproduct 1^504 demand curve (Western States)  ...    41
    9     Geographic  distribution of assumed supply and demand for
           western and Canadian acid in zero ACFL model run	    42
   10     Trends in the consumption of coal, oil, and gas from 1969-78 .    52
   11     Location of coal-fired steam-electric power plants (1978)  .  .    55
   12     Location of oil-fired steam-electric power plants (1978) ...    56
   13     Location of gas-fired steam-electric power plants (1978) ...    57
   14     Location of steam-electric power plants capable of utilizing
           a combination of fossil fuels 	    58
   15     General layout of a power plant designed with an FGD system  .    60
   16     Average boiler capacity factors as a function of boiler age  .    64
   17     Geographic  distribution of 187 power plants projected out of
           compliance  (1978) 	    73
   18     The supply cost curve for abatement acid	    OA
   19     Geographic  identification of standard point location codes
           (SPLC)	    86
   20     Flow diagram of freight rate generation model	        gy
   21     Railroad rate territories	'    gg
   22     Four basic  commodity column tariffs for H2S04 rail shipments  !    90
   23     Conceptual  demand curve for H2S04 and supply curve for
           abatement  production  	        ^2
   24     Geographic  distribution of the seven best power plant
           candidates for production and marketing of abatement HnSOA  .   1Q4
                                     VI

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                             FIGURES  (continued)
Number                                                                   Page

  25     Geographic distribution of S-burning acid plants  (1978)   .  .  .   109
  26     Clean fuel demand curve - all plants (1978)  .........   114
  27     Abatement acid supply curve for $0.35 ACFL model run  .....   116
  28     Abatement acid supply curve for $0.50 ACFL model run  .....   117
  29     Abatement acid supply curve for $0.70 ACFL model run  .....   118
  30     Conceptual demand curve for I^SO^ and supply curve for
          abatement production  ....................   125
                                     vii

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                                   TABLES
Number                                                                    Fag

 S-l     U.S. Consumption of S in All Forms by End Use	XXVi
 S-2     Projected 1978 Fossil Fuel Consumption Rates and
          Characteristics 	   XXVi
 S-3     Comparison of Projected 1978 Regional Fossil Fuel  Consumption
          with Historical 1973 Consumption	
 S-4     Power Plant Operating Characteristics Projected for  1978 .  .  . XXIX
 S-5     Summary of Model Results for Smelters and Power Plant  Sales
          to Acid Plant Demand Points	XXXiii
   1     U.S. Sulfur Consumption Patterns 1974-74 	      8
   2     Apparent Consumption of S in the U.S	      9
   3     U.S. Sulfur Demand Forecast  	     10
   4     Time-Price Relationship for S   	     14
   5     U.S. H2S04 Market Statistics 	     18
   6     U.S. Consumption of S in All Forms by End Use	     19
   7     U.S. Phosphate Consumption 	     21
   8     Average Phosphate Fertilizer Application Rates  for Major Crops
          in the U.S	     22
   9     U.S. Production of l^PO^ and Phosphate Fertilizers 	     23
   10     U.S. Phosphate Fertilizer Exports  	     25
   11     U.S. Sulfur-Burning H2S04 Plant Capacity (1978)  	     31
   12     Major Parameters in Model  	     35
   13     Incremental I^jSO^ Production for Eastern and Western
          Smelters 1976-1978   	     40
   14     Units for Expressing  State S02  Emission Regulations   	     47
   15     Consumption Pattern of Fossil Fuels in the  U.S.,  1969-73 ...     50
   16     Historical Fossil Fuel Characteristics for  the  Period
          1969-73	     51
   17     Projected 1978 Fossil Fuel Consumption Rates and
          Characteristics 	     53
   18     Comparison of Projected 1978 Regional Fossil Fuel Consumption
          with Historical 1973 Consumption  	     54
   19     Conventional Fossil-Fueled Steam-Electric Generating Plants,
          Total and Average Capacities,  Net Generation and Capacity
          Factors for the Total Power Industry, 1938-73  	     59
   20     Fifteen Largest Steam-Electric  Plants in the U.S.  in 1973  .  .     62
   21     Trends in Boiler Size, 1959-73  	     61
   22     Distribution of Boilers by Age  and Capacity Factor - All
          Boilers	     63
                                      viii

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                             TABLES  (continued)
Number
  23     Distribution of Boilers by Age and Capacity Factor -
          Boilers Out of Compliance	   65
  24     Distribution of Boilers by Size and Capacity Factor -
          All Boilers	   65
  25     Distribution of Boilers by Size and Capacity Factor -
          Boilers Out of Compliance	   66
  26     National Average Heat Rates  for Fossil-Fueled Steam-Electric
          Plants - Total Electric Power Industry, 1938-73  	   67
  27     Indirect Investment and Allowance Factors  	   75
  28     Projected 1978 Unit Costs for Raw Materials, Labor and
          Utilities	   78
  29     Estimated Maintenance Rates  for Alternative FGD Process  ....   77
  30     Annual Capital Charges for Power Industry  Financing 	   79
  31     Sample Output of Scrubbing Cost Generator  	   81
  32     Reclassification of Base Points	   88
  33     Power Plant Operating Characteristics Projected for 1978   ...   96
  34     Byproduct Smelter Acid Distribution in Model Runs	   98
  35     Eight Power Plants Scrubbing, Producing, and Marketing Acid in
          $0.35 ACFL Run	100
  36     Twenty-Four Power Plants Scrubbing, Producing, and Marketing
          Acid in $0.50 ACFL Run	101
  37     Two Power Plants Scrubbing,  Producing, and Marketing Acid  in
          $0.50 ACFL Run, But Also Using Clean Fuel	102
  38     Twenty-Nine Power Plants Scrubbing, Producing, and Marketing
          Acid in $0.70 ACFL Run	103
  39     Summary of Model Results for Smelters and  Power Plant Sales to
          Acid Plant Demand Points 	  105
  40     Operating Characteristics of Power Plant Candidates for Use
          of Scrubbing Technology  	  107
  41     Acid Plants Buying Abatement Acid in Model Runs	Ill
  42     1978 Strategies Selected for Reducing Emissions 	  113
  43     Cost Reduction by Barge Shipment	119
  44     Effect of $20 Reduction in S Price on Supply and Demand for
          Byproduct Acid	122
  45     Total Cost of Acid Production for Model Runs	126
                                     IX

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           ABBREVIATIONS,  GLOSSARY,  AND GENERAL CONVERSION FACTORS
ABBREVIATIONS
             ACFL
             BOM
             CDS
             CENTRE
             EDS
             EPA
             FGD
             FIPS
             FPC
             Ga
             ka
             Ma
             MES
             NEDS
             NRBT
             NSPS
             PEDCo
             SIP
             SPLC
             SRI
             TVA
Alternative clean fuel level
U.S. Bureau of Mines
Compliance Data System
Centre Mark Company
Energy Data System
U.S. Environmental Protection Agency
Flue gas desulfurization
Federal Information Processing Standard
Federal Power Commission
Billion (109)
Thousand (103)
Million (106)
Mutually exclusive set
National Emissions Data System
National Rate Basis Tariff
New Source Performance Standards
PEDCo-Environmental Specialists, Inc.
State Implementation Plan
Standard Point Location Code
Stanford Research Institute
Tennessee Valley Authority
            a.  Although British units are used  in  this report,
                the International System of Units  (SI) symbols
                are used in  transition to the metric system.
                                   x

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GLOSSARY
Alternative clean fuel level:  The value assigned to premium price for fuel
     that will meet the sulfur oxide emission standard.

Avoidable costs:  An estimation of the production costs over the long-term
     planning horizon that could be avoided by closing an existing acid
     plant assuming abatement acid would be available in amounts equal to
     the plant production capacity (330 days/yr).  Salvage value of the
     plant is assumed to be  equal to the salvage cost.

Capacity factor:  Throughout this study capacity factor is defined and
     calculated as the ratio of the annual quantity of heat consumed in the
     boiler in comparison to the quantity that would have been consumed if
     the boiler operated at rated capacity (full load) for the entire year
     (8760 hr).  For steam electric boilers, this definition is equal to
     capacity factors calculated in terms of either steam or electricity
     generation.

Centre Mark Company:  Source of geographic information on locations in the U.S.,
     including latitudes, longitudes, county data, and various other infor-
     mation related to over  100,000 locations.

Commodity column tariff:  Tariff publishing Docket 28300 commodity rates
     which are exceptions to the class rates.

Competitive equilibrium solution:  Represented by the long-run break-even
     market condition which  comes at a critical price where identical firms
     just cover their full competitive costs.  At a lower long-run price,
     firms would leave the industry until prices return to the critical
     equilibrium level; at higher long-run price, new firms would enter
     the industry replicating what existing firms are doing and thereby
     force market price back down to the long-run equilibrium price where
     all competitive costs are just covered.

     The long-run competitive equilibrium for sulfur and sulfuric acid
     market conditions in this study is simulated by minimizing the total
     cost of both the sulfuric acid and power plant industries ,  subject to
     the condition that the acid production demand is still met either from
     traditional sulfur sources or from a partial substitution of abatement
     sulfuric acid.

Compliance Data System:  A data base containing compliance information and
     status for all emission sources in the U.S. as they relate to clean
     air requirements.
                                   xi

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Consumer surplus:  On the assumption that the marginal utility of money
     remains constant, consumers surplus represents the gain to those
     consumers who would be willing to pay more than the market price for
     a particular good.

Docket 28300:  A general investigation by the Interstate Commerce Commission
     of the reasonableness of class rates in the U.S. (except in the mountain
     Pacific and transcontinental territories) that resulted in the class
     rates and tariffs in use today.

Energy Data System:  A data base containing fuel quality and consumption data,
     plant design and operating data, emission regulations, compliance infor-
     mation, future megawatt capacities, and air quality data.

Form 67:   Federal Power Commission form used to report annual steam-electric
     plant and water quality control data.

Frasch process:  A process developed by Herman Frasch for mining underground
     sulfur deposits by pumping large quantities of superheated water into
     the formation through pipes and pumping the melted sulfur to the surface
     where it is either shipped or stored as a liquid or solid.

Limestone slurry scrubbing:  A process for removing sulfur oxides from flue
     gases by scrubbing the gases in a tower with a limestone slurry.  The
     resulting slurry of calcium sulfites, sulfates, unreacted limestone,
     etc., is sent to a disposal pond where the solids settle out with no
     further treatment.

Magnesia slurry scrubbing:  A regenerative process for the removal of sulfur
     oxides from flue gases by scrubbing the gases in a tower with a magnesium
     oxide slurry.  The magnesium sulfite formed in the slurry is removed and
     thermally decomposed into magnesium oxide and a stream of concentrated
     sulfur dioxide gases.  The regenerated magnesium oxide is returned to the
     scrubbing tower and the concentrated sulfur dioxide stream is fed to a
     conventional contact sulfuric acid plant for the production of commercial
     (98%) sulfuric acid.  This process is called magnesia (MgO) slurry
     scrubbing in the text.

Market demand:  Amount of goods that buyers are ready to buy at each specified
     price in a given market at a given time (also called demand schedule).
     Demand for abatement acid in this study is simulated as though all con-
     sumption occurred at sulfuric acid plants producing at 330 days/yr.

Market supply:  Amount of goods that sellers are ready to sell at each speci-
     fied price in a given market at a given time (also called a supply
     schedule).

     Supply of I^SO^ in this study represents either production at each of
     the commercial acid plants or purchases from any power plant capable of
     producing abatement acid or sulfur.


                                     Xii

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Mutually exclusive set number:  A number used  in the  transportation subsystem
     to derive shipping costs between  two points.

National Emissions Data System:  A computer-based EPA emission  inventory system
     for storing and retrieving estimates of the criteria pollutants  from
     both point and area  sources.

National Rate Basis Tariff:  Tariff  containing alphabetical  lists of  all rail
     stations with rate basis applicable.

 Net social gain:   Monetary measure of the social benefit enjoyed from
      recycling abatement byproduct sulfuric acid into productive use.  It
      is the combination of consumer and producer surplus.

 Optimum useful life:   Identified in this study as the minimum point on the
      long-run average total cost curve for an acid plant.   At this  point
      the added capital cost savings enjoyed by increasing useful life one
      year equals the added maintenance saving from shortening useful life
      one year.

 PEDCo-Environmental Specialists,  Inc.:  The company that gathers information
      under contract to EPA on FGD by direct interviews with and surveys of
      utilities in the U.S.

 Producer surplus:   The difference between the market price at which a producer
      sells and the respective lower supply prices at which he would be willing
      to offer lesser amounts of a particular product.

 Product differentiation:  Any difference, real or imaginary, between two or more
      very similar goods or services that may result in preference for one
      over the other without regard to price.

 Scrubbing cost screen:  Designed in the study as an economic screen to select
      the most efficient power plant boilers in terms of unit cost of abatement
      production of 100% H2S04 equivalent.  Equivalent 100% H2S04 in any flue
      gas desulfurization process is the amount of 100% H2S04 which  could have
      been produced from the sulfur values in abatement byproducts,  such as,
      calcium sulfite, calcium sulfate throwaway sludge, or elemental sulfur.

 Standard Point Location Code:  A transportation-oriented 6-digit number
      prescribed by the National Motor Freight Association under the
      guidance of the SPLC policy committee.  It is used as a logistical
      linkage between all possible shipping origins and destinations for
      truck and/or rail.

 Wellman Lord/Allied Process:  A regenerative process for the removal of
      sulfur oxides from flue gases by scrubbing the gases in a tower with
      a solution of sodium sulfite.  The sodium bisulfite formed is  thermally
      decomposed (in a  separate vessel) to sodium sulfite and sulfur  dioxide
      gas.   The regenerated sodium sulfite is returned to the scrubbing
      tower and the sulfur dioxide gas is reduced with natural gas to form
      molten elemental sulfur.

                                     xlii

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GENERAL CONVERSION FACTORS
     EPA policy is to express all measurements in Agency documents in
metric units.  Values in this report are given in British units for the
convenience of engineers and other scientists accustomed to using the
British system.  The following conversion factors may be used to provide
metric equivalents.
          Conversion Factors for Metric  Equivalents  of  British Units
           British
Metric
ac
bbl
Btu
ft3
gal
Ib
lb/ft3

Ib/hr
ton
ton,
long
ton/hr
acre
barrels of oil
British thermal unit
cubic feet
gallons
pounds
pounds per cubic foot

pounds per hour
•a
tons (short)
n
tons (long)

tons per hour
0.405
158.97
252
0.02832
3.785
0.4536
16.02

0.126
0.90718
1.016

0.252
hectare
liters

cubic meters
liters
kilograms
kilograms per cubic
meter
grams per second
metric tons
metric tons

kilograms per second
ha
1

3
m
1
kg
kg/m

g/sec
t
t

kg/sec
 a.  All  tons are expressed in short tons in this report except sulfur which
    is expressed in long tons.
                                   xiv

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                POTENTIAL ABATEMENT PRODUCTION AND MARKETING

              OF BYPRODUCT SULFURIC ACID IN THE UNITED STATES


                             EXECUTIVE SUMMARY
INTRODUCTION

     Emission control regulations for the electric power industry require
utilities to either burn fuel with a low enough sulfur (S) content to meet
the standard or to remove a portion of the S before, during, or after com-
bustion.  Coal is the predominant fuel for power boilers and its use will
increase. Utilities generally prefer use of complying coal when it is the
economic choice compared to other alternatives for control.  However, complying
fuel  is  not always available near the areas of high electricity demand.
Technology for removal of S from coal prior to or during combustion is being
developed but will not make a substantial contribution to control in the next
decade.  The primary alternative to use of fuel that meets the emission
requirement is removing sulfur oxides (SOX) from the flue gas produced when
the coal is burned in the boiler.  Use of flue gas desulfurization (FGD)
technology currently accounts for only a minor portion of the control required,
but its use is growing as a result of limited alternatives to meet compliance
schedules.  Most applications are based on lime and limestone scrubbing.
These methods produce high volumes of waste solids for utilization or ultimate
disposal.  Technology for recovery of S in useful form is being developed
that will provide an alternative to production of waste solids.  Recovery of
S from flue gas would conserve natural S reserves and reduce the requirement
for energy used in mining S.  One of the major uncertainties associated with
this approach is the marketability of recovered S byproducts.

     In this study sponsored by the U.S. Environmental Protection Agency (EPA),
the Tennessee Valley Authority (TVA) has evaluated the potential markets for
S and sulfuric acid (^SO^) that could be economically produced by the power
industry as compared to use of clean fuel or limestone scrubbing.  A market
simulation model was developed to evaluate distribution of byproducts from
smelters as well as power plants in competition with the existing markets
based on an assumed S price of $60/long ton in 1978.  This value of S is
representative of projected costs of production.  Recovery of S from gas and
oil was not included in the study although delivered price of S reflects
this competition.
CONCLUSIONS

     A greater portion of future supply of S will have to come from other than
natural sources.  Beyond the year 2000, the demand will exceed the supply of
natural S (1).  Recovery of S byproducts from coal combustion could make a
substantial contribution to the additional supply.
                                   xv

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     The entire U.S. electric utility industry was characterized  from Federal
Power Commission  (FPC) data  (2) with respect to plant age, fuel type, capacity,
load factors, and SOX emission rates for the operating year 1978.   Out  of  a
total of 3382 boilers located at 800 power stations, 833 boilers  at 187 sta-
tions were projected to be out of compliance with current applicable emission
regulations.  The total SOX  emissions from these 187 plants are equivalent  to
17.5 Mtons (M = 1 million) of I^SC^; total H2SC>4 consumption in the  U.S. was
estimated to be 32.2 Mtons in 1978.   Therefore the total market is  about
twice the potential byproduct production.

     For the plants estimated to be out of compliance, limestone  scrubbing is
generally the least-cost  scrubbing method when credit for byproduct sales  is
not  included but when credit is applied, production of byproducts becomes
competitive; of  the alternatives considered in this study, production of
H2S04 was less expensive  than production of S.  An alternative to use of
scrubbing was provided by comparing the cost of scrubbing with selected
values  of premium cost of complying fuel.  The values were selected to
determine the effect on potential volume of abatement products.

     When the clean  fuel  premium was set at $0.70/MBtu,  the mix  of  least-
cost compliance methods was:

                  Purchase  complying fuel     71 plants
                  Use limestone scrubbing     87 plants
                  Produce byproduct acid      29 plants

 The amount  of acid  produced  and marketed totaled approximately 6  Mtons; an
 additional  5 Mtons  could  have been produced at a lower cost than  the alterna-
 tive compliance  method selected but could not be sold in competition with
 acid produced  from  elemental S priced at $60/ton.  The simulation model was
 designed to allow the nonferrous smelter industry to compete with the utility
 industry for byproduct markets.  The total byproduct acid supplied from both
 industries  was  7.11  Mtons or 22% of the total H2S04 market; however, some
 of the  plants  that  are good  candidates for recovery may be implementing other
 compliance  plans.   The control of sulfur dioxide (S02) emissions in the
 utility industry through  use of recovery technology could contribute 56% of
 the estimated total  reduction needed for the industry to be in compliance.
 Further use of recovery technology will depend primarily on substantial
 increases in elemental S  prices which are difficult to predict.   Reduction
 in the  cost of control technology would also increase the potential for
 increased production of byproducts, but the costs are not likely  to improve
 significantly.   Reduction in transportation costs is a more realistic
 possibility for  improving economics of marketing byproduct acid.   Higher
 levels  of clean  fuel premium would not affect the results since the acid
 supply  at the maximum value  studied exceeded the demand.

     The development of data bases and programs for use of the model to
predict byproduct market  potential resulted in capability to perform other
highly  relevant  calculations.

     The scrubber cost generator may be used to estimate the investment and
operating costs  of alternative scrubbing systems for all existing and planned

                                   xv i

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power plants.  In this study, costs were estimated  for  limestone,  magnesium
oxide (MgO) , and Wellman-Lord/Allied scrubbing  systems  for  all  plants  projected
to be out of compliance in  1978,  For use  in  the  study,  relativity of  costs
was the primary interest.   However, the input cost  data  could be refined  to
reflect special design considerations for  specific  plants to improve the
accuracy of estimates for planning and analyses.

     The procedure for evaluating compliance  status based on applicable stan-
dards and FPC projection of fuel characteristics  will be useful in estimating
the effect of changing emission standards  on  the  cost of compliance.   The study
reported here was based on  the State Implementation Plans (SIP) regulations
that were in effect as of June 1976.

     The transportation model that was developed  to distribute byproduct acid
from supply points to areas of use is a sophisticated program that  has poten-
tial for extensive use.  The model calculates actual, rate-base mileage between
any two points on the established railway  network.  For this study, tariffs
were incorporated for t^SO^ movements.  Available tariffs for any  other commodity
could be incorporated to calculate actual  transportation costs between any
two points .

     An important finding was that while long-run competitive equilibrium solu-
tions predict what may happen in competitive markets they do not identify net
social gain.  The savings to both industries  at the $0.70/MBtu clean fuel
premium run  resulting from  absorption of abatement byproduct acid  in the
existing market amounted to $122,877,000 or $16.20/ton of acid utilized.

METHODOLOGY

     The objective of the overall marketing model is to simulate long-run com-
petitive equilibrium market conditions for S  and  H2S04 in the U.S.  as  might
be impacted  by production of abatement acid or  S.   To simulate  these conditions,
the  cost to  both  the H2S04  and the power plant  industries is minimized subject
to the condition  that acid  demand is met either from traditional S  sources or
from substitution of abatement
     Analysis  of  the model  addresses  three  choices  for the steam plants that
 are  not meeting the current SIP  standards.  These include  (1) selecting a
 clean  fuel  strategy,  (2)  selecting  a  limestone-throwaway scrubbing technology,
 or  (3) selecting  an H2S04 (MgO)- or S-  (Wellman-Lord/Allied) producing scrub-
 bing technology.   Costs  for production  of S by  the  Wellman-Lord/Allied process
 were higher in all cases  studied than production of ^SO^.  Projected savings
 in distribution costs  for S compared  to H2S04 did not offset the incremental
 production  costs.  Costs  for use of the Wellman-Lord/Allied technology will
 be more clearly defined  during the  current  full-scale demonstration, partially
 funded by EPA, at the  Mitchell Station  of the Northern Indiana Public Service
 Company.  Revised information will  be included  in the model.  The incentive for
 production  of  S is high  because  it  is a safe, noncorrosive, convenient material
 to handle,  and can be  easily stockpiled for long periods of time at relatively
 low  cost.   Moreover,  fluctuations in  market demand  could be met with less impact
 to both the producer  and  consumer.  It  is likely that a mix of marketable by-
 products will  ultimately  provide the  least-cost compliance with S02 regulations
 in the utility industry.  Technology  for production of S should be fully devel-
 oped so that the  choice is  available  and so that accurate information Is avail-
 able for cost  comparisons with other  methods of control.
                                      xvii

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     The optimal solution predicts not only which acid producer would buy  and
which steam plant would sell t^SO^, but also which steam plant would sell  to
which acid plants.  Any variations to this optimal solution would increase
the total cost to both industries.

     A flow diagram of the major system design requirements is outlined  in
Figure S-l.  The major data bases feed the market simulation model  through
cost generation models as follows:

    1.  Emission control requirements for SOX were determined for each power
       plant boiler, stack, or plant projected to operate in 1978 using  the
       FPC data  (Form 67), June 1976 SIP, and New Source Performance
       Standards  (NSPS).

    2.  The scrubbing cost generator was developed to provide unit production
       costs for  byproduct I^SO^, elemental S, and limestone-throwaway sludge
       including  potential production quantities for each power plant boiler.
       It was designed as an economic screen to select the most efficient
       boiler combinations for meeting compliance on the basis of cents/MBtu
       heat input for each scrubbing system considered.  The results of  this
       screen provide the lowest cost method for compliance with given scrub-
       bing technology.  This information is fed to the market simulation
       model to identify both the relative efficiency as well as unique  loca-
       tion advantages for all power plant boilers producing abatement acid
       in competition with byproduct smelter acid producers in the  existing
       market.  The marketing model then estimates long-run competitive
       equilibrium solutions based on realistic outputs of abatement by-
       products by identifying major candidates for abatement byproduct
       production and consumption versus a limestone-throwaway strategy  and/
       or the alternative of using a clean fuel.

    3.  The acid production cost generator encompasses the elemental S
       producers, the S-burning H2S04 producers, and the byproduct  H2SC>4
       producers  associated with smelter operations.  These data bases were
       developed  from the TVA computerized data base on worldwide manu-
       facturers  of fertilizer and related products.  This information
       supplemented by references from other sources provided the necessary
       inputs to  the acid production cost generator to provide unit avoidable
       production costs for each t^SO^ plant projected to operate in 1978.

    4.  Transportation and distribution options were calculated by the trans-
       portation  cost generator for H2S04 and elemental S for all possible
       transfer combinations between the S producers, the electric  utilities,
       smelter plants, and H^SC^ plants considered in this study.

 Compliance Test

     The SC>2 emission and compliance model uses the projected annual fuel
 consumption and characteristics data to calculate the annual quantity of S
 that is emitted from each boiler and plant.  For each plant, allowable
 emissions are calculated based on NSPS for new boilers or the applicable SIP
 for existing boilers taking into account heating value and S content of  the

                                    xviii

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               BYPRODUCT  MARKETING MODEL
                       BASIC  SYSTEM
    SUPPLY
  DATA BASE
 TRANSPORTATION
   DATA  BASE
    DEMAND
   DATA  BASE
 POWER PLANTS,
  REGULATIONS,
 COST ESTIMATES
    TARIFFS
  RAIL MILEAGE
 BARGE MILEAGE
     ACID
    PLANTS
SCRUBBING
   COST
    GENERATOR
TRANSPORTATION
   COST
     GENERATOR
ACID  PRODUCTION
   COST
      GENERATOR
                     MARKET SIMULATION
                           LINEAR
                        PROGRAMMING
                           MODEL
/



\

n
EQUILIBRIUM
SOLUTION
RESULTS




v;
Figure S-l.  Flow diagram for major system design requirements.
                             xix

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fuel.  Excess emissions expressed  as  tons of S which must be removed are
estimated as the difference between the calculated actual and allowable values.
The compliance test selects the applicable level of SIP as (1) an entire
plant, (2) an individual boiler, or (3) an individual stack.   In all cases
where scrubbers could be used,  they are designed for an S02 removal efficiency
of 90%.  However, the actual level of removal efficiency will depend on
better definition of performance during sustained full-scale operation when
coal is the fuel.  The amount of gas  scrubbed is based on increments of
standard-size scrubbers.

Scrubber Cost Generator

     In all cases the S02 control strategy is selected on the basis of mini-
mum cost for compliance.  The data generated in the scrubbing cost model are
used to calculate the scrubbing cost  of a limestone-throwaway system versus
a salable byproduct for each of the 833 boilers or combinations of boilers
identified in this study that will be out of compliance with emission control
regulations in 1978 (based on 1976 regulations).  The cost is expressed as
cents/MBtu for direct comparison with the clean fuel alternative.  The
alternative clean fuel level (ACFL) represents the premium that can be paid
for complying fuel in lieu of using an FGD system.

     The model also calculates cost differential between scrubbing with a
limestone-throwaway system and scrubbing with MgO to produce H2S04.  This
accommodates identifying the incremental cost difference of the two systems
for all boilers or the combinations of boilers included in the model.   This
incremental cost becomes input to the marketing model which is designed to
determine potential for production and marketing of abatement I^SO^ at various
power plant locations.  The comparative FGD costs for each power plant con-
sidered in the study can be used to generate a supply curve for the produc-
tion of abatement I^SO^.  The supply  curve for abatement acid is presented
graphically in Figure S-2.  This curve is estimated by ranking power plant
boiler combinations from lowest to highest cost for producing abatement H2S04
as a function of accumulated supply quantities.

Acid Cost Generator

     H2S04 plants are widely scattered throughout the industrial sector of
the U.S.; acid has been traditionally produced by S-burning plants in captive
use near the point of consumption.  In this study it was assumed that the
H2S04 market can be simulated as though all consumption occurs at the H2S04
plants and that acid-producing firms  will close these plants and buy abate-
ment acid if it can be delivered at costs equal to or below their avoidable
cost of production.  This assumption  ignores some of the market entry
barriers but provides the basis for an economic assessment.  Avoidable cost
is an estimation of the production costs that could be avoided by closing an
existing acid plant assuming abatement byproduct acid would be available in
amounts equal to the plant production capacity (330 days/yr).  To develop
the required inputs to the model on the demand side, it was necessary to
identify the acid plants that burn elemental S for the production of H2S04
and calculate the avoidable costs  of  production at each plant.
                                   xx.

-------
PQ
S
     0.5  -
                                             8
10
12
14
                       CUMULATIVE S REMOVAL,  MTONS  OF
                Figure S-2.   The supply cost curve for abatement  acid.
                                        xxi

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     The avoidable costs (theoretical)  were calculated at each of the 90 acid
plant locations considered in the study.   Costs of manufacture based on data
generated indicated that most of the acid production costs range from $25.00-
$45.00 depending on plant location,  size, and age; the March 1976 price for
H2S04 (100% H2S04 f.o.b.) was $44.95/ton.  A summation of capacity of acid
plants versus avoidable cost of production is shown in Figure S-3.  The re-
sulting plot defines the demand curve for abatement acid.  The demand curve
is estimated by ranking all acid plants from highest to lowest cost and accumu-
lating demand quantities to show acid cost as a function of acid plant
capacity.  At a very high cost of alternative supply, only a few acid pro-
ducers could justify buying rather than producing H2S04-  As supply cost of
abatement acid declines, more acid producers would become potential customers.
At low supply costs all but the largest,  most modern acid plants located near
S supplies could be shut down.  The important implication for the present
study is that small quantities of abatement acid could be marketed at high
value but as the supply increases the value declines.

Transportation Cost Generator

     To assess representative competitive costs, a market system analysis
must generate accurate S freight rates from the Frasch S sources to the acid
plants and l^SO^ freight rates from all power plants and/or smelters to all
H2S04 plants.

     The linkage used in the study between the S-H2SC>4 and power plant data
bases and the rate generation system is a Standard Point Location Code (SPLC).
A flow diagram of the freight rate generation system used in this model is
shown in Figure S-4.  This shows that an SPLC for a power plant origin and
one for H2S04 plant destination are input to the National Rate Base Tariff
(NRBT).  This tariff determines for rail rate purposes the basing points for
the origin and destination.  Output are two sets of codes used to define
mileage and tariff rates between the byproduct shipping origin and destination
points.

     It is important to identify not only the mileage but also the tariff
number.  A slight error in mileage is not nearly as critical as knowing which
tariff applies.  Four tariffs were found in published H2S04 rates.  Rates for
eight other tariffs were generated by the TVA Navigation and Regional
Economics Branch (Division of Navigation Development and Regional Studies)
from these using sound traffic legal arguments similar to the negotiation
process that would ensue should large acid movements become a reality.


RESULTS OF ANALYSES

S and H?S04 Industry

     The U.S. Bureau of Mines (BOM)  (3) reports the production of S in all
forms in 1976 at 10.9 Mlong tons.   Elemental S was produced by 69 companies
at 182 plants in 32 states with 10 of the largest companies owning 57 plants
and accounting for 75% of the output.  The production was concentrated in
Texas and Louisiana accounting for 68% of the total output.  The Frasch S was
produced in these two states at 12 mines, 5 of the largest mines accounting

                                     xxii

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  100
   80
§
H
8
PM
   60
   40
  20
I
I
                                                I
              5        10          15         20        25         30



                    CUMULATIVE ANNUAL CAPACITY, MTONS OF 100% H2S04




         Figure  S-3,  Abatement byproduct H-SO, demand curve  (Eastern States).
                                                 35

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          SPLC,—I
  I—SPLC2
                  NRBT
I-C
                  JT
INDEX,    INDEX2
       *
       DOCKET
       28300
         I
    RATE BASE MILEAGE
                    RATE
                  SEARCH
                 MINIMUM
                   RATE
                                  MES,
                  M

          TARIFF
        GENERATOR
             I
        TARIFF NUMBER
Figure S-4.  Flow diagram of freight rate generation model.
                     xxiv

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for 82% of the total Frasch output  and  48%  of  the total production of  S  in
all forms.  Long-range prediction of  S  demand  in millions  of  tons  is shown
below.

                                         Forecast
                                 1976    1980    1985    1990

                  Fertilizer      6.4     7.5     9.3    11.0
                  Industrial      4.5     5.3     6.0     6.8

                       Total     10.9    12.8    15.3    17.8


     Frasch  S production  is a mining  operation.   Wells are  sunk  into  S-bearing
strata, S is melted by hot water injected  into the  strata,  and the molten  S
is pumped out.   The molten S is  pumped  from  the well  to either heated  tanks
for storage  as a liquid or to vats where it  cools and solidifies.  About 75%
of the  total mining costs of Frasch S is variable,  such as  the cost of
natural gas  to heat water, water treatment,  labor,  and operating supplies.
The cost of  hot  water to  melt the S is  by  far  the most important cost  and
will differ  drastically from mine to  mine  as water  requirements  and fuel cost
differ.  In  an analysis prepared for  this  study the cost of natural gas was
varied  from  $0.20-$3.00/kft-*  (k  = 1 thousand)  with  an intermediate value of
$1.00/kft3.  Water requirements  or water rate  varied  from 1600 gal/ton of  S
produced to  9000 gal/ton  of S.   The results  of this study indicated that the
lowest  capital investment and operating costs  are associated with mines
having  low water rates and that  cost  increases markedly with increasing
natural gas  costs.  For operation where the  major variables are  constant,
i.e., water  rate and natural gas cost,  the usual economies  of size prevail.

     Most of the S consumed in the U.S. is used to  produce  1*2^04.  Over two-
thirds  of the H2S04 is used in the manufacture of fertilizers.   A breakdown
of the  estimated consumption of  S in  all forms by end use is presented in
Table S-l.

Characteristics  of Power  Plants

     In 1973 utilities were requested by FPC to project fuel consumption and
characteristics  for 1978. The majority of utilities  provided FPC with these
projections. For the utilities  which did  not  project this  information, fuel
consumption  and  characteristics  reported for 1973 were used.  Based on the
updated projections, Table S-2 shows  the consumption  rates  and characteristics
of fossil fuels  projected to be  utilized during 1978.  For  plants which use
multiple fuels and did not project  their 1978  consumption,  a method for
projecting distribution of fuel  type  was developed.

     A  comparison of the  total projected 1978  coal, fuel oil, and gas  con-
sumption with the historical  1973 fuel  consumption  by region is  shown in
Table S-3.   The  projections indicate  a  general increase in  the consumption
of coal and  oil, but a slight decrease  in  the  consumption of gas. The
regional increases or decreases  are primarily  influenced by fuel availability
and price.   In reviewing  the data,  it must be  remembered that a  significant
                                   xxv

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           TABLE S-l.   U.S.  CONSUMPTION  OF S

                  IN  ALL FORMS  BY END USE

                  (klong tons S equiv)
H2S04
Fertilizer acid
H3P04
Normal superphosphates
(NH/,)2S04 and other
Total fertilizer acid
Industrial acid
Total H2S04
Non-acid
Total in all forms
1974
4,945
405
685
6,035
3,715
9,750
1,250
11,000
1975
5,410
290
670
6,370
3,080
9,450
1,200
10,650
1976
5,560
230
610
6,400
3,285
9,685
1,215
10,900
 TABLE  S-2.   PROJECTED  1978  FOSSIL FUEL CONSUMPTION

                 RATES AND CHARACTERISTICS
                                                   Plants out
                                      All plants   of  compliance
Coal
  Total consumption
    ktonsa                                475,600      226,800
    GBtub                              10,408,300    5,125,000
  Heating value, Btu/lb                     10,943      11,300
  S content, % by wt                         2.12        2.81
  Equivalent S02 content, Ib S02/MBtuc         3.87        4.97

Oil
  Total consumption
    kbbl                                 620,200      110,200
    GBtu                               3,827,400      686,900
  Heating value, Btu/gal                   146,924      148,454
  S content                                  0.99        1.42
  Equivalent S02 content, Ib S02/MBtu         1.08        1.54

Gas
  Total consumption
    Mft3                               2,556,000      108,200
    GBCu             3                 2,602,200      117,000
  Heating value, Btu/ft                      1,018       1,081

a.  k = one thousand.
b.  G = one billion.
c.  M = one million.
                          XXVI

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 TABLE S-3.  COMPARISON OF PROJECTED 1978 REGIONAL FOSSIL

     FUEL CONSUMPTION WITH HISTORICAL 1973 CONSUMPTION
  Geographic                   Coal,      Oil,       Gas,
    region3	ktons	kbbl	Mf t^

Historical 1973 consumption

New England                     1,080     82,930       6,070
Middle Atlantic                46,990    144,690      64,730
East North Central            135,960     23,340     105,590
West North Central             31,620      3,440     352,820
South Atlantic                 75,860    141,380     202,660
East South Central             63,060      6,510      73,750
West South Central              4,730     20,850   1,957,070
Mountain                       23,930      8,990     207,630
Pacific                         3,740     76,970     451,220

     U.S. total               386,970    509,100   3,421,540

Projected 1978 consumption

     U.S. total               475,570    620,250   2,556,020

a.  The states included in each geographic region are:
    New England - Connecticut, Maine, Massachusetts, New
    Hampshire, Rhode Island, Vermont; Middle Atlantic -
    New Jersey, New York, Pennsylvania; East North Central -
    Illinois, Indiana, Michigan, Ohio, Wisconsin; West
    North Central - Iowa, Kansas, Minnesota, Missouri,
    Nebraska, North Dakota, South Dakota; South Atlantic -
    Delaware, District of Columbia, Florida, Georgia,
    Maryland, North Carolina, South Carolina, Virginia,
    West Virginia; East South Central - Alabama, Kentucky,
    Mississippi, Tennessee; West South Central - Arkansas, -
    Louisiana, Oklahoma, Texas; Mountain - Arizona,
    Colorado, Idaho, Montana, Nevada, New Mexico, Utah,
    Wyoming; Pacific - California, Oregon, Washington.
b.  Regional consumption data not available.
                           xxvii

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amount of new generating capacity between 1973 and 1978 is from nuclear units.
The data shown include the effect of projected decreases in fossil fuel utili-
zation as a result of new nuclear units coming online as well as changes in
fossil fuel consumption resulting from decreases in fuel availability of
increases in cost.

     The operating characteristics of all 800 U.S. power plants projected to
be in operation in 1978 are outlined in Table S-4.  Also included in this
table are the characteristics of the plants projected to operate out of com-
pliance in 1978.  As the data in the table indicate, 187 power plants out of
a total of 800 were calculated to be out of compliance.  It should be noted
that many of the plants estimated to be out of compliance are likely imple-
menting compliance plans that are different from those selected for this
study.  Even though plants out of compliance make up only 32% of the total
population with respect to capacity, they burn about 50% of the total coal;
only 20% of the total oil, and only 5% of the total gas.  Plants out of
compliance have a 30% higher S content in the coal burned and a 43% higher S
content in the oil burned than the overall nationwide average.  The average
boiler size for plants out of compliance was about 30% greater than the
average for all plants.  The age range of boilers, the range of boiler sizes,
and boiler capacity factor for plants out of compliance were not significantly
different from the industrywide values.

Byproduct Acid from Smelters

     The 14 smelters located in the 11 Western States were analyzed separately
from the 14 smelters in the 37 Eastern States of the U.S.  The model assumes
that existing S-burning acid plants and byproduct acid plants associated with
smelter operations were operating at an equilibrium position in the 1975
market year.  The model then addresses the incremental acid that is projected
to be produced at both existing and new smelter locations in 1978.  The 1978
incremental production estimated for the Western States amounted to 849,000
tons of acid.  The analysis for smelters located in the Eastern States
amounted to 811,000 tons of acid.

     Part of the acid produced by western smelters was distributed in the
East.  This surplus western acid was marketed in the simulation model through
transshipment terminals supplied by unit trains.  The terminal locations
included Chicago, Illinois; St. Louis, Missouri; Memphis, Tennessee; Baton
Rouge, Louisiana; and Houston, Texas.  Two additional transshipment terminals
were added in the model at Buffalo, New York, and Detroit, Michigan, in order
to analyze the marketing of 200,000 tons of byproduct acid from smelters in
Canada.  This concept is presented graphically in Figure S-5.

Byproduct Acid from Power Plants

     The clean fuel alternative is defined as the incremental additional
price for fuel that will meet the applicable S02 emission regulation.  The
ACFL selected for the model runs ($0.00, $0.35, $0.50, and $0.70/MBtu) were
chosen to show the effect on potential volume of abatement acid.  For some
power plants with multiple boiler installations a mix of alternative methods
                                 XXV111

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TABLE S-4.  POWER PLANT OPERATING CHARACTERISTICS PROJECTED FOR 1978





No. of power plants
No. of boilers
Total capacity, MW
Total fuel
Coal, ktons
Coal, GBtu 1
Oil, kbbl
Oil, GBtu
Gas, Mft3
Gas, GBtu
Average S content of coal, %
Average S content of oil, %
Emissions, equivalent tons H2S04
Total emitted
Required abatement
Average capacity factor, %
Average boiler generating capacity, MW
Age of boilers, %
0-5
6-10
11-15
16-30
>30
Size of boilers, %
<200
200-500
501-1000
>1000
Capacity factor of boilers, %
<20
, 20-40
41-60
>60

1978
all
U.S. plants
800
3,382
411,000

475,600
10,408,300
620,300
3,827,400
2,556,000
2,602,200
2.12
0.99

29,552,100
9,912,600
31.87
122

5
8
8
42
37

82
11.7
6
0.3

40
20
23
17
1978
plants
out of
compliance
187
833
132,600

226,800
5,125,100
110,200
686,900
108,200
v 167,000
2.81
1.42

17,562,300
9,912,600
35.12
159

10
10
6
42
32

75
15
9
1

35
17
29
19
                             xxix

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X
X
X
                                                          • DEMAND POINT
                                                          A TRANSSHIPMENT TERMINAL
                                                          O ORIGIN OF BYPRODUCT
                                                            SMELTER  ACID
                Figure  S-5.  Geographic distribution of  assumed supply and demand  for western and
                                      Canadian acid in  zero ACFL model run.

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produce the least-cost compliance  strategy.   A summary  of  the  distribution
of compliance strategies selected  by  the model for  each ACFL model  run  is
listed as follows:

                                                  ACFL, cents/MBtu
        	Compliance  strategy	0      35     50     70

        Plants using  clean  fuel  only            187    168    113     71
        Plants using  only limestone  scrubbing    0      7     41     77
        Plants using  limestone scrubbers  and
         clean fuel                               0      4      7     10
        Plants using  MgO scrubbing only          0      8     24     29
        Plants using  MgO scrubbing and  clean
         fuel                                    	0    	0    	2   	0

             Total power plants                  187    187    187   187

      The potential production and marketing of abatement acid for power
 plants  that  produced  acid  in each of the  model runs  are outlined as follows:

                                        ACFL,  cents/MBtu	
                                    0	35	50	7JD

                No.  of plants       0       8      26      29
                Thousands of tons
                 marketed           0   2,554   5,108   5,595


      Power plants that were the best candidates for production of  byproduct
 acid were generally larger, newer plants with high load factors.   The  dis-
 tinctive characteristics were (1) most boilers <10 yr old, (2) average size
 about 600 MW (<15% smaller than 200 MW), and (3) the average  capacity  factor
 about 60%.  The average load factor for potential acid-producing plants was
 more than three times as high as the average for all plants considered.


      A summary of the compliance strategies developed from the model runs
 for controlling excess emissions projected for 1978 is outlined in the
 following tabulation:

                 Strategies Selected for Reducing Emissions

              (Reductions expressed as equiv ktons of
ACFL,
cents/MBtu
0
35
50
70
00
By using
clean fuel
9,912
7,993
3,123
700

Total by
scrubbing
0
2,885
9,503
12,583
13,598
By MgO
scrubbing
0
2,554
5,108
5,595
-
By limestone
scrubbing
0
330
4,395
6,988
-
Total
reduction
9,912
10,878
12,627
13,284
13,598
                                    xxxi

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Equilibrium Solution

     A summary of model results for smelter and power plant sales  to acid
plant demand points for all model runs is outlined in Table S-5.   These
results show the potential quantity of power plant acid in relation to the
total market.  At the $0.70/MBtu ACFL, the potential for production of acid
(abatement capacity) at a cost below the alternative clean fuel premium  fuel
cost exceeded the market demand (sales) for the acid by 5 Mtons.   The plants
that would not be able to market the acid used limestone scrubbing even  though
production of acid would have been less costly if markets were available.
At the $0.35/MBtu level, essentially all of the acid that could be produced
economically compared to purchase of complying fuel was sold.  The small
differential in sales between the $0.50 and $0.70/MBtu level of ACFL indicates
that the market for byproduct acid from power plants was nearly saturated at
5 Mtons, or approximately 15% of the total market.  Further substitution of
byproduct acid in the existing market would depend on substantial  increase in
the price of S; $60 was assumed for the study.

Distribution of Acid Markets

     Distribution of acid for the 90 acid plants considered in each model run
is outlined as follows:


                                               ACFL, cents/MBtu
                                                0   35   50   70
              Producing from S                 58   42   30   28
              Buying from smelters only        21   11    1    5
              Buying from steam plants only     0   22   41   41
              Producing from S and buying
               from smelters                   11    6    2    1
              Producing from S and buying
               from steam plants                0232
              Producing from S and buying
               from smelters and steam
               plants                           0001
              Buying from smelters and
               steam plants                     0    7   13   12

                   Total acid plants           90   90   90   90


     Four significant factors that affect the purchase of abatement acid by
current producers of H2S04 in this study are listed as follows:

   1.   Size
   2.   Age
   3.   Compliance with clean air standards
   4.   Location

     Abatement  acid  produced in the model run from the utility industry  at
the $0.70/MBtu  clean fuel  premium was distributed to 56 different  demand
points  in 23  states.   The  current  supply that was replaced by byproduct  acid

                                   xxxii

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        TABLE S-5.   SUMMARY OF MODEL RESULTS FOR SMELTERS AND

            POWER PLANT SALES TO ACID PLANT DEMAND POINTS

                           (ktons of
                                          ACFL, cents /MBtu

Eastern smelters
Capacity
Sales
Demand points
Western smelters
Capacity
Sales
Demand points
Canadian acid
Capacity
Sales
Demand points
Total smelter acid capacity
Sales
Demand
Mixed demand points
Steam plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur to 1^504 plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur only
0

818
818
15

738
738
15

200
200
4
1,756
1,756
32a
11

-
-
-
-

32,237
30,481
69a
11
58
35

818
818
13

738
738
8

200
200
4
1,756
1,756
24a
13

2,635
2,554
31a
9

32,237
27,926
50a
8
42
50

818
818
12

738
594
3

200
200
2
1,756
1,612
16a
15

8,497
5,108
57a
16

32,237
25,516
35a
5
30
70

818
818
14

738
498
3

200
200
3
1,756
1,516
19a
13

10,758
5,595
56a
14

32,237
25,126
31a
4
28

a.  Steam plants and eastern and western smelters can supply a common
    demand point.
                                XXX111

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was generally from smaller,  older plants remotely located from the elemental
S production points on the Gulf Coast.   The larger,  more efficient plants
generally can produce acid at costs lower than the delivered cost of abate-
ment byproducts;  however, there are exceptions.   Savings in transportation
cost because of location advantage can offset production cost differential.

Sensitivity Analyses

     One of the key inputs in the analysis of the potential market for abate-
ment byproduct acid is the price of elemental S.   All the results of this
study are based on S price of $60/long ton f.o.b. Port Sulphur.   A $20.00
decrease in the unit price of S lowers the avoidable cost of production for
H2S04 at each respective acid plant by $6.11/ton  of  acid produced.  This
price structure would reduce the quantity of both byproduct smelter acid as
well as the abatement acid from power plants that can be marketed in the
model.

     The model assumed distribution of byproduct  acid by rail shipment.
Since several of the potential producers are located on navigable waterways,
barge transportation could be used.  As an example of possible savings on
shipment costs, estimates were made for barge shipments of selected produc-
tion totaling 700,000 tons.   The cost differential between rail  and barge
transportation totaled $725,000 or about $l/ton of acid.  This potential
savings is 11% of the average transport cost.  Because barge rates are
normally negotiated, rates were not available for inclusion in the trans-
portation model.  An in-depth analysis will be required before realistic
conclusions can be made.
RECOMMENDATION

     Information on current compliance programs for existing power plants
and for additional planned capacity was not available during the period of
this study.  The results of the work show that the potential for use of
recovery technology is good and the initial follow-on work should focus on
plants where compliance alternatives are still flexible.   A survey of com-
pliance plans should be carried out and the option of producing byproduct
acid should be evaluated by incorporating specific information on those
plants into the program data base.   This evaluation would be particularly
helpful in the planning process for future coal-fired power plants or for
those that may be required to convert from gas or oil to  coal.
                                   XXXIV

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                               INTRODUCTION

     Air quality regulations require many fossil  fuel-fired power plants to
meet emission limitations on sulfur oxides  (SOX)  formed when sulfur  (S) in
the fuel is burned.  The current alternatives are use of low-S fuel  that
meets the emission regulation or use of flue gas  desulfurization (FGD)
technology to remove SOX after the fuel is burned.  Other technology to
convert high-S fuels to clean gas or liquids is being developed but  is not
yet ready for use.

     The electric utility industry would generally prefer use of complying
fuel if it is the economic choice.  However, coal supplies that meet the
emission regulations are in short supply in the eastern part of the  country
where a major portion of the power is produced.   Much of the coal in the
Western States is sufficiently low in S to meet the present New Source
Performance Standards (NSPS), but limitations on  mining and transportation
facilities reduce the potential of this fuel supply for use in the industrial
East.  Moreover, proposed changes to the regulations could prevent use of
coal from regions outside the area of use.

     FGD technology is still in the development stage, but several power
companies have installed FGD systems to comply with the regulations while
burning high-S fuel.  Most of the processes are based on scrubbing with lime
or limestone and produce sludge that must be discarded in storage ponds.
This practice commits large land areas to nonproductive use.  Technology for
recovery of S in useful form is also under development.  These processes will
provide an alternative to processes producing waste solids and will  allow
conservation of natural S reserves.  An effective method for evaluating
market potential of recovered products and for identifying the most  likely
mix of compliance strategies is needed to provide guidance to the utility
industry in selecting from alternative systems.

     In order to provide perspective on the potential use of recovery
technology, the U.S. Environmental Protection Agency (EPA) contracted with
the Tennessee Valley Authority (TVA) to carry out a series of studies to
develop a method for comparison of FGD systems to evaluate market potential
for abatement products, and to characterize and identify power plants that
are the most likely candidates for producing useful products.

     Phase I was completed in December 1973 using the TVA power system as a
single utility example of theoretical production  and distribution of abate-
ment sulfuric acid (H2S04).  A computerized production-transportation model

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was developed and although the study was hypothetical, it provided consider-
able insight as to the impact that abatement H2S04 could have on the existing
market.  Results of the study were published (4).

     Phase II involved a preliminary market study of the potential use of
calcium sulfate (CaS04) sludge by the wallboard fabrication industry to derive
cost data for comparison of throwaway alternatives.  This study was conducted
early in 1974  (5).

     Phase III, the subject of this report, is an expansion of the Phase I
study.  A TVA interim report, S-469, was prepared as part of this phase to
include analysis of abatement production of elemental S as well as H2S04 (6).
However, the cost of abating elemental S with current technology was such
that it could not normally compete in the market with abatement H2S04-
Possibly future technology will provide a more competitive scrubbing system.
The final report of Phase III addresses the potential production and market-
ing of abatement H2SC>4 by the utility industry in the 48 contiguous states
of the U.S. in competition with byproduct acid produced in the smelter
industry.

     As presently planned future work will focus on an expanded study of
CaS04 sludge utilization for wallboard, potential use of abatement
S byproducts in the fertilizer industry [S, H2S04, (Nlfy^SO^J, and will
evaluate alternative strategies for optimum technology mix considering
product markets [S, H2S04, (Ntfy^SC^, phosphate fertilizers, wallboard, etc.],
process cost differentials, and clean fuel alternatives.
OBJECTIVES OF PHASE III STUDY

     The objectives for this third phase of study are outlined as follows:
Using the analysis techniques, data research, and basic computer model
derived for Phase I, the expanded investigation was conducted to (1)
determine the quantities of byproduct t^SC^ or elemental S which could be
produced by air pollution abatement installations at power plants,  (2) define
the most economical market distribution-transportation system including
storage costs, (3) determine competitive costs of H2S04 producers using
elemental S as raw material; costs of acid plant pollution control  included,
(4) determine competitive costs of elemental S production, (5) predict as a
function of the above the possible net sales revenue for marketing
strategies covering the existing acid market, the existing elemental S
market, and the growth markets for these commodities, and (6) recommend the
most practical byproduct for specific power plant installations based on
results of the above tasks.

     The purpose of these objectives is to provide general and practical
information concerning the potential for abatement byproducts in the current
production, distribution, and use of S and H2S04 in the U.S.   Also, the
computer model of Phase I was enlarged to cover the expanded power  plant
data base and programed to reflect pollution restrictions dictated  by

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State Implementation Plans  (SIP)  and  NSPS.   The model was designed for
multiproduct capability and  relatively easy modification as the data bases
change.  A further criterion is  system transferability to other potential
users through the use  of  standard computer  languages, commercial time
sharing, and remote batch national computer networks, although it should be
noted that the system  that has been built is a highly complex system of
programs and data bases requiring advanced  and very specialized skills.
PHASE I MODEL

     The Phase  I model was  a traditional transportation model solved with a
linear programing  algorithm.   Transportation costs were calculated by a rate
specialist  for  each  possible transport combination.  Cost of the abatement
acid at the steam  plant  was assumed to be zero.   The solution to the model
minimized the cost of marketing abatement acid as well as the average total
production  cost for  the  H2S04 industry.   The model assumed that  the acid
plant would close  down and  buy abatement acid if the acid could  be delivered
equal to or below  the avoidable cost of production.
 THE EXPANDED MODEL

      The  1972 Federal Power Commission (FPC)  Form 67 data file contained
 information that could be correlated with variables used in the detailed
 cost estimates of the five leading FGD processes prepared by TVA in
 January 1975 (EPA 600/2-75-006)  (7).  The availability of these data
 provided  the basis for development of a cost  screen designed to identify  the
 most promising power plant boiler candidates  for abatement byproduct
 production.   The 1973 FPC Form 67 data available in 1976, contained 5- and
 10-yr projections of proposed new power plant installations.  SIP and NSPS
 standards for air pollution control effective in June 1976 identified
 allowable emissions for each power plant in the U.S.  A rail transportation
 rate generation model developed by TVA was modified to calculate accurate
 transportation rates for elemental S and H2S04 for all origins and destina-
 tions in the rail rate territories located east of the transcontinental
 territory.

      A systems model was designed to combine  data inputs needed to assess the
 nationwide market potential of abatement byproducts.  Three major data bases—
 (1) H2S04 producers, (2) transportation-distribution options, and (3) power
 plant data (FPC, SIP, and TVA cost estimates)—supply information to feed a
 market simulation model through three cost generation models.  All data were
 projected to 1978 values.  The three cost generation models include   (1)
 the transportation cost generator, (2) the scrubbing cost generator, and
 (3) the H2S04 production cost generator.  The transportation cost generator
 provides  transportation, distribution, and storage options to calculate least-
 cost shipping modes considering rail, barge,or truck combinations for S-H2S04
 from Port Sulphur, Louisiana, to all acid plants and between all combinations

-------
of power plants, smelters,  and acid plants considered in the study.  The  second
model, the scrubbing cost generator, was designed to provide a method  for pro-
jecting comparative costs for installing FGD systems on power plants projected
to be out of compliance in 1978.  It is used as an economic screen  to  select
the most efficient boilers in terms of unit cost of abatement production.   The
third model is used to calculate the avoidable cost of production for  each  S-
burning H2SC>4 plant included in the study.  Avoidable cost is an estimation of
the production cost that could be avoided by closing an existing acid  plant
with  the assumption that abatement byproduct acid would be available in
amounts equal to the plant production capacity (330 days/yr).

      Analysis of the model addresses three choices for the steam plants that
are projected to operate out of compliance in 1978.  This includes  (1) select-
ing a clean fuel strategy, (2) selecting a limestone-throwaway scrubbing
technology, or  (3) selecting an H2S04-producing scrubbing technology.

      Concepts include the consideration of nonferrous smelters byproduct  acid
in the  final solution; central regeneration facilities for one or more boiler
combinations of scrubbing at power plant sites for recovery processes; the
estimated cost of limestone delivered to each potential power plant scrubbing
site  (this required development of data for all limestone sources in the  U.S.);
actual  emission regulation codes and values; limiting the potential acid  market
to users of elemental S; distinguishing between scrubbing cost estimates  for
new plants versus retrofitting old plants; site specific location adjustments;
the addition of western power plants, acid plants, and smelters; and addition
of geographic data required by the transportation system in the market simula-
tion  model.  The new data sources considered in addition to the previous  phase
include EPA Energy Data Systems (EDS), Compliance Data Systems (CDS),  the
monthly report  from PEDCo-Environmental Specialists, Inc., Stanford Research
Institute  (SRI), U.S. Bureau of Mines (BOM), National Emission Data Systems
 (NEDS), Centre Mark Company (CENTRE) geographic and transportation data,  and
several FPC publications and reports.

      The expanded model allows for significantly better estimates of long-run
competitive equilibrium solutions since they are based upon more realistic
economic premises and outputs of abatement byproducts than the Phase I work.

      A  basic flow diagram of major system design requirements is shown in
Figure  1.  A more detailed flow diagram of the model is presented in Appendix
A.  It  is assumed that the I^SO^ market can be simulated as though  all con-
sumption occurred at H2S04 plants, and that acid-producing firms would close
these plants and buy abatement acid if acid prices were below their projected
long-run H2S04 production cost.  Long-run competitive equilibrium market
conditions can be simulated by minimizing the cost to both the H2SC»4 and  power
industries.  Power plants are assumed free to produce or not to produce S or
H2S04 and to sell to any H2S04 plant in competition with other power plants.
Likewise, H2S04 plants are assumed free to continue buying S from traditional
sources or from power plants, and free to buy acid in lieu of production
subject to competition in their respective industries.  Product differentia-
tion  is not assumed significant.  Problems of stable, guaranteed abatement
supplies are ignored, but probably are solvable.  Rail transportation

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               BYPRODUCT  MARKETING MODEL
                       BASIC SYSTEM
    SUPPLY
  DATA BASE
 POWER PLANTS,
  REGULATIONS,
 COST ESTIMATES
SCRUBBING
  COST
    GENERATOR
 TRANSPORTATION
   DATA  BASE
    TARIFFS
  RAIL MILEAGE
 BARGE MILEAGE
TRANSPORTATION
   COST
     GENERATOR
    DEMAND
   DATA  BASE
     ACID
    PLANTS
ACID  PRODUCTION
   COST
      GENERATOR
                     MARKET  SIMULATION
                           LINEAR
                        PROGRAMMING
                           MODEL
/


\
EQUILIBRIUM
SOLUTION
RESULTS

A


vy
  Figure 1.  Flow diagram for major system design requirements.

                              5

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cost is assumed adequate for simulating competitive market conditions.   Some
preliminary work was done using barge-truck strategies to determine possible
impact on the equilibrium solution, but in-depth analysis will be required
before any realistic conclusions can be made.
PROGRAM AND SCOPE

     The computer model design is directed towards identifying major  candi-
dates for abatement byproduct production and consumption.  From a data bank
maintained at the TVA National Fertilizer Development Center, design  and oper-
ating inputs were cataloged in the computer for existing U.S. contact and
chamber t^SO^ plants. Capital and operating costs for mining S by the Frasch
process, transporting and storage of S, manufacturing acid by the contact
process, storage of acid, and controlling acid plant tail gas emission were
calculated to determine competitive costs of S and acid production.

     Development of an accurate transportation data base for computing
shipping costs for S and acid contributed in a major way to the value of the
study since shipping cost is a significant and essential element in the price.

     Power plant design and operating data provided in the FPC Form 67 data
base were used to characterize key design and operation parameters of all
power plants in the U.S.  For this effort, only boilers burning coal  or oil
are of  interest.  Parameters such as fuel type, S in fuel, heat rate, fuel
consumed, on-stream time, age of boiler, etc., are vital.  Possible output
of byproducts was calculated for each power plant, given the level of S02
control designated by June 1976 SIP standards.  For boilers where scrubbing
was needed, 90% removal efficiency was assumed.  However, scrubbing was used
only on the number of boilers necessary to bring the plant into compliance.
The most likely candidates for use of recovery compared to low-S fuel or
limestone scrubbing were identified.  A mathematical statement of the model
is presented in Appendix B.

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                    ELEMENTAL S AND H2S04  INDUSTRY


     S is one of the most important industrial raw materials.   It is used
principally in the form of I^SO^ at some stage in the production of virtually
everything we eat, wear, or use.  It is referred to as  the workhorse of the
chemical industry.  Its consumption is an  indicator of  the state of the
economy of an individual nation or of the  world.  Unfortunately, however, in
most uses S ends up as a residual of the production process.  Recycling this
residual back into productive use is a major problem facing  the chemical
industry.

DOMESTIC CONSUMPTION OF S

     S enters into the production of many  products in varying amounts, for
example,from 18.090 tons of S or S equivalent per ton of uranium 235 (U-235)
0.0003 ton/ton of phenol-formaldehyde plastic molding compound.  The amount
of S and the equivalent l^SO^ consumed per ton of various manufactured
products is shown in Appendix C.

     The demand for S or 1^804 is derived  from the demand for the products
outlined in Table 1.  In most instances it is used in fixed  proportions with
other inputs in the production process.  For this reason demand is inelastic
in the short run but tends to become more  elastic in the long run because
there are very few unique uses for S.  The demand is subject to only modest
seasonal fluctuations.  Because of the pervasive use of S throughout the
industrial sector of the economy there has been a historically strong corre-
lation between the demand for S and the index of industrial  production.  That
is, the demand is responsive to cyclical fluctuations in business conditions
and expands when industrial production rises.

     In 1974 55% of all domestic S consumption was used in the manufacture
of fertilizers.  The balance of 45% was used in the production of the follow-
ing products:  plastic and synthetic products, 6%; paper products, 3%; paints,
4%; nonferrous metal production, 5%; explosives, 3%; petroleum refining, 2%;
iron and steel production, 1%; and other uses, 21%.  Each of the various uses
included in the latter category used <1% of  the  S demand  (8) .

     The distribution trends for the apparent consumption of S, by source,
1970-76, is outlined in Table 2.  The distribution in 1976 mainly from
domestic sources is listed as follows:

                       Frasch S                  43%
                       Recovered elemental S     29%
                       S in other forms           8%
                       Imports of Frasch and
                        recovered elemental S    16%

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                          TABLE 1.   U.S.  S  CONSUMPTION PATTERNS  1964-743
                                            (klong tons  S)



Agriculture (fertilizers)
Plastic and synthetic products
Paper products
Paints
Nonferrous metal production (Cu-U)
Explosives
Petroleum refining
Iron and steel production
Other
U.S. primary demand
1964

3,090
500
415
505
235
215
155
330
1,810
7,255
1965

3,610
555
430
510
265
230
165
295
1,921
7,981
1966

4,425
555
440
520
310
260
190
275
2,170
9,145
1967

4,735
495
400
505
260
265
195
220
2,176
9,251
1968

4,470
550
390
490
300
250
180
170
2,272
9,072
1969

4,465
570
365
445
370
260
190
125
2,379
9,169
1970

4,680
495
350
420
390
255
195
120
2.322
9,227
1971

4,800
515
320
380
410
255
200
105
2,188
9,173
1972

5,210
540
340
390
430
260
220
110
2,354
9,854
1973

5,520
580
370
420
500
280
230
110
2,224
10,234
1974

5,980
610
390
440
560
290
240
110
2,260
10,880

a.   Sulfur. U.S. Bureau of Mines reprint from Bulletin 667, 1975, p. 15.

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              TABLE 2.   APPARENT  CONSUMPTION OF S IN  THE U.S.

                                    (klong  tons)
                                    1970   1971   1972   1973     1974    1975    1976

Frasch
  Shipments                        6,504  6,738  7,613   7,438    7,898   6,077   5,860
  Imports                            539    449    269    302      954     967     731
  Exports                          1.433  1.536  1.852   1.776    2.601   1.295   1.198

     Total                         5,610  5,651  6,030   5,964    6,251   5,749   5,393

Recovered
  Shipments                        1,471  1,582  1,927   2,451    2,547   2,902   3,146
  Imports                            998    850    869    920    1,196     930     996
  Exports from the Virgin Islands  	-  	-  	^  	-   	62^   	57   	72_

     Total                         2,469  2,432  2,796   3,371    3,681   3,775   4,070

Pyrites
  Shipments                          339    316    283    212      162     237     286
  Imports5                           130    130  	50  	-   	-   	-   	-

     Total                           469    446    333    212      162     237     286

Byproduct sulfuric acid              537    518    546    600      654     767     942
Other forms0                         142    126    149 	88   	7£   	75  	77_

     Total all forms               9,227  9,173  9,854 10,235   10,818  10,603  10,768


a.  Sulfur, U.S. Bureau of Mines reprint from Bulletin 667, 1975, p. 15.
b.  Estimate.
c.  Includes consumption of hydrogen sulfide and liquid  sulfur dioxide.

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Three distinct trends in domestic consumption of S by sources are indicated
in Table 2.   Domestic Frasch S has steadily declined while domestic_recovered
S has steadily risen.  BOM predicts that these two trends will continue.
Although imports have become an increasingly important source of S for
domestic consumption, they are expected to remain stable or even decline over
the long range.

     The basic reason for these trends relates to the pervasive drive for
pollution control.  The Frasch industry formerly enjoyed a dominant role in
the S market throughout the U.S.  However, since 1960 recovered S and byproduct
H9SOA sectors have progressively obtained control of the markets in the
Western and Central States as well as a gradual penetration of the markets in
the Southern States.  Canadian imports of recovered S are largely confined to
the northern tier of states, whereas Mexican imports of Frasch S are limited
to the Florida and east coast markets.  As a result the Frasch industry has
gradually constricted its marketing to the Southern and Eastern States and
the inland waterway system with the export trade holding at a level of 1-2
Mtons.

     Long-term projections of S demand in the U.S. are shown in Table 3  (9).


ORGANIZATION OF FRASCH  S PRODUCTION, DISTRIBUTION, AND HANDLING

     BOM reports  the production of S in all forms in 1976 at 10.707 Mlong
tons  (5); elemental  S was produced by 69 companies at 182 plants in 32 states.
Ten of the largest companies  own 57 plants and account for 75% of the output.
The production was concentrated in Texas and Louisiana accounting for 68% of
the total output.  The  Frasch S was produced in these two states at 12 mines.
                     TABLE 3.  U.S. S DEMAND FORECAST

                               (Mlong tons)

                                       Forecast
                               1976   1980   1985   1990

                 Fertilizer     6.4    7.5    9.3   11.0
                 Industrial     4.5    5.3    6.0    6.8

                      Total    10.9   12.8   15.3   17.8
                                    10

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The mines are owned by  the  following companies:

          	Company	No.  of mines	State

          Freeport Minerals                     3         Louisiana
          Texas Gulf                             5         Texas
          Texas Gulf                             !         Louisiana
          Duval                                  1         Texas
          Jefferson Lake  Sulfur                  1         Texas
          Farmland Industries  Corporation
            (purchased from  Atlantic
            Richfield Corporation 11-76)          1         Texas


     Five of the  largest  mines account  for 82%  total Frasch output  and  48%
of the total production of  S in all forms (8).

     Frasch S production  is a  mining operation.   Wells  are sunk into  S-bearing
strata, S is melted by  hot  water injected into  the strata, and  the  molten S
is pumped out.  The molten  S is  pumped  from the  well to either  heated tanks
for storage as a  liquid or  to  vats where it cools and solidifies.

     About  75% of the total mining costs of Frasch S is variable, such  as
the cost of natural gas to  heat  water, water  treatment,  labor,  ana  operating
supplies  (10). The cost of  hot water to  melt  the S is by far  the most
important cost and will differ drastically from  mine to mine  as water require-
ments and fuel cost differ.  In  an analysis prepared for this study the cost
of natural  gas was varied from $0.20-$3.00/ kf t-* with an intermediate  value
of $1.00/kft3 (6). Water requirements or water rate varied from  1600 gal/ton
 of  S  produced  to  9000  gal/ton  of S.   Results of the cost calculations
(in  terms of third  quarter, 1974 dollars) are presented in Appendix D,
Tables  1-3.

     These  results indicate that the lowest capital investment  and  operating
costs are associated with mines  having  low water rates  and that cost  increases
markedly with increasing  natural gas costs.  For operation where the major
variables are constant, i.e.,  water  rate and  natural gas cost,  the  usual
economies of size prevail.

     The development of a S dome can be  compared to the punching of pins in
a pin cushion.  Each well punched into  a S dome  formation has an expected
life of 1-2 yr.   At any time the S mine  can have several wells  operating in
parallel.   The number of  wells depends  primarily on the short-run market
demand.  As the mining  process for a given dome  reaches the mature  stage,
operating costs increase  at an increasing rate due to the increased water and
energy requirements.  This  incremental  increase  causes  the supply price of
S to rise to a point where  it  is no  longer economical to continue mining the
S dome.

     Most molten  S is shipped  in liquid  form by  water from the  mines  or
transshipment terminals on  the Texas and Louisiana Gulf Coast to the marketing
terminals.  The basing  point for the Gulf Coast  market  is Port  Sulphur.

                                     11

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Marketing terminals are strategically located either on the inland waterway
system or along the east coast adjacent to ports served by deepwater vessels.
From the marketing terminal,  molten S is transported by barge, truck, or rail
directly to the point of consumption at a S-burning acid plant.  A map of the
relative locations for S terminals is presented in Figure 2.  March 1975 trans
port rates were used in this  study.  Rates were projected to 1978 with an
inflation factor of 1.15.

     Cost data were estimated for S-marketing terminals serving H2S04 plants
in eastern U.S. (11, 12).  The data obtained are presented in Appendix E in
terms of third quarter, 1974  dollars.  As expected, increasing the size of
the terminals decreases the unit operating costs.  Terminals that handle only
molten S have lower costs than terminals which reship both solid and liquid
S.  Storage requirements added, on the average, $2.47/ton to the cost of S
on the inland waterway system and $1.20 at deepwater terminals in Florida
and the east coast.  These data were used in the program to calculate the
production cost of l^SO^ for  this study.
     The delivered cost of S to each acid plant in the model is based on
$60/long ton for S f.o.b.  Port Sulphur plus transportation from Port Sulphur
through marketing terminals by either truck or rail to the acid plant, which-
ever is lower cost.  The least-cost mode for transporting S was extended to
cover a relative comparison of rail transportation from Port Sulphur versus
water transport — terminal throughput — truck or rail to the acid plant.  This
least-cost mode was selected in all cases for S delivered to a given acid
plant.
     Most of the large t^SO^ users own and operate captively their acid
production plants.  Such plants are located in close proximity to the major
markets for the prime product (chemicals) or close to the raw material inputs
used in the production process (fertilizers) .   Although many companies that
produce l^SO^ are industrial giants, there is  very little opportunity for
concentration in the acid market because of the pervasive use of H2SC>4 in the
many sectors of the industrial economy.  That  is, no single acid producer
uses enough S to exercise significant control  over the S market.  A breakdown
of the top 20 largest producers of H2S04 is presented in the analysis section
of this report.


S PRICE HISTORY

     The average annual price  f.o.b. mine  or S  plant  in  dollars  per  long ton for
Frasch and recovered S reported to BOM from 1954-76 are presented in Table 4.

     It is noted that the cyclical fluctuation in business activity in the
domestic economy during the 1958 and 1961 recessions did not affect S prices.
This situation prevailed over several decades  prior to 1965 due to the
existence of ample Frasch stocks under the control of a few major producers.
This was followed by a period of short supply  coupled with the rapid growth
of the fertilizer industry which resulted in abnormally high prices in 1967
and most of 1968 when an oversupply developed.   The oversupply caused a
general collapse of the S market lasting through most of 1973.  Then prices

                                    12

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               LIQUID SULFUR TERMINAL
                    INLAND WATERWAY
                   9'DEPTH OR MORE
                   6'-9'DEPTH
             — — UNDER CONSTRUCTION
             I—ft TENNESSEE-CUMBERLAND RIVER CANAL
Figure 2.  Geographic distribution of S terminals.
                           13

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 TABLE 4.   TIME-PRICE RELATIONSHIP FOR Sa




(Frasch and recovered S f.o.b.  mine/plant)
Average annual price, dollars per long ton
Year
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974,
1975b
1976° (first quarter)
a. Sulfur, U.S. Bureau
p. 16.
b. Preliminary.
c. Estimate.
Actual prices
26.65
27.94
26.49
24.41
23,82
23.46
23,13
23.12
21.75
19.99
20.19
22.47
25.77
32.64
40.12
27.05
23.14
17.47
17.03
17.84
28.88
46.50
55.00
of Mines reprint


Constant 1973 dollars
45.87
47.44
43.50
38.62
36.76
35.60
34.57
34.10
31.70
28.76
28.64
31.30
34.92
42.83
50.59
32.55
26.42
19.07
17.98
17.84
28.18
38.72
43.55
from Bulletin 667, 1975,


                    14

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rose to an average of $51.19/ton  f.o.b.  mine/plant in 1976 followed  by  an
apparent stabilizing trend.   The  average price for recovered S during  this
same period was $13.50/ton  lower  f.o.b.  plant, as compared to Frasch S  price.

     S is normally sold under long-term contracts direct to industrial  con-
sumers and priced on a delivered  basis at regional terminals.  The regional
terminal prices vary with location.   Export prices are determined independent
of domestic prices.  The f.o.b. or f.a.s. gulf port prices published in the
Chemical Marketing Reporter and other journals reflect spot purchases.
Generally the quoted prices for spot and contract sales are the same, but
with no formal commodity exchange for S it is difficult to determine the
exact S price at any given  point  in time.  The current published price  in
the Chemical Marketing Reporter is $65/long ton f.o.b. gulf ports.   The price
assumed for this study is $60/long ton f.o.b. Port Sulphur.
 S RESERVES

     G. H. K. Pearse  recently completed a study on the long-run S  supply  for
 North America  (1).  He  projects the long-run supply price gradually increas-
 ing  from  $10-$40/ton  f.o.b.  mine in 1970 dollars (about $50 in 1974).   The
 resulting S  supply  price  increase will encourage the relatively inefficient
 Frasch  and native S mines to become producers over time.   He projects  that
 the  current  S reserves  in the U.S. from conventional sources (Frasch process,
 native  ore,  petroleum,  natural gas, sulfide ores, and pyrite) in the amount
 of 290  Mtons will be  mined out at current production rates, about  12 Mtons/yr,
 by 2000-      During  the  same period it is estimated that 110 Mtons of S  will
 become  available from oil shales and coal gas, giving a total cumulative
 production of 400 Mtons.   The cumulative demand in the U.S. is estimated  to
 be 550  Mtons by 2000, leaving a deficit of 150 Mtons of S (513.95  Mtons
 of H2S04).

     BOM  estimates  the  U.S.  reserves at 230 Mtons (8).  This includes  reserves
 of primary S deposits of  the elemental, pyrite, and sulfate types.  Such
 reserves  are defined  as S that is recoverable at present price levels  using
 current technology.

     They have  also defined "other identified S resources" as S potentially
 recoverable  from identified deposits at all price levels by full utilization
 of current technology.   The domestic reserves identified in this classifica-
 tion amount  to  400  Mtons.  No attempt is made in the latter estimate to
 associate the estimated supply price with specific reserve sources. A study
 in this area is needed.
 IMPACT OF ENVIRONMENTAL REGULATIONS ON S PRODUCTION

 Frasch S Production

      There are relatively few environmental problems associated with the
 Frasch sector of the industry.  The major centers of production are located
 in remote undeveloped areas and the molten S product which is produced and


                                      15

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distributed directly to the consumer poses no environmental problem.  However,
the small portion of elemental S that is stored and distributed in the solid
form (referred to as vatted S) does cause a dust problem.  Special handling
techniques have been developed to overcome the dust hazard.  It is estimated
that 95% of the elemental S distributed to S-burning acid plants is handled
in the liquid form.

Recovered S Production

     The growth in the recovery of S from natural gas since the mid-1950 's
has been one of the most significant trends in the S market.   The principal
sources of recovered S are the hydrogen sulfide (l^S) contaminants in sour
natural gas and the organic S compounds contained in crude oil.  Recovery is
mainly in the elemental form.  Its production has been stimulated by the
increasing demand for low-S fuel as an air pollution control measure.
Recovered elemental S accounted for 29% of the total domestic production of
S in all forms in 1976 (3) .   It was produced by 51 companies in 137 plants
in 27 states.  The five largest recovered elemental S producers were Chevron
USA Inc., Exxon Company USA, Getty Oil Company, Shell Oil Company, and
Standard Oil Company of Indiana.  Together their 41 plants accounted for 53%
of the recovered elemental S production in 1976.  Future recovery of S from
natural gas is likely to decline as gas supplies drop.

Byproduct H7SOA Production at Smelters

     In the smelting of nonferrous sulfide ores, primarily copper (Cu) , lead
(Pb), and zinc (Zn) , the S is converted into sulfur dioxide (S02) which can
be recovered from stack gases in the form of ^504.  The acid is referred to
as byproduct H^SO^.   In practice only the more highly concentrated portion of
the smelter gases are used to produce t^SO^.   Because of the remote location
of most nonferrous metal smelters the pollution control laws allow inter-
mittent controls for the lean streams of the S02 in the stack gases.
     The S contained in byproduct I^SO^ produced at Cu, Pb, and Zn smelters
during 1976 amounted to 9% of the total domestic production of S in all forms.
This represented a 23% increase in output as compared to 1975.  It was pro-
duced by 13 companies at 24 plants in 13 states.  The five largest producers
of byproduct t^SO, were American Smelting and Refining Company, Magma Copper
Company, Kennecott Copper Corporation, Phelps Dodge Corporation, and St. Joe
Minerals Corporation.  Together their 14 plants produced 71% of the output
during 1976 (3).

H2S04 Production in S-Burning Acid Plants

     All H2S04 plants, particularly the older ones, have problems in con-
trolling the amount of pollutants in their tail gases required by air pollu-
tion control laws.  The SIP standards in most states require the conversion
efficiency of S to H2S04 to be equal to or >99.7% efficient.  This
means that a major portion of the existing plants must add a retrofit
tail gas cleaning system in order to comply with the air pollution control
laws.   A detailed discussion on the retrofit alternatives for H2S04 plants
is outlined in Appendix F.

                                     16

-------
DOMESTIC CONSUMPTION OF H2S04

     In 1974, 90% of the  S  consumed in the U.S.  was either converted to  HoSO/
or produced directly in this form.   H2SOA is considered to be the most
important of the mineral  acids.   In 1974 H2S04 was produced at 150 plants  in
42 states  (13).

     H2SO^ is produced by burning S or S-bearing materials to form S02.  The
S02 is oxidized by air in the  presence of a catalyst to form S03.   The 803
is then passed through an adsorption tower where it is absorbed in recircu-
lating concentrated acid.   This  process produces concentrated acid of high
purity; compact plants of high capacity are feasible.

     Sources of S or S02  for the manufacture of H2SO.  include (1)  elemental
S,  (2) pyrites,  (3) gypsum, (4)  petroleum products, (5) smelter off-gases,
and  (6) waste gases from  burning fossil fuels.  In 1975 a brimstone-based
acid accounted for 91% of the  total H2SO^ production,  followed by non-
ferrous smelter gases at  7% and  all other raw material sources at 2%.
     H2S04  capacity  and production have grown slowly.   In 1967
 capacity was  36.93 Mtons.   The average growth rate has been approximately
 3.5% annually;  and,  by 1975,  capacity had grown to 48.18 Mtons.   Based  on
 current announcements  of new  plants,  H2S04 capacity by 1980 should  be approxi-
 mately 51.0 Mtons.

     In 1967, U.S. production of H2S04 from all sources was 28.8  Mtons,
 representing  an average operating rate of 78% of capacity (13) .   In the
 following 7 yr,  a general improvement in operating rates for H2S04  plants
 took place, reaching a peak of almost 90% of capacity  during the  phosphate
 fertilizer  shortage  of 1973-74.   In 1975, with the addition of almost 10
 Mtons of additional  capacity  the average operating rate for the industry
 dropped to  only 67%  of capacity.  Production of H2S04  from all sources  was
 in excess of  32.3 Mtons.

     Almost all plants in the U.S. today are contact plants. Chamber plants,
 which are being phased out, now comprise only 0.2% of  total plant capacity
 compared to 3.5% in  1967.

     The use  of spent  H2S04,  the second most common process, has  decreased
 over the past 8 yr from a high of 20.5% of capacity in 1967 to 17.4% in 1975.
 It is expected  that  use of spent H2S04 will drop to 16.5% of capacity by  1980.

     Production from smelter  operations has been increasing.  In  1967,  the
 percent of  total capacity for plants associated with the smelters was only
 8.5.  By 1975,  it had grown to 12.3% and is expected to continue  to a high
 of 14.7% by 1980. The availability of this acid for fertilizer use, however,
 may be limited  because of its use in the Southwest for leaching Cu  and  U
 ores.  Table  5  lists the capacity, production, and operating rates  for  H2S04
 in the U.S. for the  years 1967-80 (14).
                                      17

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                                 TABLE 5.  U.S.  H2S04 MARKET STATISTICS

                                            (Mtons  of material)
            Product
 1967
1970
1973
1974
1975
1976
1977
1978
                                               1979
                                                               1980
 Total Sulfuric  Acid
   Capacity
   Production
   Operating rate,  %
 36.93    36.71   39.22   38.69   48.18
 28.82    29.53   31.95   34.18   32.37
(78.0)   (80.4)   (80.0)  (88.3)  (67.2)
                               48.54   49.72   50.41   50.89   51.01
Smelter Sulfuric Acid
Capacity
Total capacity, %
Production
Operating rate, %
Spent Sulfuric Acid
Capacity
Total capacity, %
Production
Chamber Process Plants
Capacity
Total capacity, %
Production
Operating rate, %
Sulfur- Burning Contact Plants
Capacity
Total capacity, %

3.14
(8.5)
1.25
(39.7)

7.56
(20.5)
1.08

1.28
(3.5)
0.84
(66.0)

24.94
(67.5)

3.39
(9.2)
1.84
(54.1)

7.58
(20.6)
1.27

0.67
(1.8)
0.32
(48.2)

25.08
(68.3)

3.81
(9.7)
2.05
(54.0)

8.60
(21.9)
1.56

0.30
(0.8)
0.11
(35.4)

26.51
(67.6)

4.14
(10.7)
2.24
(54.1)

8.32
(21.5)
0.75

0.14
(0.4)
0.13
(93.0)

26.09
(67.4)

5.97
(12.3)
2.63,
(44.0)

8.40
(17.4)
0.95

0.12
(0.2)
0.10
(83.9)

33.70
(70.0)

6
(13



8
(17


0
(0



33
(68

.67
•7)



.41
.3)


.07
•1)



.39
.8)

6.82
(13.7)



8.41
(16.9)


0.07
(0.1)



34.42
(69.2)

7.38
(14.6)



8.41
(16.7)


0.07
(0.1)



34.55
(68.5)

7.38
(14.5)



8.41
(16.5)


0.07
(0.1)



35.03
(68.8)

7.50
(14.7)



8.41
(16.5)


0.07
(0.1)



35.03
(68.7)
a.  Refortified acid only.

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          END USE ANALYSIS OF  S AND H2S04  IN FERTILIZER PRODUCTION


PHOSPHATE FERTILIZER MARKET

     While S and H2S04 have many uses,  it  is estimated  that about two-thirds
of the total U.S. consumption  of S in all  fortnr,  is  used in the  fertilizer
industry (15).  The balance of consumption was for  a variety of uses in
essentially every sector of the domestic manufacturing  industry.  In 1976
preliminary data indicate that 6.4 Mtons of  S was   used in the production of
fertilizer (Table 6).  Ninety  percent of the total  went to the production
of phosphoric acid  (H3P04)  and normal  superphosphate.   Thus,  any  analysis of
the future of the S and  H2S04  market must  consider  the  prospects  of  the  phos-
phate fertilizer market.   The  following is a review of  the production  and use
patterns that have  taken place in  the  U.S. phosphate fertilizer market in the
past  few years  and  a  discussion of  the  future U.S.  outlook for  the phosphate
industry.

          TABLE 6.  U. S. CONSUMPTION OF S IN ALL FORMS BY END USE

                            (klong tons  S equiv)


                                         1974     1975     1976
           H2S04
             Fertilizer acid
               H3P04                     4,945    5,410    5,560
               Normal superphosphates      405      290      230
                     SO, and other         685      670      610
                                           ^ '        • ' ~ T       --• ••
                Total fertilizer acid    6,035    6,370    6,400

             Industrial acid             3,715    3,080    3,285

                Total H2S04              9,750    9,450    9,685

           Nonacid                       1,250    1.200    1.215

                Total in all forms      11,000   10,650   10,900
                                      19

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Phosphate Consumption Patterns

     Between 1945 and 1974, the U.S.  phosphate fertilizer market has averaged
an annual growth rate of almost 4.5%/yr (16).   Over this period, the market
has been characterized by several major cyclical movements; however, market
growth has exhibited a stable upward movement.  In recent years, there has
been an indication that phosphate use by farmers has begun to level off
(Table 7) .  Soil test results have shown an accumulation of phosphorus (P)
in the soil in some areas, and application rates on the nation's major crops
appear to be approaching optimum levels under today's cropping practices
and management.

     In 1975 phosphate fertilizer use declined by more than 10%.  Analysts
generally agree that this decline was caused by an imbalance in the input and
output price structure faced by the farmer during the year.  In relation to
the prices received by the farmer for his crops, fertilizer price levels
were too high; and the farmer curtailed fertilizer use.  With an improvement
in the benefit to cost ratio for the farmer in 1976, phosphate fertilizer use
recovered the lost demand of the 1975 season and exceeded its previous highs
by almost 200,000 tons of P2C>5 (17).   While this recovery was significant,
it left in doubt the question of the future growth pattern for the phosphate
market.

     Some indication of the future growth in phosphate fertilizer demand can
be found by looking at the recent history of average rates of application on
the four major crops grown in the U.S. (Table 8) (18).  Cotton producers,
for example, have not changed phosphate application levels since 1964,
responding only to changing market conditions as determined by cotton prices.
Until last year, when phosphate application rates reached all time highs,
corn had shown the same pattern.  With application rates and the percentage
of the planted acreage receiving phosphates appearing to be relatively con-
stant, acreage planted becomes the key factor in forecasting the future
demand for phosphate fertilizers in the U.S.  In recent years, planted
acreage has been at an all time high as government policy has been geared to
stimulating maximum farm production.   High levels of exports of farm products
at very favorable prices in response to food shortages in many parts of the
world have played an important part in the farm picture in the past few years.

     But this situation has been changing rapidly.  Grain-producing countries
have had good weather conditions, are reporting bumper crops, and are actively
seeking export markets.  In addition, some of the major importing nations
are also in the midst of harvesting a record crop production and establishing
buffer stocks as a future hedge against poor crop years.  These factors make
forecasting the future national agricultural policy difficult and clouds the
outlook for the short-term phosphate fertilizer market.

     Projections of phosphate fertilizer use in 1980 which were made prior to
the 1976 recovery indicate a range between 5 and 6 Mtons of P205 (19).
Including the 1976 recovery projections of 1980, demand has varied from 5.5-
6.3 Mtons P205, centering around 5.8 M (20).  If phosphate use falls within
these suggested ranges, the average annual growth rate for the next few years
will remain below the long-term average for the industry.

                                     20

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TABLE 7.  U.S. PHOSPHATE CONSUMPTION




           (Tons of

Fiscal
year
1955
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Total
P205
consumption
2,283,660
2,572,348
2,645,085
2,807,039
3,072,873
3,377,841
3,512,207
3,897,132
4,304,688
4,453,330
4,665,569
4,573,750
4,803,443
4,863,738
5,085,162
5,098,626
4,510,979
5,215,246
P205
in
mixtures
1,821,087
2,033,316
2,069,425
2,219,444
2,473,599
2,704,985
2,816,056
3,110,784
3,502,897
3,579,140
3,724,237
3,709,062
3,943,372
3,997,280
4,237,591
4,271,429
3,717,825
4,422,380
Direct application materials
Superphosphates
291,406
287,335
303,256
313,860
318,415
382,287
403,403
506,351
517,470
566,120
656,713
608,338
610,969
620,059
576,580
576,497
566,953
564,667
Ammonium
phosphates
84,617
171,329
188,398
204,768
205,457
215,604
204,401
220,908
223,761
227,288
207,448
183,688
178,878
174,277
201,423
193,000
175,899
228,199
Total
462,573
539,032
575,660
587,595
599,274
672,856
696,151
786,348
801,791
874,190
941,332
864,697
860,071
866,458
847,571
827,197
793,154
792,866
Diammonium
phosphates
113
35,278
63,482
110,074
177,487
244,271
302,088
417,821
451,452
608,296
723,786
726,486
814,938
883,795
1,073,198
1,051,416
1,038,091
1,486,950

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         TABLE 8.  AVERAGE PHOSPHATE FERTILIZER APPLICATION RATES

                        FOR MAJOR CROPS IN THE U.S.

                                 (Lb/acre)


                 Year   Corn   Cotton   Soybeans   Wheat
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
33
40
49
51
57
56
63
54
57
54
54
50
60
30
32
32
30
31
31
27
27
30
32
31
21
28
3
5
9
9
9
11
10
10
13
13
11
10
12
12
12
13
16
15
15
15
15
16
17
18
15
19

Phosphate Production and Trade Patterns

     The phosphate fertilizer market is made up of several different types
of products  that have different S requirements.  These can be classified as
normal superphosphate, concentrated superphosphate, ammonium phosphates,
liquid mixtures, and granular mixed fertilizers.  Depending upon the grade
of phosphate rock used, S requirements for the production of normal super-
phosphate range from 0.60-0.65 ton  of S per ton of P205, concentrated super-
phosphate from 0.65-0.70, and wet-process H3P04 from 0.90-0.95 (21).  The
P205 content of ammonium phosphates and most fertilizer mixtures is derived
from wet-process H3P04-  Because of the wide range of S requirements, the
future phosphate product mix is an important factor in determining the out-
look for the S and ^SO^ market.

     Production of wet-process H^PO^ and the major phosphate fertilizer
materials in the U.S.  is  shown in Table 9 (22).  Between 1960 and 1976,
HoPO/ production increased from 1.3 Mtons of ?2®5 to almost 7 Mtons.  During
the same period, normal superphosphate production has steadily declined and
today is <400,000 tons of P205-  Concentrated superphosphate production has
remained relatively constant between 1.0 and 1.5 Mtons.

     The significant change in the U.S. phosphate fertilizer market has been
the rapid shift from low-analysis materials to a market based almost entirely
on the production of wet-process H3P04.  In addition to the ammonium phosphate
grades, there has also been a significant gain in the liquid mixed  ferti-
lizer market which is based primarily on wet-process superphosphoric acid.
                                      22

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ISJ
LO
                      TABLE 9.   U.S.  PRODUCTION OF H3P04 AND PHOSPHATE FERTILIZERS

                                             (ktons of

Year
1955
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Wet-process
phosphoric
acid
775,000
1,325,000
1,409,000
1,577,000
1,957,000
2,275,000
2,896,000
3,596,000
3,993,000
4,152,000
4,328,000
4,642,000
5,016,000
5,775,000
5,919,000
6,186,000
6,889,000
6,938,000
Multinutrient materials
Superphosphate
Normal
1,558
1,270
1,247
1,213
1,227
1,206
1,113
1,138
1,184
914
807
670
626
677
620
698
484
388
Concentrated
707
986
1,024
960
1,113
1,225
1,466
1,696
1,481
1,389
1,354
1,474
1,513
1,659
1,693
1,719
1,649
1,595
Ammonium
phosphates
_
269
370
536
-
-
1,081
1,376
1,747
1,633
1,844
2,092
2,395
2,577
2,919
2,654
3,044
3,633
Other
__
131
102
113
-
-
172
239
284
215
288
361
468
570
347
296
218
232
Total
8
400
472
649
891
1,034
1,253
1,615
2,031
1,848
2,132
2,453
2,863
3,147
3,266
2,950
3,262
3,865
Total
2,273
2,656
2,743
2,822
3,231
3,465
3,832
4,449
4,696
4,151
4,293
4,597
4,992
5,483
5,578
5,367
5,395
5,848

-------
H3P04 use in the production of granular complete mixed fertilizers also
remains as a significant part of the phosphate fertilizer picture.

     The Canadian phosphate market is very similar to the U.S. with  the
exception that normal and concentrated superphosphate play a much smaller
role in the total supply picture.  Most of the phosphate production  in
Canada is made up of the various grades of monophosphate and diammonium
phosphate materials.

     Exports of phosphate materials to the world market now play an  important
role in the supply situation for the U.S.  It is estimated that over 20% of
the total U.S. production of finished phosphate fertilizer materials now
enters world markets.  Up to now the ammonium phosphates and concentrated
superphosphate have been the primary products in the export market.  However,
in the past several years there has been a growing trend for other countries
to establish phosphate product production facilities based on the importation
of ^PO^.  The U.S. has a key position in this market and is exporting sub-
stantially higher amounts of ^PO^ than it has in previous years.  Product
exports are shown in Table 10 (23).

     When product production levels are related to trade tonnages, the impact
of the shift to HoPO^-based materials is apparent.  Concentrated super-
phosphate production has leveled off while trade levels have increased.  Thus,
the available supply for the U.S. market for this product has been on the
decline along with supply of normal superphosphate.  Ammonium phosphate
production has been expanded to the point of satisfying the domestic market
and allowing large gains in the export sector.  Ammonium phosphates now
account for over 60% of all U.S. phosphate production entering the export
market.

Future Supply Patterns

     The last .large-scale expansion of phosphate production facilities took
place from 1973 to 1975.  At that time, the total wet-process l^PO^ capacity
went from 6.4 Mtons to 8.6 Mtons P205-  With the final completion of this
expansion program early in 1977, the U.S. 1^04 capacity stood at just over
9.0 Mtons.  There have been no expansions of Canadian capacity which now
contributes over 900,000 tons of P2C>5 to the North American total (24).
Between now and 1980, there are no new capacity expansions anticipated.
Several possible projects have been in the planning stage for some time but
cannot be included in the tabulation at this time.  Should any of these units
be built, U.S. capacity will exceed 10 Mtons of ?2®5-

     Over the last 15 yr, the number of normal superphosphate plants has
shown a steady decline.  At one time, they numbered over 200 units scattered
over the country, but today they number only in the forties and are located
primarily in the southeastern U.S.  Faced with rising costs on all fronts,
many of these plants have been converted to ammoniation-granulation facili-
ties which use H^PO, as the primary phosphate source.  It is expected that
normal superphosphate production will continue to decline.  However, it will
be a somewhat slower rate than has been experienced in the past few years.
                                     24

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       TABLE 10.  U.S. PHOSPHATE FERTILIZER EXPORTS

                      (ktons of P205)
       Superphosphate    Ammonium    Phosphoric   Total all
Year   Normal  Triple   phosphates	acid	materials
1955     57      60          38           -           155

1960     31     144          46           -           221
1961     30     174          34           -           238
1962     26     228          53           -           307
1963     18     270          81           -           369
1964     39     276         159           -           474

1965     17     233         140           -           390
1966     18     294         338           -           650
1967     15     291         556           -           862
1968     19     533         556           -         1,108
1969      6     361         413           -           780

1970      8     325         448          19           800
1971      2     321         597          57           977
1972     12     393         799          22         1,263
1973      3     409         983          40         1,473
1974      6     488         876          33         1,451

1975      6     494       1,181         169         1,882
1976      2     589       1,242         216         2,049
                             25

-------
It is doubtful that this product will disappear completely from the phosphate
picture; however, its market share will remain quite small in the years ahead.

     Very little in the way of capacity additions for concentrated super-
phosphate are expected.  This product's market share will probably decline;
however, it is expected that production levels will remain relatively con-
stant over the next few years.  Concentrated superphosphate will remain a
popular export product for those countries that have domestic nitrogen (N)
supplies and do not wish to import N in the form of ammonium phosphates.

     The future supply outlook for the U.S. phosphate industry is shown in
Figure 3.  Total demand for phosphate materials including that entering the
export market should be approaching 8 Mtons of ?2^5-  Tne potential supply
that can be made available to the fertilizer industry if plants are operated
at their historical average operating rate of 87% of capacity, and assuming
the continued decline in normal superphosphate production, will balance with
this level of demand by the end of the decade.  Between now and 1980, however,
it can be expected that the industry will operate at somewhat reduced levels
moving to higher or lower levels as dictated both by domestic demand and the
demands of the export market.

Implications for the S Market

     From the above discussion it can be concluded that the S industry should
not expect the phosphate fertilizer market to absorb any large-scale
"increase" in the production of H2S04 in the next few years.   The shift to
t^PO^ with its higher S requirement is almost complete so the changing product
mix of the phosphate industry will have a relatively minor impact on the S
market.

     S demand by the phosphate industry should be variable over the next few
years as operating rates change according to the demands of the export market.
Between 1975 and 1980, however, estimates show that total S demand by the
fertilizer industry should increase by about 1 Mtons.  The industrial sector
of the market is estimated to grow by 1.2 Mtons during the same period.
                                     26

-------
  10
O
 w
o.

u_
O
to

O
(O
z
o
                            POTENTIAL  FERTILIZER
                            SUPPLY AT  87%
                            OPERATING RATE
                                    PHOSPHATE FERTILIZER
                                    DEMAND  INCLUDING
                                    NET EXPORTS
          1974
                   1975
1976
1977
1978
1979
1980
                                                                   1981
             Figure 3.  U.S. phosphate supply - demand outlook.
                                     27

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          ANALYSIS OF THE POTENTIAL DEMAND FOR ABATEMENT BYPRODUCT
     In this study, it was assumed that the H2S04 market can be simulated as
though all consumption occurs at the H2S04 plants and that acid-producing
firms will close these plants and buy abatement acid if it can be delivered
equal to or below their avoidable cost of production.  Avoidable cost is an
estimation of the production cost that could be avoided by closing an existing
acid plant assuming abatement byproduct acid would be available in amounts
equal to the plant production capacity (330 days/yr).  To develop the required
inputs to the model on the demand side, it was necessary to identify all
potential acid producers and their avoidable costs of production.  The acid
plants selected include only those plants that burn elemental S as feedstock
for the production of H2S04.

     The sludge acid plants are excluded from the analysis because of their
unique operating procedure.  That is, they receive sludge acid or weak acids
which are decomposed to produce pure S02 used as feedstock to an acid plant.
The sludge acid feedstock is usually supplemented with elemental S in order
to efficiently produce a concentrated commercial- grade acid.

     Sludge acid plants could use a regenerable product loaded with S02 from
an FGD system by regenerating the absorbent onsite.   However, this action
would require considerable modification of the existing acid plant facilities.
It was not included in the study.
THE EXISTING S-BURNING ACID PLANTS IN THE U.S.

     TVA's computerized file of worldwide manufacturers of fertilizer and
related products contains a list of 104 plants producing ^804 by burning
elemental S.   Total annual production capacity exceeds 35 Mtons.  Fourteen of
these plants are located in the 11 Western States with a production capacity
of 3.04 Mtons  (3).   This group was analyzed separately because of the unique
characteristics of the market in these states coupled with the difficulties
encountered in modeling the transportation rates in the transcontinental
freight zone.  This is discussed further in the section dealing with the
marketing of byproduct acid produced by smelters.

     The acid plants located in the 37 Eastern  States  were considered as a
potential market for abatement byproduct acid.  This includes 90 S-burning
H2S04 plants with an annual production capacity of 32.237 Mtons based on
330 days' operation/yr.  The geographic distribution of these plants by states
is outlined in Figure 4 and Table 11  (14).
                                      29

-------
                                  SULFUR-BURNING ACID  PLANTS
                                  •  FRASCH SULFUR
                                  o  RECOVERED SULFUR
Figure 4.  Geographic distribution of S-burning acid plants  (1978).

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        TABLE  11.   U.S.  S-BURNING H2S04  PLANT CAPACITY (1978)a




                          (ktons - 330 days/yr)

State
Alabama
Arkansas
Florida
Georgia
Iowa
Illinois
Indiana
Kansas
Louisiana
Massachusetts
Maryland
Maine
Michigan
Total East
State
California
Colorado
Idaho
New Mexico
Total West
Total Contiguous


Number of plants
4
2
20
3
1
6
1
1
6
1
1
1
2
37 States
Number of plants
6
1
2
1
11 States
States 48


Annual
capacity
342
205
16,189
365
98
985
56
105
4,965
120
350
75
60

Annual
capacity
1,271
55
1,310
141




State
Missouri
Mississippi
North Carolina
New Jersey
New York
Ohio
Oklahoma
Pennsylvania
South Carolina
Tennessee
Texas
Virginia
West Virginia

State
Nevada
Washington
Wyoming





Number of Plants
2
1
6
9
1
5
1
1
1
1
4
8
1
90
Number of plants
1
1
2

14
104


Annual
capaci ty
553
1,220
2,026
1,720
6
665
110
75
42
132
806
832
135
32,237
Annual
capacity
140
15
110

3,042
35,279

a.  Projected 1978
                                    31

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THE IMPACT OF ABATEMENT ACID

     H2S04 plants are widely scattered throughout the U.S. chiefly because of
the low-bulk value of the acid, difficulties in handling the acid in the bulk,
and subsequent high cost of shipment as compared to handling elemental S.
Therefore, acid has been traditionally produced by S-burning plants in captive
use near the point of consumption.  However, many existing plants are old and
will soon need replacing.  Some will likely shut down in 1978 because
compliance with pollution control regulations will not be economical.  This
group should be receptive to the opportunity to buy abatement acid in lieu of
building a new acid plant.

     Many power plants enjoy a unique location advantage for supplying abate-
ment acid in the existing market.  This is especially true for acid plants
located in the more remote areas from traditional S supplies.  The most orderly
way to incorporate abatement acid would be to replace the capacity of relative-
ly high-cost S-burning H2S04 plants.  These are generally remotely located
from S sources.  The producer is given the opportunity to close his plant down
and buy abatement acid if it results in a saving.  The more efficient plants
would continue to produce.


PRODUCTION COSTS FOR H2S04

     The expenses that could be saved or avoided by shutting down existing
acid producers were estimated.  Such expenses are delineated below:

           Raw material          S

           Utilities             Electric power
                                 Cooling water
                                 Processed water
                                 Boiler-feed water

           Operating expenses    Labor
                                 Supervision

           Capital costs         Amortized costs for maintenance of
                                 existing facilities and amortized
                                 costs of new capital investment at
                                 end of useful plant life

     In the  Phase I study a computer program was developed using these inputs
to  calculate contact H2S04 production costs.  Details of this program are
given in  the report on Phase I.  For existing plants, the initial capital
expenditures are handled as a  "sunken investment" and, therefore, do not enter
directly  into the firm's decision to discontinue present production and buy
abatement ^504.  Only avoidable costs are considered in making this decision.

     Annual  costs are calculated in perpetuity using the discounted cash flow
analysis method.  The outlay streams are then amortized or averaged over all
years in  the firm's planning horizon.  The cost streams are  composed of:


                                      32

-------
   1.   Constant annual expenditures for S, utilities, and operating expenses

   2.   Periodic expenditures for new replacement plants

   3.   Maintenance of existing facilities which is assumed to grow at a
       compound rate

The impact of inflation is not included in the analysis.  These cost streams
for a new plant are presented in Figure 5.

     The optimum useful life is identified as the minimum point on the average
total cost curve.  At this point the added capital cost savings that result
from increasing useful life 1 yr equals the added maintenance saving from
shortening useful life 1 yr.  The average capital charge of 19.3%, identified
in Figure 5, covers a range from 23-36 yr.  Random effects, such as abrupt
physical, economical, technological, or environmental changes, play the
dominant role during this period with regard to the timing of plant replacement
or shutdown.

     H2S04 plants built prior to 1960 were assumed to average 95.5% conversion
of S to acid.  Plants built between 1960 and 1975 were assumed more efficient
with 97% conversion.  These efficiencies, however, are not representative of
plants that must operate after 1975 since emission limitations will require an
efficiency of at least 99.7%.  For the potential growth market, it was
necessary to consider tail gas cleanup at a 99.7% efficiency level for new
plants (double absorption).  Capital and operating cost estimates for acid
plant tail gas cleaning systems for existing plants are outlined in Appendix F.
These costs, of course, must be added to the avoidable costs of existing plants.


THE DEMAND CURVE FOR ABATEMENT ACID

     The avoidable costs (theoretical) are calculated at each respective acid
plant location considered in the study.  The major variables used in the acid
plant cost generation program are outlined in Table 12 along with example
values.  Costs of manufacture based on data generated here indicate that most
of the acid production costs range from $25-$45 depending on plant location,
size, and age; the March 1976 price for H2S04 (100% H2S04 f.o.b.) was $44.95/ton
(25).   Cost estimates projected for each specific acid plant are outlined as
a demand schedule in Appendix G.  A summation of capacity of acid plants
versus avoidable cost of production is shown in Figure 6.  The resulting plot
defines the demand curve for abatement acid.

     The demand curve is estimated by ranking all acid plants from highest to
lowest cost and accumulating demand quantities to show acid cost as a function
of acid plant capacity.  At a very high cost of alternative supply only a few
acid producers could justify buying rather than producing t^SO^.  These plants
tend to be old, low-volume producers far from S supplies.  As supply cost of
abatement acid declines, more acid producers would become potential customers.
At low supply costs all but the largest, most modern acid plants located near
S supplies could be shut down.  The important implication for the present study
is that small quantities of abatement acid could be marketed at high value but
as the supply increases the value declines.

                                      33

-------
  20
              T
                TOTAL"
                                 \
                                     OPTIMAL
                                     USEFUL LIFE
  15
o
o
-i

j*
a

o
   10
              CAPITAL-
              MAINTENANCE
o
a:
UJ
o.
                                   I
              10
                        20        30        40

                          USEFUL LIFE .YEARS
50
60
           Figure 5.  Amortized value of maintenance and capital

               outlays for  new I^SO^ plants  (assuming 11%

                 interest and 5% compound maintenance).
                                  34

-------
           TABLE 12.  MAJOR PARAMETERS IN MODEL
No.
Description of variable
Example
 value
 1    Tons of S/ton H2S04 (before 1960)               0.3053
 2    Tons of S/ton H2S04 (after 1960)                0.3006
 3    Year of technology change                         1960
 4    H2S04 plant investment ($/ton/yr)               27.285
 5    Capacity for this plant (ktons/yr)               247.5
 6    Scale factor for determining investment for
       other sized plants                           0.734054
 7    Fixed conversion cost/ton ($/ton)                 0.47
 8    Fixed annual conversion cost ($/yr)            116.620
 9    Taxes and insurance rate                         0.015
10    Time preference rate for money                    0.11
11    Compound maintenance rate                         0.05
12    Economic useful life (yr)                           34
13    Percent H2S04 concentration                         98
14    Port Sulphur price ($/ton S)                     53.57
15    Steam plant H2S04 price ($/ton H2S04)                0
16    Proportion of 330 tons/day capacity estimate         1
17    Number of years considered                           1
18    Year considered                                   1978
19    Unit cost inflation factor over 1973              1.93
20    Transportation cost inflation over 1975           1.15
21    Retrofit cost for compliance                      4.41
                             35

-------
o
H
W
U
PL,
    00
     80
     60
    40
    20
                            1
I
1
I
                             10          15         20         25

                      CUMULATIVE ANNUAL  CAPACITY, MTONS OF 100%
                                30
                                 35
             Figure 6.   Abatement  byproduct 1^804 demand curve (Eastern States)

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     ANALYSIS OF THE POTENTIAL SUPPLY OF BYPRODUCT H2S04 FROM SMELTERS


     S contained in byproduct acid at Cu, Pb, and Zn smelters amounted to 9%
of the total domestic production of S in all forms in 1976.  It represents
the third most important source of S in the S industry  as  shown in  Table  2.
The byproduct acid market is a well-developed market and it has been  in
operation a number of years.  The recent increases in production  outlined in
Tables 5 and 6 are a direct result of the existing environmental  regulations
that require more stringent control of emissions.

     New source performance standards for H2S04 plants  limit the  quantity of
S02 that may be emitted to 4 Ib S02/ton of H2S04.   Proposed standards for
primary Cu, Zn, and Pb smelters limit the emission concentration of S02 to
<0.065% by vol requiring the removal of  approximately 90% of the emitted
S02-   Although state regulations for existing t^SO^ plants and smelters are
in most cases less stringent than the NSPS,  there are cases where the state
regulation  is equal to NSPS.
END USES FOR BYPRODUCT ACID

     Approximately 5% of the domestic S consumption is used for leaching of
Cu and U ores with l^SO^.  In the Cu industry it is used for the extraction
of the metal occurring in deposits, mine dumps, and wastes when Cu content
is too low to justify concentration with conventional flotation techniques.
It is also used for the recovery of Cu from ores containing Cu carbonate and
silicate minerals that cannot be treated efficiently by flotation processes.
Smelter acid is also used as a reagent for the recovery of U from ores.  The
surplus of the byproduct smelter acid goes into the same market identified
in Table 1 for acid produced from elemental S.  A number of the captive use
^2^4 plants which closed down in the last decade are presently using by-
product acid from smelters.  The most popular end use is for fertilizer
production.
1978 PRODUCTION POTENTIAL

     To evaluate the potential production of abatement acid from power plants
in the existing S market, the marketing model must be designed to accommodate
the byproduct acid from smelters.  They are already established in the acid
market.
     The present technology assumes that the production of byproduct
to control S02 emissions in smelter operations represents the best available
technology.  Since the law requires S02 control, the smelter operator is

                                     37

-------
faced with the option of either marketing the surplus acid  that cannot  be
used in leaching operations or neutralizing the acid to form a waste  product
that is acceptable to the environment.  This means that a cost equivalent to
the cost of neutralizing the acid could theoretically be invested  in  marketing
the acid.  A discussion including cost estimates for byproduct l^SO^  produc-
tion from smelter gases including estimates of retrofit tail gas cleanup  and
limestone neutralization is presented in Appendix H.  In the model it is_
assumed that the value of the byproduct acid is zero at the plant  site.

     Using a 1975 base period, it was assumed that existing S-burning acid
plants and byproduct acid plants operating at smelter locations were  operating
at  an equilibrium position in the market place.  The incremental acid that
is  projected to be produced at both existing and new smelter locations  in
1978 is assumed to be in direct competition with abatement  acid that  could be
produced by a steam plant at a given location.

     The 14 smelters located in the 11 Western States were  analyzed separately
from the 14 smelters in the 37 Eastern States of the U.S.   Each smelter that
was identified as being out of compliance by the EPA compliance data  system
in  September 1976 was assumed to be equipped with control equipment by  1978
that increased capacity by 16% compared to 1975.  Plants in compliance were
assumed to increase their capacity factor by 10% in 1978 and new plants are
assumed to operate at 60% capacity (100% = 330 days/yr).  The geographic
location of the plants considered in this analysis are outlined in Figure 7.
The 1978 incremental production estimated for the Western States amounted to
849,000 tons I^SO^.  The analysis for the smelters located  in the  Eastern
States amounted to 811,000 tons of acid.  This analysis is  presented  in
Table 13.

     The avoidable costs of production were calculated for each of  the 14
acid plants located in the 11 Western States.   This analysis assumed the use
of  recovered S from western Canada at $25/ton f.o.b.  Calgary,  Alberta, Canada,
delivered by rail to each acid plant considered.   The results  of these
calculations are presented in graphic form in Figure 8 as a demand curve for
abatement acid for the Western States.   The interpretation of  this demand
curve is similar to the demand curve presented in Figure 6.   Assuming a zero
value for the smelter acid only one smelter location at Hayden, Arizona,
could deliver byproduct acid equal to or below the avoidable cost  of produc-
tion at an acid plant located at Helm,  California.   This accommodated the
marketing of 111,000 tons of byproduct smelter acid in the Western States.
This left a balance of 738,000 tons to be marketed in the Eastern  States.

     The strategy for marketing the western surplus smelter acid in the
eastern market involves the use of transshipment terminals  supplied by unit
trains.  Rail rates for unit train shipments are shown in Appendix I.  The
value of the acid at the transshipment terminal was assumed to be  equal to
the rail rate plus $1.5G/ton terminal handling charge.  The terminal  locations
selected were:  Chicago, Illinois; St.  Louis,  Missouri; Memphis, Tennessee;
Baton Rouge, Louisiana; and Houston, Texas.  Two additional transshipment
terminals were added in the model at Buffalo,  New York, and Detroit, Michigan,
in  order to analyze the marketing of 200,000 tons of byproduct acid from
smelters in Canada.  This concept is presented graphically  in Figure  9.   The
storage cost analysis is presented in Appendix F.

                                     38

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                                                         X   \
                                   A NONFERROUS SMELTER
Figure 7.   Geographic distribution of smelter byproduct  acid  plants
            in 37 Eastern States and 11 Western States.

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TABLE 13.  INCREMENTAL H2SOA PRODUCTION FOR EASTERN AND WESTERN SMELTERS




                                1976-1978
Existing
Capacity,
State ktons
Missouri
Tennessee
Pennsylvania
Iowa
Oklahoma
Texas
Ohio
Total
1978 increased
production factor
1978 increased
production
Total 1978 increased
production estimate
Arizona
New Mexico
Montana
Idaho
Utah
Washington
Total
1978 increased
production factor
1978 increased
production
Total 1978 increased
production estimate
760
1,250
579
100
91
286
20
3,086






2,284
780
330
250
600
50
4,294






In
compliance
190
-
-
-
91
160
20
461

0.10

46


2,284
-
-
-
-
-
2,284

0.10

228


Out of
compliance New
90 480
1,250
500 79
100
- -
126

1,840 785

0.16 0.60

294 471

811

200 580
230 100
250
600
50
1,330 680

0.16 0.60

213 408

849
                                  40

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-tA>-
             500      1000    1500     2000    2500     3000   3500

          CUMULATIVE  ANNUAL  CAPACITY, 1000 TONS  100% H2S04
          Figure 8.   Abatement byproduct I^SO^ demand curve
                         (Western States).
                                 41

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                                     • DEMAND POINT
                                     A TRANSSHIPMENT TERMINAL
                                     O ORIGIN OF BYPRODUCT
                                       SMELTER ACID
Figure 9.   Geographic  distribution of assumed supply and demand  for western
                 and Canadian acid in zero ACFL model run.

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     In the marketing model, the seven transshipment terminals  (listed above)
are handled as simulated smelter-producing locations that can compete in the
market with the 14 eastern smelters and the 187 power plants that are candi-
dates for production of t^SO^.  The results of the model runs are presented
in a later section.
                                     43

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                   S02 EMISSION REGULATIONS AND APPLICATIONS


     With the passage of the Clean Air Act Amendments of 1970, EPA was given
the responsibility and authority to regulate and control air pollution in the
U.S. and its territories.  Among other responsibilities, the Clean Air Act
required EPA to put into effect National Ambient Air Quality Standards (NAAQS)
for pollutants which adversely affect public health and welfare, including
S02, nitrogen dioxide (N02),  particulate matter, carbon monoxide (CO), hydro-
carbons, and photochemical oxidants.
SIP

     The Clean Air Act required each state to adopt and submit to EPA an
acceptable plan for attaining, maintaining, and enforcing NAAQS in all regions
of the state.  These SIP prescribed emission limiting regulations, timetables
for compliance with the limitations, and measures required to ensure attain-
ment of the standards.  Unacceptable plans were returned to the states for
revision or, in some cases, substitute regulations were established by EPA.
While the primary responsibility for enforcing SIP regulations rests with the
individual states, EPA is responsible for assuring that all implementation
plan requirements are fulfilled.  As a result, EPA provides technical and
legal assistance to the states in enforcing SIP regulations.  If any state
fails to enforce its implementation plan regulations, the Federal Government
may take legal actions against the noncomplying sources.

     Following initial approval of most SIP in 1972, many states began
submitting to EPA revisions to their implementation plan, many of which alter
the emission limitations.  Usually, these revisions are based on additional
air quality measurement data or on a more detailed technical analysis of air
pollution control strategies.  When approved by EPA, these revisions become a
part of the implementation plan.


FEDERAL NSPS

     In addition to the SIP limitations, emissions from certain sources are
restricted further by NSPS.

     The purpose of these standards is to prevent the occurrences of new air
pollution problems, encourage improvements in emission control technology, and
provide a mechanism for controlling pollutants which EPA suspects are hazardous,
but for which insufficient information is available to regulate under other
provisions of the Act.
                                      45

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     The standards are applicable to newly  constructed  facilities,  new
equipment additions to existing facilities,  and  existing  equipment  which is
modified in such a way that an increase of  pollutant  emissions  occurs.   NSPS
is in most cases more stringent than SIP.
TRENDS IN ESTABLISHING SIP

     Over the past few years, much attention has  been focused on emission
regulations  for SOX since these regulations impact the supply  of  fuel,
particularly coal, which can be burned to produce electrical energy.
While  U.S. supplies of coal are plentiful,  some of  this  coal  is too high in
S  content to be burned in compliance with  State and  Federal regulations for
S02 without  the use of emission reduction  systems, which,  in  some cases, are
either costly or  impractical.  As a result, many  states  have  been reevaluating
 their  S02 regulations to ensure that scarce low-S fuels  are being required
 only in areas where they are  needed to protect public health.   In some cases,
 states have  revised their S emission regulations  to  allow  the burning of higher
 S  fuels in less polluted areas where they  can be  burned  without violating
 ambient air  quality standards.


 EMISSION CONTROL  REGULATIONS  FOR  FOSSIL-FIRED POWER GENERATORS

 Units of the Regulation

      NSPS contains distinct regulations  which limit  the  emission of particu-
 lates and S02 from individual fossil-fired boilers  as shown below:

                                         Allowable emission,
                                  	Ib/MBtu  heat input	
                                   Coal-fired unit   Oil-fired unit

              Particulate matter         0.1               0.1
              S02                        1.2               0.8

      This regulation is applicable to boilers for which construction or
 modification was begun after August 17,  1971.

      In contrast to NSPS regulations, there are variations in (1) the units of
 measure in which SIP regulations for existing plants are expressed, (2) the
 equipment (boiler, stack, or entire plant)  to which the regulations apply, and
 (3) the value of the regulation.  Table  14  shows the units in which SIP
 regulations are expressed.

      Some states control all emission sources equally, while other states
 prescribe different emission limits for  sources according to the fuel used,
 the geographic location, the size of the source, or the type of source (e.g.,
 power plant or other combustion units).
                                      46

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       TABLE 14.   UNITS FOR EXPRESSING STATE S02 EMISSION REGULATIONS (26)
                    1.   % S for all fuels
                    2.   % S for each fuel
                    3.   Lb S02/MBtu for all fuels
                    4.   Lb S02/MBtu for each fuel
                    5.   Lb S/MBtu for all fuels
                    6.   Lb S/MBtu for each fuel
                    7.   Ppm S02 in exhaust gas
                    8.   Impact on ambient air quality in ppm
                    9.   Lb S02/hr


     The most common regulation for controlling S02 emissions is by either
limiting the amount of S or S02 emitted per unit heat input (Ib S/MBtu, Ib
S02/MBtu) or limiting the S content of the fuel (% S).  However, other S02
regulations limit S02 emission concentrations expressed as parts of SC>2 per
million parts of volume of stack gas (ppm SC^) or limit the amount of S02
emitted per hour (Ib S02/hr).  Some states or regions specify ambient air
quality regulations only (i.e., no specific emission limit for a source).
Other methods of limiting S02 emissions which appear in the SIP include re-
quiring a percent control of input S (% control) and requiring applica-
tion of "latest reasonably available control technology" or "new proven
technologies."

     Some of the above-mentioned methods for regulating SC>2  control the
emissions of SOX more directly than do others, and each method has different
implications regarding fuels that can be legally burned.

     A detailed discussion of the effect of different applications of the SIP
regulations on degree of S02 removal is included in State Implementation
Plan Emission Regulations for Sulfur Oxides; Fuel Combustion (EPA-450/2-76-
002, March 1976)(267!~

Application of the Regulations

     Besides the various units of measure used regulations also vary as to the
equipment upon which the emission limit is enforced.  Twenty-five states or
territories enforce their regulations on a boiler basis, 13 on a stack basis,
and 18 on a total plant basis  (all boilers collectively).  In considering
compliance with a regulation, this information determines whether a source is
allowed to average its emission over all boilers (or stacks) or if each
boiler (or stack) must comply with the regulation.

     About one-third of the states regulate specific fuel types.  These
regulations usually control oil-fired sources more strictly than coal-fired
sources since, in general, oil contains less S and has  a higher heat content
than does coal.  But, in some cases, the S restriction  for coal is more
stringent than the restriction for oil to prohibit the  use of coal without
flue gas cleaning equipment.


                                      47

-------
     About half of the states have specific S02 regulations for various
geographic areas within the state.  These geographic areas might be specified
as cities, counties, Federal Air Quality Control Regions (AQCR), Standard
Metropolitan Statistical Areas (SMSA), or some locally defined geographic
region.  In some areas, including Arizona, New Mexico, and Puerto Rico,
regulations have been promulgated which apply to specific plants.

     In about one-third of the states, the size of the source determines
whether or not  the  source must comply with an S02 emission limitation  and  if
so, the stringency  of  the limitation.  In most cases, source size is defined
by the heat input rate measured in MBtu/hr.  Other methods of defining source
size include Ib steam/hr generated and emission potential in tons S02/yr
emitted.  In some states, emission limit is determined by the heat input range
under which a source falls.  In these states, larger sources usually are
controlled more stringently than smaller sources.

     Over half  of the  states use more than one of the parameters discussed
above  in  their  regulations.  In addition, about 35% of the states have
separate  regulations for new sources and about 10% have regulations for
existing  sources that become more stringent over time.

     In a few states,  the limits on emissions or fuel quality are specified as
maximum values  averaged over a given time period.  Most regulations, however,
state  that emissions or S content shall not exceed a maximum value.  This
phraseology implies that instantaneous compliance with the limit is required.
EMISSION COMPLIANCE ALTERNATIVES

     Several methods for reducing S02 emissions for compliance with State or
Federal emission regulations are considered in this study.  Alternative
strategies considered for power plants include:

   Use of low-S coal
   Limestone scrubbing with ponding of sludge
   Magnesia  (MgO) scrubbing with H2S04 production

     It is assumed that H2S04 plants and smelters which are out of compliance
will reduce their emission by producing
     The major objectives of this study are to determine the potential for
production of byproduct H2S04, in meeting S02 emission regulations and the
impact of their recovery and sale on S-I^SO^ industry supply-distribution
characteristics.  In all cases, the S02 control strategy is selected on the
basis of minimum costs for compliance.
                                      48

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               CHARACTERISTICS OF THE POWER UTILITY INDUSTRY
     In the power industry, either fossil or nuclear fuel is supplied to a
boiler and the heat energy of the fuel is used to generate steam.  The steam
generated in the boilers is fed to steam turbines which drive generators for
producing electricity.  Fossil fuel is a general term which refers to either
coal, oil, or natural gas.  Most coal and oil contain S that is emitted as
S02 in the stack gas when the fuel is burned.  Natural gas may contain some
S, but in relatively small amounts.  Nuclear fuels do not contain S and are
not consumed in the same manner as fossil fuels; therefore, their use does
not result in the emission of S02-  In presenting characteristics of the power
industry below, emphasis is placed on fossil-fired plants which use coal, oil,
or natural gas to generate steam.

     Detailed information related to the characteristics of the steam-
electric utility industry is found in  Steam-Electric Plant Construction Cost
and Annual Production Expenses  (FPC S-250)  (27) and  Steam-Electric Plant
Air and Water Quality Control Data  (FPC S-253)  (2).   Key information given
in these publications is included below to characterize the utility  industry.
FOSSIL FUELS

     During the decade prior to 1967, approximately 66% of the total annual
fossil-fueled power generation was by coal, about 26% by natural gas, and
the remaining 8% by residual oil.  During the second half of the past decade,
when restrictions on the importation of residual oil were removed on the
east coast, foreign residual oil began to compete favorably with other fuels.
Electric utilities, particularly those near deepwater ports, started to
convert from coal to oil and to build new oil-fired units.  This process was
accelerated with the setting forth of strict S02 emission control regulations.
With the growing shortage in the supply of natural gas, the use of desulfu-
rized or naturally low-S oil offered the most viable solution to the S02
pollution problem along the entire east coast.

     A large proportion of the oil used by electric utilities, particularly
along the eastern seaboard, is of foreign origin.  In the 1965-72 period,
approximately 398 coal-fired generating units were converted to the use of
oil.  Economic considerations dictated the conversions initially.  More
recently, however, the paramount reason for converting to oil has been the
requirement to meet strict S emission regulations which the utilities were
unable to do using coal.  Most of the conversions took place on the east
coast at plants with easy access to ocean and river barge transport of lower
priced, desulfurized, or naturally low-S imported residual oil.  The Arab
                                     49

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oil embargo in late 1973 was instrumental in effecting arbitrary and sudden
huge price increases in the world price of oil.  In a relatively short period
of time, the economic advantage of using imported oil versus coal as a fuel
for electric power generation reversed.  In early 1974 a number of utilities
on the east coast reported 42 oil-burning plants of their systems capacities
as having capability of conversion from oil to coal.  A few of these plants
have been converted to coal, with conversion by the others contingent upon
coal availability.  Due to current uncertainties in the long-range oil supply
picture, and the increasing amounts of nuclear generation becoming available
to electric utilities, oil's role in electric generation will probably decline
in the  future.

Historical Consumption and Characteristics

     The historical consumption pattern of coal, natural gas, and oil in  the
U.S. from  1969  through 1973 based on FPC Form 67 data is shown in Table 15.
Historical characteristics of coal, oil, and gas for the corresponding period
are  given  in Table 16.  The data indicate that the average heating value  of
coal,  fuel oil, and gas has declined slightly during this period.  The data
also show  a slight decline in the average S content of coal and a significant
decline in the  average S  content of oil.  The lower heating values of coal
and  fuel oil appear to be at the expense of using fuels with lower S contents.
The  average ash content of coal during the same period increased from approxi-
mately 12.5 to  13.3%.
               TABLE 15.   CONSUMPTION PATTERN OF FOSSIL FUELS
                          IN  THE U.S.,  1969-73  (2)
                         Total Btu,  10
                                      15
                                     of total Btu
           Year
Coal
Oil
Gas
Total   Coal   Oil
Gas
1969
1970
1971
1972
1973
7.065
7.098
7.244
7.794
8.583
1.577
2.008
2.328
2.816
3.270
3.429
3.820
3.841
3.811
3.517
12.071
12.926
13.413
14.421
15.370
58.5
54.9
54.0
53.9
55.8
13.1
15.5
17.4
19.6
21.3
28.4
29.6
28.6
26.5
22.9
                                      50

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TABLE 16.  HISTORICAL FOSSIL FUEL CHARACTERISTICS  FOR THE  PERIOD  1969-73  (2)


                                                    Year
                                1969	1970	1971	1972	1973

Coal

Average heating value,
 Btu/lb                        11,628     11,276     11,169     11,176     11,090
Average S content, % by wt       2.59       2.58       2.47       2.39       2.32
Equivalent S02 content,
 Ib S02/MBtu                     4.46       4.58       4.42       4.28       4.27
Average ash content, % by wt    12.53      13.72      13.85      13.41      13.29


Fuel Oil

Average heating value,
 Btu/gal                       148,727    147,991    147,017    146,285    145,772
Average S content, % by wt       1.68       1.52       1.28       1.07       0.98
Equivalent S02 content,
 Ib S02/MBtu                     1.80       1.64       1.40       1.18       1.08


Gas

Average heating value,
 Btu/ft3                        1,033      1,031      1,030      1,028      1,028
 Projected 1978 Consumption and  Characteristics

     In 1973 utilities were also  requested  by FPC  to  project  fuel  consumption
 and characteristics for 1978.   The majority of  utilities  provided  FPC with
 these projections.  For the utilities which did not^project this information,
 fuel consumption and characteristics were assumed  to  be the same as  that
 reported for 1973.  Based on  the  updated projections,  Table 17  shows the  con-
 sumption rates and characteristics of fossil fuels projected  to be utilized
 during 1978.  For plants which  use multiple fuels  and did not project their
 1978 consumption, the method  for  projecting fuel is discussed in Appendix J.

     A comparison of the total  projected 1978 coal, fuel  oil, and  gas con-
 sumption with the historical  1973 fuel  consumption by region  is shown in
 Table 18.  Figure 10 shows the  overall  trend in fossil fuel consumption from
 1969 through 1978.  The projections indicate a  general increase in the con-
 sumption of coal and oil, but a slight  decrease in the consumption of gas.
 The regional increases or decreases are primarily  influenced  by fuel avail-
 ability and price.  In reviewing  the data,  it must be remembered that a
 significant amount of new generating capacity between 1973 and  1978  is from
 nuclear units.  The data shown  include  the  effect  of  projected  decreases  in
 fossil fuel utilization as a  result of  new  nuclear units  coming online as well
 as changes in fossil fuel consumption resulting from  decreases  in  fuel avail-
 ability or increases in cost.
                                      51

-------
    16.0
    14.0
     12.0
                               TOTAL,
in
 O   10.0
 x
 t/i
 =   8.0
 CD
  COAL
     6.0
     4.0
                               GAS
      2.0
   OIL
                   I
I
                 1969      1970
         I97i
         YEAR
1972      1973      1978
                Figure 10.  Trends in the consumption of coal,
                         oil, and gas from 1969-78.
                                     52

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 TABLE  17.   PROJECTED 1978 FOSSIL FUEL CONSUMPTION RATES AND CHARACTERISTICS
                                               All plants
              Plants out
            of compliance
       Coal
         Total consumption
           ktons
           GBtu
         Heating value,  Btu/lb
         S content,  % by wt
         Equivalent  S02  content, Ib S02/MBtu
       Oil
         Total consumption
           kbbl
           GBtu
         Heating value,  Btu/gal
         S content,  % by wt
         Equivalent  S02  content, Ib S02/MBtu
       Gas
         Total consumption
           Mft3
           GBtu
         Heating value,  Btu/ft3
   475,570
10,408,290
    10,943
      2.12
      3.87
   620,247
 3,827,427
   146,924
      0.99
      1.08
 2,556,021
 2,602,232
     1,018
  226,780
5,125,075
   11,300
     2.81
     4.97
  110,167
  686,900
  148,454
     1.42
     1.54
  108,239
  116,968
    1,081
POWER PLANT CHARACTERISTICS

Plant Location

     The location of major coal-, oil-, and gas-fired power plants based on
1973 FPC data is shown in Figures 11 through 13 respectively.  Figure 14
shows the location of plants which use multiple fuel mixes for the same
period.  The data show coal-fired plants to be scattered from the east to
the west coast.  The highest concentration of coal-fired plants is in the
Midwest.  Oil-fired power plants are most predominant along the east and west
coasts and the lower Mississippi Valley; however, they are also found at
other scattered locations in the Midwestern States.  Gas-fired plants are
predominant near the Louisiana and Texas Gulf Coast and adjacent states, but
like oil-fired plants, are also found at other locations.  At the end of 1973,
plants with facilities for using multiple fuels were widely scattered.

Plant Size

     Historical data for conventional fossil-fueled steam-electric generating
plants for the total power industry are shown in Table 19.  An analysis of
these data indicates that total fossil-fueled power generation has generally
doubled every 10 yr.  New plants are constructed to (1) provide additional
capacity for the increasing electrical demand and  (2) provide replacement
capacity for older less-efficient plants which are being retired.  The total
                                     53

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 TABLE 18.   COMPARISON OF PROJECTED 1978 REGIONAL FOSSIL

     FUEL CONSUMPTION WITH HISTORICAL 1973 CONSUMPTION
  Geographic                   Coal,      Oil,       Gas,
    regiona	ktons	kbbl	Mft3

Historical 1973 consumption (2)

New England                     1,080     82,930       6,070
Middle Atlantic                44,990    144,690      64,730
East North Central            135,960     23,340     105,590
West North Central             31,620      3,440     352,820
South Atlantic                 75,860    141,380     202,660
East South Central             63,060      6,510      73,750
West South Central              4,730     20,850   1,957,070
Mountain                       23,930      8,990     207,630
Pacific                         3,740     76,970     451,220

     U.S. total               386,970    509,100   3,421,540

Projected 1978 consumption

     U.S. total               475,570    620,250   2,556,020

a.  The states included in each geographic region are:
    New England - Connecticut, Maine, Massachusetts, New
    Hampshire, Rhode Island, Vermont; Middle Atlantic -
    New Jersey, New York, Pennsylvania; East North Central -
    Illinois, Indiana, Michigan, Ohio, Wisconsin; West
    North Central - Iowa, Kansas, Minnesota, Missouri,
    Nebraska, North Dakota, South Dakota; South Atlantic -
    Delaware, District of Columbia, Florida, Georgia,
    Maryland, North Carolina, South Carolina, Virginia,
    West Virginia; East South Central - Alabama, Kentucky,
    Mississippi, Tennessee; West South Central - Arkansas,
    Louisiana, Oklahoma, Texas; Mountain - Arizona,
    Colorado, Idaho, Montana, Nevada, New Mexico, Utah,
    Wyoming; Pacific - California, Oregon, Washington.
b.  Regional consumption data not available.
                         54

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Ul
Ul
    •  Coal users
                         Figure 11.  Location of coal-fired steam-electric power plants  (1978)

-------
D Oil users
               Figure 12.  Location of oil-fired steam-electric power plants  (1978)

-------
Gas users
             Figure 13.  Location of gas-fired steam-electric power plants (1978).

-------
00
          Combination users
                           Figure 14.   Location of steam-electric power plants capable of
                                     utilizing a combination of fossil fuels.

-------
 installed  steam-electric generating capacity from fossil-fueled plants
 increased  from 26,000 MW in 1938 to over 318,000 MW in 1973.  During the same
 period,  average plant size in megawatts increased from 22 to 322.  The total
 number of  plants varies annually as new plants are built and old plants are
 retired.   At  the end of 1973, there were 219 fossil-fueled plants 500 MW in
 size  or  larger.


      TABLE 19.  CONVENTIONAL FOSSIL-FUELED STEAM-ELECTRIC GENERATING

  PLANTS, TOTAL AND AVERAGE CAPACITIES, NET GENERATION AND CAPACITY FACTORS

                 FOR THE TOTAL POWER INDUSTRY, 1938-73a'b (27)


                 1938     1947     1957	1967	1971	1972	1973

Number of
 plants           1,165    1,045    1,039       971       985       979       988
Installed
 capacity,  MW    26,066   36,035   99,500   210,237   275,593   294,049   318,357
Average plant
 size, MW           22       35       96       217       280       300       322
Net generation,
 GkWh             68.4    174.5    497.2     974.1   1,282.2   1,378.3   1,459.2
Approximate
 average  annual
 plant factor, %    35       55       57        53        53        54        52

                                  *
a.  Excludes Puerto Rico.
b.  Excludes nuclear, geothermal, gas turbine, and internal combustion plants.


      Most  power plants consist of a number of separate units which are capable
 of producing  power independently of the other units within the plant.  Each
 unit generally includes a separate boiler for generating steam, a separate
 turbine  and generator for producing electricity, and separate flue gas han-
 dling facilities.  Although some plants have common flue gas stacks for
 multiple boilers, most boilers are designed with separate stacks.  Modular
 units allow for servicing and maintenance without significantly affecting the
 output of  the overall plant and allows for the addition of new generating
 capacity without intefering with the operation of the existing facilities.

      A diagram showing the general layout of a plant, including facilities
 for S02  control, is shown in Figure 15.  This diagram illustrates the relation-
 ships between plant, boilers, and stacks, and facilities for controlling S02
 emissions.
                                      59

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SULFUR,
SCRUBBER, SUALrF,UDRIC
SLURRY OR WASTE
DISPOSAL
FACILITIES
BYPRODUCT
RAW MATERIAL
FACILITIES

Figure 15.  General layout of a power plant designed with an FGD system.

-------
BOILER CHARACTERISTICS

Boiler Size

     As an illustration of the size relationship between plants and boilers,
Table 20 identifies the total plant size in megawatts and the number of
separate units for the 15 largest steam-electric plants in the U.S. based on
1973 FPC data.  These plants range in size from 1872-2933 MW.  For comparison,
individual boiler sizes at these plants range from 69-1300 MW.
           TABLE 20.   FIFTEEN LARGEST STEAM-ELECTRIC PLANTS IN THE

                             U.S.  IN 1973a  (27)
           Plant name
MW
Unit
Utility
Amos
Paradise
Labadie
Monroe
Sammis
Robinson, P.H.

Four Corners

Moss Landing

Alamitos

Pittsburg

Marshall
Widows Creek
Nine Mile
Point
St. Clair
Keystone

a. Coal-fired
2,933
2,558
2,482
2,462
2,456
2,315

2,270

2,175

2,121

2,029

2,000
1,978
1,917

1,905
1,872

except as
3
3
4
3
7
4

5

7

6

7

4
8
5

7
2

noted,
b . Based on maximum generator
Appalachian Power Company
Tennessee Valley Authority
Union Electric Company
Detroit Edison Company
Ohio Edison Company
Houston Lighting and Power
Company
Arizona Public Service
Company
Pacific Gas and Electric
Company
Southern California Edison
Company
Pacific Gas and Electric
Company
Duke Power Company
Tennessee Valley Authority
Louisiana Power and Light
Company
Detroit Edison Company
Pennsylvania Power and
Light Company

ratings.
                                     61

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     The average size of larger boilers (>300 MW) placed in service has  gener-
ally increased over the years.  Table 21 shows the number of units, corres-
ponding total megawatts, and the average unit size in megawatts for units
placed in service during the period 1959-73.
               TABLE 21.  TRENDS IN BOILER SIZE, 1959-73 (27)


                      Fossil-fueled units, 300 MW and larger
                         No. units
                         placed in    Total    Average unit
                Year      service      MW        size, MW
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
5
8
9
7
10
10
17
20a
26
22
26
25
29
32
35
1,800
2,525
3,180
2,525
4,500
3,625
7,740
8,424
13,245
12,274
14,249
14,413
17,575
18,753
21,843
360
317
353
361
450
362
455
421
509
558
548
577
606
586
624
                   Total   281
                146,671
522
                a.
Seven of these units were actually
installed in prior years and were
rerated in 1966.
     For comparison with the size ranges  given above,  the average boiler size
considering all boilers projected to be operational  in 1978  is' 122 MW and the
average boiler size for plants which are  projected to  be  out of compliance
in 1978 is 159 MW.   In contrast,  the largest  commercial boilers presently in
operation or under  construction are  1300-MW units.
                                    62

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 Boiler  Capacity Factors

      The  data given in Table 19 indicate that average annual capacity factors
 for power plants ranged from approximately 52-57% of rated capacity for the
 period  1947-73.   In contrast, however, capacity factors for individual boilers
 within  a  plant vary considerably.   As new units are added, load factors for
 the older units are generally decreased and the newer, more efficient units
 are operated at higher capacity factors.  However, delays in construction of
 new generating capacity often require older plants to operate at higher than
 normal  capacity factors.   Based on historical FPC data for 1969-73, the
 average annual capacity factors for all boilers as a function of boiler age
 were determined and are shown in Figure 16.  The data indicate a gradual
 increase  in capacity factors from approximately 50 to 65% during the first
 10 yr of  operation followed by a relatively constant profile for approxi-
 mately  5-7 yr and a gradually declining operating profile over the remaining
 life of the plant.  Boilers >20 yr old generally operate at annual capacity
 factors <50%.  A breakdown of the projected 1978 distribution of all boilers
 by age  and capacity factor is shown in Table 22.  Table 23 shows the distri-
 bution  for these boilers projected to be out of compliance.


  TABLE  22.  DISTRIBUTION OF BOILERS BY AGE AND CAPACITY FACTOR - ALL BOILERS
                Number of boilers and (% of total number of boilers)
Boiler capacity factor
Boiler
age, yr
0-5
6-10
11-15
16-30
>30
Total

28
30
20
265
1,009
1,352
<20%
( 0.8%)
( 0.9%)
( 0.6%)
( 7.9%)
(29.8%)
(40.0%)
20-40%
26
34
45
410
154
669
( 0.8%)
( 1.0%)
( 1.3%)
(12.1%)
( 4.6%)
(19.8%)
41-60%
84
92
73
465
61
775
( 2
( 2
( 2
(13
( 1
(22
.5%)
.7%)
.2%)
.7%)
.8%)
.9%)
40
127
120
274
25
586
>60%
( 1.2%)
( 3.8%)
( 3.5%)
( 8.1%)
( 0.7%)
(17.3%)
Total
178
283
258
1,414
1,249
3,382
( 5.3%)
( 8.4%)
( 7.6%)
(41.8%)
(36.9%)
( 100%)

     Boiler capacity factors also vary as a function of boiler size.  Larger
boilers are often operated as base load plants while the older, generally
smaller and less-efficient boilers are operated to provide peaking capacity.
Table 24 shows a breakdown of the projected 1978 distribution of all boilers
by size and capacity factor.  Table 25 shows the distribution for these
boilers projected to be out of compliance.

     Capacity factors are also a function of fuel type; however, plant design
is the primary consideration which affects the consumption-distribution
pattern.  For plants which are capable of burning alternate fuels, the utili-
zation trend changes as a function of fuel availability and costs.
                                      63
                                       X

-------
  80
         ALL BOILERS AVERAGE CAPACITY FACTOR  vs. BOILER AGE-

                      BASED ON 1969-1973  FPC DATA
















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                            BOILER AGE-YEARS
       Figure 16.  Average boiler capacity factors as a function

                          of boiler age.
                                  64

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        TABLE 23.   DISTRIBUTION OF BOILERS BY AGE AND CAPACITY FACTOR -

                          BOILERS OUT OF COMPLIANCE


Boiler
age, yr
0-5
6-10
11-15
16-30
>30
Total

Number
of boilers and (% of total number of boilers)
Boiler capacity factor

5
9
4
56
216
290
<20%
( 0.6%)
( 1.1%)
( 0.5%)
( 6.7%)
(25.9%)
(34.8%)
20-40%
8
5
5
90
38
146
( 1.0%)
( 0.6%)
( 0.6%)
(10.8%)
( 4.6%)
(17.6%)
41-60%
49
26
16
135
13
239
( 5
( 3
( 1
(16
( 1
(28
.9%)
.1%)
.9%)
.2%)
.6%)
.7%)
19
45
26
66
2
158
>60%
( 2.3%)
( 5.4%)
( 3.1%)
( 7.9%)
( 0.2%)
(18.9%)
Total
81
85
51
347
269
833
( 9.8%)
(10.2%)
( 6.1%)
(41.6%)
(32.3%)
( 100%)

       TABLE 24.  DISTRIBUTION OF BOILERS BY SIZE AND CAPACITY FACTOR -

                                 ALL BOILERS
 Boiler
size,  MW
        Number of boilers and (% of total number of boilers)
       	Boiler capacity factor	
    <20%
  20-40%
  41-60%
    >60%
   Total
 <200
200-500
501-1000
 >1000
1,270 (37.6%)
   53 ( 1.6%)
   29 ( 0.8%)
    0 ( 0.0%)
601 (17.8%)
 45 ( 1.3%)
 21 ( 0.6%)
  2 ( 0.1%)
510 (15.1%)
180 ( 5.3%)
 79 ( 2.3%)
  6 ( 0.2%)
390 (11.5%)
120 ( 3.5%)
 76 ( 2.3%)
  0 ( 0.0%)
2,771 (82.0%)
  398 (11.7%)
  205 ( 6.1%)
    8 ( 0.2%)
  Total    1,352 (40.0%)   669 (19.8%)   775  (22.9%)    586  (17.3%)    3,382  ( 100%)
                                       65

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       TABLE 25.  DISTRIBUTION OF BOILERS BY SIZE AND CAPACITY FACTOR  -

                          BOILERS OUT OF COMPLIANCE
 Boiler
size, MW
       Number of boilers and (% of total number of boilers)
                      Boiler capacity factor	
   <20%
  20-40%
  41-60%
  >60%
                                                          Total
  <200
200-500
501-1000
 >1000
283 (34.0%)
  7 ( 0.8%)
  0 ( 0.0%)
  0 ( 0.0%)
129 (15.5%)
 12 ( 1.4%)
  5 ( 0.6%)
  0 ( 0.0%)
129 (15.5%)
 69 ( 8.3%)
 36 ( 4.3%)
  5 ( 0.6%)
87 (10.4%)
38 ( 4.6%)
33 ( 4.0%)
 0 ( 0.0%)
628 (75.4%)
126 (15.1%)
 74 ( 8.9%)
  5 ( 0.6%)
  Total    290 (34.8%)   146 (17.5%)   239 (28.7%)   158 (19.0%)   833  ( 100%)
Boiler Heat Rates

     Because heating values of fossil fuels vary over a wide range, the thermal
efficiency of fossil fuel steam-electric power plants is generally expressed
in terms of heat rate.  Heat rate is defined as the'total Btu of heat required
to generate 1 kWh of electricity for delivery to the transmission system.
These data are reported annually to FPC at the utility, plant, and boiler level.
Table 26 shows historical national average heat rates for fossil-fueled power
plants from 1938-73.  This table also shows the thermal efficiency for con-
verting heat energy into electricity, which is calculated by dividing the
thermal equivalent of 1 kWh (3413 Btu) by the heat rate.  As shown, national
average heat rates have declined from a high of 16,500 Btu/kWh in 1938 to about
10,400 Btu/kWh in 1972-73.

     According to the FPC data, there were 14 units in 1973 with heat rates of
<9000 Btu/kWh compared with 18 units in 1972.  The most efficient single unit
had a heat rate of 8714 Btu/kWh in 1973.   Corresponding to 1973, there was a
total of 41 plants with overall heat rates of <9,500 Btu/kWh, and 124 plants
with heat rates under 10,000 Btu/kWh.  These totals account for 19 and 45% of
the total electrical generation respectively.  The most efficient single plant
had an average heat rate of 8818 Btu/kWh.   Based on projections to 1978, plant
heat rates range from 8,818 to >30,000 Btu/kWh.

     The most efficient heat rate at the company level was reported as 9524
Btu/kWh.  In 1973 there was a total of 16 utilities with heat rates <10,000
Btu/kWh.
                                      66

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TABLE 26.  NATIONAL AVERAGE HEAT RATES FOR FOSSIL-FUELED STEAM-




 ELECTRIC PLANTS - TOTAL ELECTRIC POWER INDUSTRY, 1938-73 (27)

Year
1938
1948
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
Btu/net
kWh
16,500
15,738
13,361
12,889
12,180
11,699
11,456
11,365
11,085
10,970
10,760
10,650
Thermal
efficiency,3
%
20.68
21.69
25.54
26.48
28.02
29.17
29.79
30.03
30.79
31.11
31.72
32.05
Year
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Btu/net
kWh
10,558
10,482
10,462
10,453
10,415
10,432
10,398
10,447
10,494
10,478
10,379
10,389
Thermal
efficiency,3
%
32.33
32.56
32.62
32.65
32.77
32.72
32.82
32.67
32.52
32.57
32.88
32.85

 a.  Based  on  3,413  Btu as the energy equivalent of 1 kWh.
                              67

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                           SCRUBBING COST GENERATOR
     Each utility is required by law to report annually plant, boiler, and
fuel characteristics for their steam-electric generators on FPC Form 67.  A
file containing FPC Form 67 data for the period 1969-73 was supplied to TVA
along with utility projections, where available, of similar data for 1978 for
use in the byproduct marketing study.  The data were primarily for use in
projecting S02 emissions at power plants for determining the compliance status
of power plants with State and Federal S0£ emission regulations and the market
potential for S and 8(2804 abatement production at plants which are out of
compliance.

     TVA developed a procedure for using the Form 67 data in conjunction with
applicable S02 emission regulations to (1) project the compliance status of
individual plants and the quantity of S which must be recovered to meet SC>2
emission regulations for those plants out of compliance, (2) estimate costs
for removing the required amount of S02 from the gas to meet compliance
requirements by three alternative scrubbing processes, and (3) compare the
costs for scrubbing including credit from sale of byproducts with alternative
costs for complying with the regulation by the use of low-S coal.  The overall
comparison is used to assist in selecting the minimum cost compliance alter-
native.   Discussions of the data required for input to the scrubbing cost
generator and the method for developing the model are given below.


PROCEDURE FOR UTILIZING FPC DATA TO ESTIMATE COMPLIANCE STATUS

FPC Form 67 Data Projections

     The projected 1978 FPC Form 67 data which serve as input to both the SC>2
emission and compliance model and the scrubber cost generator include a number
of key data items which were reported to FPC at the plant level only.  In the
compliance tests and the scrubber cost generator the majority of the calcula-
tions are begun at the boiler level; therefore, it was necessary to project
much of  the plant level data to the boiler level for input to these models.
Plant level data available from either 1978 projections or historical 1969-73
data updated with more current information from FPC include plant capacity in
megawatts, overall projected plant capacity factor, fuel consumption breakdown
as coal, oil, and gas, plant heat rate in Btu/kWh, heating values of coal, oil,
and gas, and S contents of coal and oil.  At the boiler level, the following
data are available from similar sources: boiler startup year, boiler capacity
in megawatts, and design combustion air rates to the boiler at full load
expressed in sft3/min.  Fuel is allocated from the plant level to the boiler
level from either utility projections for 1978 or historical 1969-73 consump-
tion.  For the cases in which utilities projected plant level data, the data


                                       69

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were generally used as projected.  For the other cases where  historical plant
data were used projections at the boiler level were adjusted  in  accordance
with the historical boiler age-capacity factor relationship which  was described
earlier.  In all cases, data projections and adjustments at the  boiler level
are allowed to override the plant level data.  Details of  the methods for
allocating fuel from the plant to the boiler level may be  found  in Appendix J.
The projections of fuel consumptions are reported in terms of GBtu/yr for each
fuel at each boiler for convenience in comparing the relative fuel distribution,
and individual boiler capacity factors (annual) are calculated.

     Since individual boiler heat rates are not included in the  FPC data file,
the overall plant heat rates were assumed to be applicable for each boiler in
the plant.  Reported air rates to the boiler are compared with calculated air
rates as a check of the data file.  If reported air rates  differ from calcu-
lated rates by >25%, calculated air rates are allowed to override  the reported
rates.

     The FPC data file is used by the compliance test model to project SC>2
emissions for each boiler and plant for comparison with allowable  emissions.
The compliance test procedure is discussed below.

Compliance Test

     The S02 emission and compliance model uses the projected annual fuel
consumption and characteristics data to calculate the annual  quantity of S
which is emitted for each boiler and plant.  For each plant,  allowable
emissions are calculated based on NSPS for new boilers or  the applicable SIP
in effect for AQCR in which the plant is located for existing boilers in
conjunction with the heating value and S content of the fuel.  Excess emissions
expressed as tons S which must be removed per year are then estimated as the
difference between the calculated and allowable emissions.  In the test for
compliance, the plant is considered to be in compliance with  the regulation if
actual  emissions are less than allowable emissions, or do not exceed allowable
emissions by >10%.  This allowance factor is applied to adjust for round off
differences in converting SIP from the various units of expression to the
equivalent single unit of expression (Ib S02/MBtu) for simplification in
testing for compliance.

     The compliance procedure tests the level of application  of  the SIP to
determine the procedure for complying with the regulation.  Levels of appli-
cation  are specified as either (1) an entire plant, (2) an individual boiler,
or (3)  an individual stack.  In all cases where scrubbers are required, they
are assumed to be designed for an SC>2 removal efficiency of 90%.   However, the
actual  performance level needs to be more clearly defined  in  sustained full-
scale operation when high-S coal is burned.  The 90% level results in over-
compliance for many plants, particularly those which have  SIP which apply at
the boiler level.

Compliance Procedure for Meeting Plant Level SIP	
     When the regulation applies to an entire plant, the model determines the
number  of boilers which must be scrubbed, ordered from lowest to highest cost,
to reduce overall plant emission to comply with the regulation.  The FPC data


                                       70

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for these plants and specific boilers are used  as  input  to  the  scrubbing cost
generator for projecting costs.

Compliance Procedure for Meeting Boiler Level SIP—
     When SIP are applied at the boiler level,  the compliance test procedure
determines compliance status for individual boilers  similar  to  the method for
determining compliance status at the plant level and specifies  the boilers
which exceed allowable emissions.  The FPC data for  these plants and specific
boilers are then used as input to the scrubbing cost generator  and for projecting
costs similar to the plant level SIP compliance procedure.   A hypothetical
example is given below to illustrate the difference  in SC>2 emission reductions
when the two procedures are applied to the same plant.   Assume  that a plant
made up of four equal-size boilers operating at equal capacity  factors has a
total annual S emission rate of 120,000 tons/yr and  an allowable emission of
60,000 tons/yr.  Excess emissions for this plant calculated  by  difference are
equal to 60,000 tons/yr.  The total S emission  rate  per  boiler  is about
30,000 tons/yr.  If scrubbers capable of removing  90% of the S  to the boiler
were installed on each boiler, the net reduction in  emissions for each boiler
would be 0.90 x 30,000 or 27,000 tons/yr.  If the  S02 emission  regulation was
a plant level regulation, the reduction in emissions could be achieved by
installing scrubbers on three of the four boilers.   (Excess  emissions = 60,000
tons/yr; reduction in emissions for three boilers  =  3 x  27,000  or 81,000 tons/
yr, which is greater than the quantity of excess emissions.)  If the same
hypothetical plant had boiler level rather than plant level  SIP, the fourth
boiler would not be in compliance, even though  the total emissions for the
plant were less than the allowable emissions.  Therefore, all four boilers
would require scrubbers if the regulation was on a boiler basis.

Compliance Procedure for Meeting Stack Level SIP—
     Power plants are designed with a wide variety of boiler-stack config-
urations.  Therefore, the application of stack  level regulations has different
implications as far as the procedure for complying with  the  regulation.  If,
for example, the plant is designed with multiple boilers, but with a single
stack, the procedure for meeting the regulation is similar to the procedure
for complying with plant level regulations.  If the  plant is designed with
separate stacks for each individual boiler, the procedure for meeting the
regulations is similar to the procedure for complying with boiler level SIP.
Most power plants fit into one of the above two categories.  However, there
are a number of plants which have multiple boilers which feed to more than one
stack.  In many cases, the FPC data for these plants do  not  include sufficient
information to determine the specific association  between stacks and boilers.
Therefore it is not possible for these plants to use a compliance test to
determine status of individual stacks.  Because of this  problem, and with the
concurrence of EPA, all stack level SIP are used similar to  boiler level SIP
when the association between boilers and stacks cannot be determined.

     The final output of the scrubbing cost generator is an  identification of
all boilers at each plant that must be scrubbed to meet  the  S02 emission
regulation.
                                       71

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Compliance Status of Power Plants

     Based on the projected data, it is estimated that a total of 187 plants
will be out of compliance with either NSPS  (new plants)  or  SIP  (existing
plants) in 1978.   It should be noted that many of the plants shown as out of
compliance are likely on a compliance schedule with technology that may  be
different from that projected.  Of these, a total of 69 plants is  out of
compliance based on plant level SIP and 118 based on boiler level SIP.   A map
showing the location of these plants is shown in Figure 17.  Boiler sizes for
plants out of compliance range from as low as 5 to 1150 MW,  whereas plant
sizes range from  38 to 2558  MW.   Boiler  ages for  these plants range from zero
(new plants) to 60 yr old.  The total annual quantity of emissions from  these
plants is equivalent to 5,734,629 tons of S per year, compared to an allowable
emission rate of 3,236,764 tons/yr.  Based on these projections, an average
overall S02 removal efficiency of 44% would be required to bring these plants
into compliance.

     The method for using the output of the compliance tests to project  costs
for meeting the regulation by FGD is discussed below.
DEVELOPMENT OF THE SCRUBBING COST GENERATOR

     The purpose of the scrubber cost generator is to provide a simplified,
consistent method for projecting comparative costs for installing FGD systems
on the power plants projected to be out of compliance with the regulation.
Because of the limited amount of information available for input to the model,
the projections are to be treated as general rather than specific in evalua-
tion of the results.

     The FPC data projections to 1978 and the output of the compliance test
models are inputs to the model.  The basis for its development and other
relevant information concerning its use are discussed below.

Background

     TVA in conjunction with EPA published a report entitled  Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes  (EPA 600/2-75-006;
NTIS PB 242 541, January 1975)  (7) which projects the economics of S02 control
by two throwaway processes (limestone and lime slurry scrubbing) and three
recovery processes  (magnesia slurry-regeneration, Wellman Lord/Allied, and
catalytic oxidation).  As mentioned, the limestone, magnesia, and Wellman
Lord/Allied are the primary FGD alternatives considered in the current study.
The detailed "base" investment and operating cost projections given in the
above report for these processes, and the method illustrated for scaling costs,
were coded into a computer model to allow for projection of economics for these
processes at other capacities based on using the 1978 FPC data projections
discussed above.

     The "base" data incorporated into the program correspond to scrubbing
processes designed for 500-MW boilers, both new and existing, which burn 3.5%
S coal (dry basis).  They are assumed to emit 92% of the S in the coal overhead

                                      72

-------
« < 70$/MBTU  (SCRUBBING COST)
A>70$/MBTU  (SCRUBBING COST)
    Figure 17.  Geographic distribution of 187 power plants projected  out  of  compliance (1978)

-------
as S02, and are designed to remove 90% of the S02-  The processes were
modified from the initial study to exclude the costs for particulate  removal.

Investment Scaling Procedure

Direct Investment Scaling—
     A method was established for using the FPC Form 67 data and the  compliance
test data to project the investment and unit revenue requirements for each
power plant out of compliance.  Quantities of air and S rates to the  boiler
for the base case are included in the data base.

     Similar data are projected for each boiler which is determined from  the
compliance test to be out of compliance.  Relative capacities are calculated
to allow for scaling costs.  Flue gas processing equipment and costs  are
estimated assuming that each boiler must be designed with separate, independ-
ent equipment.  Absorbent preparation and effluent processing areas,  however,
are designed with common facilities at the plant level to process the combined
quantities of absorbent and effluent from all of the boilers.  This "common
facility" concept minimizes the investment requirements because designing for
installation of single large units rather than multiple small units results in
an economy of scale.

     The FPC Form 67 data base does not contain data specifying flue  gas  rates
from the boiler to allow for scaling of the gas processing equipment  (scrubbers,
fans,  reheaters, and duct).  Therefore, costs for these areas are scaled  on the
basis  of air rates to the boiler.  Emission rates of S for each boiler are
available from the compliance tests and are totaled for each boiler which
requires S(>2 control; the total quantity is then used in scaling S processing
costs.

     The general form of the equations for scaling costs for (1) the  flue gas
processing areas and (2) the absorbent preparation and effluent processing
areas  are shown below:
                                                                            Bl
(1)  Flue gas processing    Base flue gas
     area cost for       _  processing
     individual             area cost
     boiler (I)
Design air rate to boiler (I)

Design air rate to base boiler
     Where Bl = scaling exponent for the gas processing equipment whose
                costs are being scaled.

Total flue gas processing area costs for the plant are equal to the sum of the
flue gas processing area costs for each boiler which requires scrubbers.
                                                                            B2
(2)  Absorbent prepara-     Base absorbent
     tion and effluent      preparation and
     processing area     =  effluent pro-
     common facilities      cessing area
     cost (entire plant)    cost
Total annual S throughput for
all boilers which require
scrubbers
Total annual S throughput for
the base plant
     Where B2 = scaling exponent for the S processing equipment whose
                costs are being scaled.
                                      74

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     Since the absorbent preparation and effluent processing areas are
designed utilizing common  facilities for the total  throughput,  these calcu-
lated costs do not need to be  summed boiler by boiler.

     The total direct investment is calculated as the  sum of the total flue
gas processing area and the  common facilities costs.

Indirect Investment Costs—
     Indirect investment costs are estimated as a percentage of the direct
costs similar to the method  used in the initial study.   For simplification  in
developing the model, the  indirect cost factors do  not vary with plant or
boiler size.   Table 27 shows the indirect cost factors which are used in
projecting total investment  requirements for each of the three  processes as a
function of plant status (new  or existing unit).
            TABLE  27.   INDIRECT INVESTMENT AND ALLOWANCE FACTORS (7)
   Indirect Investment Factors

   Engineering design and supervision
   Construction field expense
   Contractor fees
   Contingency

       Total indirects
                                      Indirect investment and allowance factors
                                      as  a percent of direct capital investment
                                           Limestone   Magnesia and Wellman
                                      	process   Lord/Allied gfocesses
                                         New  Existing
 9
11
 5
10

35
10
13
 7
Ij.

41
                    Hew  Existing
11
11
 5
10

37
12
13
 7
11

43
  Allowance Factors

  Startup and modifications
  Interest during construction

       Total allowances
 8
_8

16
 8
JJ

16
10
_8

18
10
_8

18
                                       75

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Investment Adjustment Factors —
     The data base was created to allow the input of other factors for  ad-
justing process investment.  A process premise factor is an allowable input  to
adjust the projected process investment for any of the four processes.   The
adjustment is applied uniformly for all plants.  It allows the relativity of
process investments to be varied from that reported in the initial study to
reflect updated technology and costs and is applied separate from cost  indices.
For the current study, process premise factors for the limestone, sodium, and
gypsum processes are input as 1.2, whereas the factor for the magnesia  process
is input as 1.3.  These values adjust the relativity of the costs to conform
with recent vendor cost data.

     The data base also allows for the use of site-specific factors which can
be used for any process and any plant to adjust the investment to take  into
account special design provisions which were not considered in the initial
study.  Factors were incorporated for some of the TVA plants to reflect the
effect of a common plenum which would require fewer scrubbers, and to adjust
for higher projected capacity factors in comparison with projected FPC  factors.

     Two additional factors which may be input to the program to impact
process investment include  (1) a retrofit difficulty factor (developed  by
PEDCo) and (2) a location factor.  Each of these factors is applied specifi-
cally to all processes at a given location.  The retrofit difficulty factor
adjusts the projected investment equally for all processes at a given location
to account for site-specific variations in design and layout which would
affect costs for installation of each process alternative equally.  Location
factors are applied in the same manner to account for site-specific differences
in construction costs which are related to plant location and terrain.

     The FPC data file does not contain information specifying the number of
flue gas ducts on existing boilers.  Since the number of required scrubbing
trains is a function of the number  of ducts, power plants with gas flow
rates of <700,000 sft3/min were arbitrarily assumed to be designed with two
ducts, whereas plants with larger flow rates were assumed to be designed with
four ducts.

Revenue Requirement Scaling Procedure

Direct Costs —
     Annual quantities of raw materials and utilities required for each
processing area (i.e., absorbent preparation, scrubbing,  reheat, S02 processing,
etc.) are identified and are scaled from the "base" data proportional to the
relative gas ratio or the relative S throughput ratio similar to the method
for scaling investments.   Labor and analyses requirements are scaled propor-
tional to the relative gas or S throughput ratio raised to a fractional
exponential power.
f«n    P             as.humidif ica<:ion water,  reheat,  and electricity for the
and'uMliMe    Pr°P°rtional to the relative gas rate, whereas raw materials
and utilities,  such as absorbent and electricity for the S-processing areas
are scaled proportional to the  relative S  rate.   Annual cos
                                                 Annual costs for raw materals

                                      76

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and utilities are then calculated by applying  the unit  costs  to  the annual
usage rates.

     Projected unit costs for raw materials and  utilities  for 1978 are shown
in Table 28 with the exception of limestone and  sludge  disposal.  A program
with the supporting data base was developed for  calculating the  delivered cost
of limestone to each power plant considered in the  study.  Details are out-
lined in Appendix X.

     Maintenance is estimated as a percent of  the subtotal direct investment
at the rates indicated in Table 29.  Conversion  operating  costs  are defined as
the sum of utility, labor, maintenance, and analyses  costs.   Direct costs are
defined as the sum of raw material plus conversion  costs.


     TABLE 29.  ESTIMATED MAINTENANCE  RATES FOR  ALTERNATIVE FGD  PROCESS  (7)


                                            Maintenance rate,
       	  Process	% of  direct  investment	

                   Limestone                        8
                   Magnesia                         7
                   Wellman-Lord/Allied              6
Indirect Costs—
     The capital charges included in  the  indirect  operating  costs are applied
as average capital charges, including depreciation,  interim  replacements,
insurance, and cost of capital and  taxes.   Depreciation  is straight line over
the remaining life of the plant  (based  on an  assumed useful  life of 30 yr).
The capital charge allocation for interim replacements varies as a function of
the remaining life of the plant.  For a new plant  it is  allocated as 0.67% of
the total investment, but declines  to zero for  plants with <20 yr of remaining
life.  Insurance is allocated as 0.50%  of total investment for all plants.
The overall breakdown of capital charges  included  in the cost projections is
shown in Table 30  (7).

     For each process, plant overhead is  estimated as 20% of conversion costs,
and administrative overhead as 10%  of operating labor.   Administrative over-
heads in the initial study (7) were calculated  on  a different basis for
processes producing a salable byproduct as compared to sludge producing
processes to take into account the  costs  for  marketing the byproducts.  For
this study, however, the byproduct  prices are assumed to be  net prices after
marketing expenses have been deducted;  therefore,  administrative overheads
are calculated by the same procedure  for  all  processes.

     Subtotal indirect costs are defined  as the total of capital charges, and
plant and administrative overheads.   Total annual  revenue requirements are
defined as the total of direct plus indirect  costs.
                                       77

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TABLE 28.  PROJECTED 1978 UNIT COSTS FOR RAW MATERIALS, LABOR, AND UTILITIES
                                                    Unit cost, $
           Raw Materials

           Limestone
           Lime
           Mag ne s ium ox id e
           Coke
           Vanadium pentoxide catalyst
           Sodium carbonate
           Antioxidant (sodium process-scrubbing)
           Sulfuric acid
  Variable3
 42.00/ton
215.00/ton
 28.00/ton
  2.20/1
 78.00/ton
  2.75/lb
 54.00/ton
           Labor

           Operating labor
           Analyses
 10.00/hr
 15.00/hr
           Utilities

           Fuel oil, No. 6
           Natural gas
           Steam (500 psig)
           Process water
           Electricity
           Heat credit
           Water treatment
           Sludge transportation fee
              (offsite disposal variation)
  0.35/gal
  2.50/kft3
  1.40/klb
  0.06/kgal
  0.027/kWh
  1.15/MBtu
  1.20/kgal

  1.00/tona
a. See details in Appendix K.
                                    78

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  TABLE 30.  ANNUAL CAPITAL CHARGES FOR POWER INDUSTRY FINANCING (7)
Depreciation, straight line (based on
 years remaining life of power unit)
Interim replacements (equipment
 having less than 30-yr life)
Insurance

Total rate applied to
 original investment
                                          As percentage of
                                         original investment
                                        Years remaining life
                                           30     25     20

                                          3.33   4.00   5.00

                                          0.67   0.40
                                          0.50   0.50   0.50
                                          4.50   4.90   5.50
Cost of capital (capital structure
 assumed to be 50% debt and 50% equity)
  Bonds at 8% interest
  Equity at 12% return to stockholder
Taxes
  Federal (50% of gross return or
   same as return on equity)
  State (national average for states
   in relation to Federal rates)

Total rate applied to
 depreciation base
                                           As percentage
                                           of outstanding
                                         depreciation basec
                                                4.00
                                                6.00
                                                6.00

                                                4.80


                                               20.80b
    Original investment yet to be recovered or "written off."
    Applied on an average basis, the total annual percentage of original
    fixed investment for a plant with 30 yr remaining life would be
    4.5% + 1/2(20.80%) = 14.90%.
a.
b.
                                79

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Output of the Scrubbing Cost Generator

     The overall output of the scrubbing cost generator includes  the  following
information for each of the three scrubbing alternatives considered:

   1.  Plant investment

         $
         $/kW

   2.  First-year costs excluding byproduct revenue

         $
         Mills/kWh
         Cents/MBtu

   3.  Byproduct

         Production rate, tons/yr
         Equivalent cost, $/ton

   4.  Incremental process cost in comparison to limestone scrubbing

         $
         $/ton of byproduct

An example output is shown in Table 31.

     The data generated in the scrubbing cost model are used  to calculate  the
scrubbing costs of a throwaway system versus a salable byproduct  for  each  of
the  833 boilers identified in this study as operating out of  compliance with
pollution control laws in 1978.

     The scrubbing costs for fossil fuel power generation are expressed in
cents/MBtu for convenience in comparing them with clean fuel  alternatives.
Use  of low-S fuel is also a realistic alternative to FGD which must be
considered for meeting compliance regulations.  The alternative clean fuel
level  (ACFL) represents the amount of premium that one can pay for fuel that
is low enough in S to meet compliance in lieu of scrubbing with an FGD system.

     The model also calculates the cost differential between  scrubbing with a
limestone throwaway system versus  MgO-acid producing system.   This comparison
is  based on the quivalent  of  100% H2S04 for both  systems.   This  accommodates
 identifying the incremental cost difference of  the  two systems for all boilers
 or combinations of  boilers  included  in the model.

     The lowest cost scrubbing system is limestone scrubbing  at all plants in
the  model except for a unique type of plant, that is, a large (500-MW) new
plant burning a low-S fuel such as oil  and yet is exceeding SIP regulations.
MgO-acid scrubbing in this instance is  lower in cost as compared  to limestone
scrubbing.   Such plants were handled in the model with a zero incremental  cost
in lieu  of using the negative cost.

                                      80

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            TABLE 31.   SAMPLE OUTPUT OF  SCRUBBING COST GENERATOR
Plant code:   000000-0000
PLANT NAME:   X
                                  Compliance  costs from 1978 projections
Capacity factor, %
  Coal
  Oil
  Gas
S content, %
  Coal
  Oil
Total capacity, MW (12 boilers)
Total scrubbed, MW (5 boilers)
Process
  Investments
    $
    $/kW
First year costs (byproduct
 revenues excluded)
  $
  Mills/kWh
  Cents/MBtu

Byproduct
  Tons/yr
  Cost, $/ton
Incremental costs in compari-
 son to limestone process
  $
  $/ton
     56.5
      2.5
      0.1
      3.2
      1.5
    1,275
    1,109


Limestone
Magnesia
                                                                Wellman-Lord/
                                                                      Allied
80
45


,152,545
72.3
,078,254
6.82
65.7
Sludge
426,094
105.8
0
0
95,996,739
86.6
52,957,830
8.02
77.2
H2S04
228,181
232.1
7,879,576
35
104,861,270
94.6
67,973,845
10.29
99.1
S
68,399
993.8
22,895,591
335
                                       81

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     Costs for production of S by the Wellman-Lord/Allied process were higher
in all cases studied than production of H2S04.  Projected savings in distri-
bution costs for S compared to H2S04 did not offset the incremental production
costs.  Costs for use of the Wellman-Lord/Allied technology will be more
clearly defined during the current full-scale demonstration, partially funded
by EPA, at the Mitchell Station of the Northern Indiana Public Service Company.
Revised information will be included in the model.  Also, EPA is currently
sponsoring work with ESEERCO (Empire State Electric Energy Research Corporation)
and Niagara Mohawk to develop the Atomics International process for producing
S from SC-2 in stack gas.  This technology and other work involving use of
solid reductants could lead to lower costs for production of S as an alter-
native to producing H2S04.

     Several factors that are difficult to incorporate into a generalized
economic model could have a significant influence on the choice of byproducts.
The incentive for production of S is high because it is a safe, noncorrosive,
convenient material to handle, and can be easily stockpiled for long periods
of time at relatively low cost.  Because of the latter advantage, S could be
incorporated more easily into the existing market.  Moreover, fluctuations
in market demand could be met with less impact to both the producer and con-
sumer.  S also has the advantage of being more economical to ship than acid,
especially for long distances.

     In the computer program used for the marketing study, the model assumes
that acid plants that could be supplied with byproduct acid at a lower cost
than their own production costs (including cost of raw material S) would shut
down and purchase byproduct acid to sell to their customers.  This would
involve a strong commitment to use of the byproduct because personnel to man
the acid plant could not be kept on standby nor would a guaranteed supply of
S be available on short notice.  The acid distributor would very likely prefer
to purchase byproduct S (at a lower price than natural S) to supplement or
replace his traditional supply.  Also, H2S04 plants normally generate steam
from burning S for use in other plant operations.  It would be necessary to
replace this available energy with an alternate supply requiring the burning
of additional coal or fuel oil.  Facilities for replacement steam production
could cost more than the savings from purchase of byproduct acid.  S would
be favored over acid as a byproduct in those power plant locations where an
existing S terminal is already in operation.  There are a number of such
terminals on the East Coast.  The facilities required for handling molten S
would be of little value in handling acid.  Also, S would be the preferred
byproduct in extremely cold climates.  The freezing point of acid varies with
concentration, but 98% acid will freeze at about 40°F.  Long-term storage of
acid would be much more expensive and difficult under these conditions.
Another situation when S would be favored is for power plants in the Western
States where the limited acid market is controlled by smelters.  Shipping S
to the eastern market would be more economical than acid.

      It is likely that a mix of marketable byproducts will ultimately provide
the least-cost compliance with S02 regulations in the utility industry.
Technology for production of S should be fully developed so that the choice
is available and so that accurate information is available for cost comparisons
with other methods of control.

                                     82

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     The cost information from the scrubbing  cost model becomes  input to the
marketing model which is designed to determine the potential for the pro-
duction and marketing of byproduct l^SO^  at  the various power plant locations.
The data can also be used to generate  a  supply curve for the production of
abatement
Supply Curve for Abatement Acid

     A demand curve for abatement  acid  was presented in Figure 6.   For
illustrative purposes it is useful to consider the supply curve that would be
traced out by different levels of  a uniform f.o.b. steam plant supply cost
for 1^504.  This ignores steam plant location relative to acid plants.   Such
a curve can be estimated by ranking power plant boilers from lowest to highest
cost for producing H2S04 and  accumulating supply quantities shown  in Figure 18.
The range of supply costs  is  much  greater than those for demand.   While  about
9 Mtons of acid  is  available at an infinite price, supplies greater  than
about 8 Mtons  is unreasonable.
                                       83

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      1.5
     1.0
crt
O
U

H
M
     0.5
                                            8
10
12
14
                       CUMULATIVE S REMOVAL, MTONS OF HnSO,
                    Figure 18.  The supply cost curve for abatement acid.
                                        84

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         ABATEMENT BYPRODUCT ACID DISTRIBUTION-TRANSPORTATION  SYSTEM


     To assess representative competitive  costs,  this market system analysis
must generate accurate S freight rates  from the Frasch  S  sources to the acid
plants and 1^804 freight rates from all power  plants to all 1^504 plants.
This represents more than 300,000 possible rates  which  is a prohibitive
manual task.  Also, the overall market  study series calls for  a possible
expansion to evaluate CaS04 for wallboard,  ammonium sulfate  {(1^4)2804], and
several other fertilizer classifications;  therefore, the  task  becomes
increasingly demanding.
STANDARD POINT LOCATION CODE

     The logistical linkage between  the H2S04  and power plant data bases and
the rate generation system is the  Standard  Point Location  Code  (SPLC).  This
is a transportation-oriented, six-digit number prescribed  by the National
Motor Freight Traffic Association  under the guidance  of the SPLC Policy
Committee.  The system is similar  to U.S. mail zip codes.  Figure 19 shows
location areas to the first two-digit  level.   The first digit indicates a
region relating to major traditional traffic associations.  The first two
digits uniquely identify a state or  a  portion  thereof.  As more digits are
added, smaller nested areal units  are  identified.  The third digit gives a
cluster of counties, the fourth digit  a county, the fifth  digit a cluster of
points within a county, and the sixth  digit identifies all rail and truck
specific points.
DISTRIBUTION COST GENERATION

     A logic flow diagram of the freight  rate  generation  system used in this
model is shown in Figure 20.  It shows  that  an SPLC  for a power plant origin
and one for an H2S04 plant destination  are input  to  the National Rate Basis
Tariff 1-C (NRBT 1-C).  This tariff determines for rail rate purposes the
basing points for the origin and destination.   While there are about 60,000
rail points, there are only 2,632 basing  points east of the Rocky Mountains.

     Outputs from the NRBT 1-C block  in Figure 20 are two sets of codes used
to define mileage and tariff rates between the byproduct  shipping origin and
destination points.  One set—Index 1 and Index 2—is used to determine the
appropriate rate base mileage to be applied.   The two index values are
pointers to a 3.5 M record triangular mileage  file compiled from 12 tariffs
resulting from the landmark 1945 Interstate  Commerce Commission hearing
entitled "Docket 28300."  (Short line rail mileage published in the twelve
"28300 Class Tariffs" by all railroads  operating  east of  the transcontinental


                                      85

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00
                   Figure 19.   Geographic identification of Standard Point  Location Codes  (SPLC),

-------
        SPLC,—,
              |—SPLC2
                NRBT    I-C
     I
  INDEX
  __*
INDEX.
  i
    DOCKET
     28300
       I
 RATE  BASE MILEAGE
                 RATE
               SEARCH
               MINIMUM
                RATE
MES,
 i
MES;
                      TARIFF
                    GENERATOR
                         I
                    TARIFF NUMBER
Figure 20.  Flow diagram of freight rate generation model.
                       87

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territory outlined in Figure 21).   The file includes rail (and some truck)
tariff mileage for shipments within and between five major freight associations
shown in Figure 21.   Output from the Docket 28300 block of Figure 20 is a rate
base number that can be thought of as a type of mileage.

     The second group of codes output from the NRBT 1-C define the mutually
exclusive set (MES)  numbers for the origin and destination points and serve
as input to the Tariff Rate Generator block to choose the appropriate tariff.
Figure 21 shows the  location of the nine rate territories (MES Nos.) east of
the Rockies.   Identification of the nine territories is necessary due to over-
lapping application  of the five major freight rate territories.  The remaining
10 MES numbers as shown in Table 32 are those base points which by virtue of
unique circumstances or borderline applications necessitates separate listing.
The result is a total of 19 MES numbers for basing points in the Docket 28300
tariffs.  Given the  MES for both the origin and destination it can be deter-
mined in which tariff(s) these points can be found, which is output from the
Tariff Generator block in Figure 20.
                 TABLE 32.  RECLASSIFICATION OF BASE POINTS

10
10
11
12
12
12
13
13
13
13
13
13
14
14
KY
KY
KY
DC
VA
WV
VA
VA
VA
VA
VA
VA
VA
VA
Lexington
Winchester
Chilesburg
Washington
Norfolk
Charleston
Alberta (S)
Altavista (S)
Burkeville (S)
Lynchburg (S)
Petersburg (S)
Suffolk (S)
Bristol
Norton
14
14
15
15
16
16
17
18
19
19
19
19
19
19
VA
TN
SC
SC
NC
TN
IL
NY
IN
IN
IN
IN
IN
WV
St. Paul
Bristol
Anderson Quarry
Rion
Bunn
Brownsville
Sparta
Pulaski
Cannelton
Corydon
Ferdinand
Huntingburg
Marengo
Olcott

     The importance of knowing not only the mileage but also the tarrif
number is illustrated in Figure 22.  Shown are l^SO^ rail rates within four
major freight associations as a function of rate base numbers.  A slight
error in mileage is not nearly as critical as knowing which tariff applies.
Also these are the only published 1^804 rates.  Rates for the other eight
tariffs were generated by the TVA Navigation and Regional Economics Branch
(Division of Navigation Development and Regional Studies) from those using
sound traffic legal arguments similar to the negotiation process that would
ensue should large acid movements become a reality.  In Figure 20 rate base
and tariff numbers are input to the Rate Search block and the minimum rate
is output for use in the transportation cost model.
                                     88

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oo
                                          WESTERN  TRUNK

                                               TERRITORY
 GENERAL FREIGHT  TR
"•COMMITTEE
I    t
I   ,"•...
              TRANS-CONTINENTAL
                 TERRITORY
                                          SOUTHWESTERN

                                            TERRITORY

                                              SWL  5
                                                              #8 SWL-SFA
                                     Figure 21.  Railroad rate territories.

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  26 i—
  24 -
  22
   20
   18
   16
   14
o

tr
   12
CO




O



*x


-co-
10


                    •'"  /WTL-2000J  /

                   / /'         '


                //       A
               :' /       /SW-2004-l
      E-2009-H / /'        /
                            SFA-351-0
      -4
      -/





           200   400   600    800    1000    1200   I40O   1600    1800


                              DISTANCE
          Figure 22.   Four basic commodity column tariffs for

                         H2S04 rail shipments.
                                    90

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                      MARKET SIMULATION MODEL THEORY
     Objective of the overall marketing model is to simulate long-run com-
petitive equilibrium S and H2S04 market conditions in the U.S.  as might be
impacted by recovery of byproducts from S02  control in the power industry.
To simulate these conditions, total cost  of  both the H2S04 and  power industries
is minimized subject tc the condition  that acid  production (demand) is still
met, either from traditional S sources or from substitution of  abatement
     The model is similar to the classic  transportation model  of linear pro-
graming where demands represent H2S04 plant  customers  and  supplies represent
either production at each of the commercial  acid  plants or purchases from
any power plant boiler capable of producing  acid.   Incurred (transfer) costs
represent either H2S04 production cost using Port  Sulphur  S in the first case
or boiler scrubbing cost plus transportation cost  to the respective acid
plants in the second case.  A mathematical statement of the model is outlined
in Appendix B.
ECONOMIC THEORY

     Through the use of several simplifying  assumptions,  the complex process
taking place in the model can be conceptualized  in  terms  of classical supply
and demand curves.

     If spatial considerations could be  ignored,  the  demand (price) curve in
Figure 6 and the supply (cost) curve in  Figure 18 could be plotted on the
same graph as in Figure 23; where they intersect  would represent supply-
demand equilibrium.

     It was explained earlier, and summarized in  Figure 6, that from the
H2S04 plant data base and the long-run average acid production cost generator,
all commercial acid producers can be ranked  in terms  of a demand curve.  A
conceptual f.o.b.  power plant acid demand  curve DDT is shown in Figure 23.
At high abatement supply price levels, only  the  smallest, oldest, most
remotely located acid plants would be interested  in curtailing production
and buying abatement acid.  As supply price  declines, more acid producers
buy until even the largest, newest plants  located near S  supply sources
become candidates.

     Likewise, as explained earlier and  summarized  in Figure 18 boilers can
be ranked in terms of a supply (cost) curve, f.o.b. each  power plant such as
SS'  in Figure 23.   The intersection of such  a supply  curve wxth the conceptual


                                      91

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t
u
<


0.
o
Ul
o

o:
o.
                                                         USE
                                                   MCLEAN FUEL
CONTINUE PRODUCTION
                      QUANTITY  OF SULFURIC ACID
        Figure 23.  Conceptual demand curve for l^SO^ and supply

                    curve for abatement production.
                                 92

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 demand in Figure 23 would represent  an equilibrium position at point Q.   The
 price F represents the alternative of buying complying fuel.

     From the demand curve DD1 , H2S04 producers above equilibrium price  P
 would find it profitable to buy acid from steam plants rather than continuing
 production.  Those less than price P would find it more profitable to con-
 tinue production.

     From the supply curve SS1, boilers below price P would find it feasible
 to use a scrubbing strategy that  produces H2S04, while those above price P
 but less than price F would profit from using a scrubbing strategy that
 produces and disposes calcium  (Ca) sludge.  Those above price F would find it
 more profitable to use a clean fuels strategy in lieu of scrubbing, assuming
 that such clean fuel is available.

 Multidimensional Equilibrium Model

     While the preceding simplified  economic description presents the essence
 of the economic model, a more  elaborate spatial equilibrium model is required
 for realistic analysis.  The problem is that the lowest acid cost boiler
 could be close to or far from  the highest cost commercial acid plant.  It
 therefore  is necessary to trace  a demand curve for a single source (location)
 of supply.  This could be done for every supply point, but would be of no
 analytical significance unless there was only one supply point being con-
 sidered.  As soon as more than one supply point is considered, competition
 develops for demand points.  Hence,  while traditional supply-demand concepts
 are helpful in exploring the basic underlying economic structure of flue gas
 marketing alternatives, a much more  elaborate multidimensional equilibrium
 model is required before analytical  conclusion can be drawn.

     The model implicitly ranks potential acid buyers as described earlier
 under the demand for abatement acid  except that every potential abatement
 acid producer is given his own view  of the market with reference to his
 specific location.  As the model  is  being solved this view is dynamically
 changed to reflect the bidding away  of markets by other potential abatement
 producers.  The decision-making process might be viewed in two stages  (1)
 the utility manager is bidding for markets at a given price and (2)  based on
 results of the bidding decides if production of acid is the least-cost
 alternative.   The results of this bidding process,  of course,  interacts  with
 his abatement strategy decision.  The task of simulating this process  from
 the viewpoint of 104 acid producers  and 833 steam plant boilers can be
 solved with modern computers and  linear programing techniques.   The solution
 reveals not only which acid producers would buy and which power plants would
 sell H2S04, but also which power  plants would sell to which acid plants.  The
mix of abatement strategies and marketing patterns resulting in the lowest
possible cost to the combined  industries (society)  is said to be optimal.
 Such a solution simulates the  result of long-run competitive equilibrium
solutions.  Any variation to this optimal solution would increase the total
cost to both industries .
     The model is designed to place  alternative strat e?ies/°^C°^"°^fves
emissions in perspective for each power  plant  in relation to the  alternatives
                                      93

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available to all other power plants.  The model addresses only those plants
that are projected to be out of compliance in 1978.  The strategies considered
include (1) the use of clean fuel,  (2) scrubbing with limestone to produce a
throwaway sludge, and (3) scrubbing with MgO to produce J^SO^ as a marketable
product.  It is obvious that the lower the cost of clean fuel the less justi-
fication utilities would have to use FGD.  However, clean fuel is more
expensive than traditional fuel supplies.  The premium cost for complying
fuel is assumed to be the limit on the net cost of scrubbing.  That is, as
the premium for clean fuel increases the more the utility industry can pay
for FGD systems.

     If scrubbing is the least-cost option the model chooses between the use
of limestone scrubbing technology or the production of abatement acid; costs
for production of S by the Wellman-Lord/Allied process were higher in all
cases studied than production of 112804.   If the incremental cost of scrubbing
with MgO to produce I^SO^ compared with limestone scrubbing can be recovered
by marketing t^SO^ in the existing market then the power plant would choose
the acid-producing strategy.

     The model considers total cost of both the H2S04 and power industries
and chooses the set of alternatives that minimize the total cost.   t^SO^
producers are given a choice of continuing production or buying acid from any
steam plant.
                                     94

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                            RESULTS AND ANALYSIS
PLANTS  OUT OF COMPLIANCE IN 1978

     The operating characteristics of all 800 U.S. power plants projected to
be in operation in 1978 are outlined in Table 33.  Also included in this table
are the characteristics of the plants projected  to operate out of compliance
in 1978.

     As the data in the table indicate, 187 power plants out of a total of 800
were calculated to be out of compliance.  It should be noted that many of the
plants  estimated to be out of compliance are likely on compliance scheduled
that are different from those selected for this  study.  Even though plants out
of compliance make up only 32% of the total population with respect to capacity,
they burn about 50% of the total coal; only 20%  of the total oil and only 5%
of the  total gas.  Plants out of compliance have a 30% higher S content in the
coal burned and a 43% higher S content in the oil burned than the overall
nationwide average.  The average boiler size for plants out of compliance was
about 30% greater than the average for all plants.  The age range of boilers,
the range of boiler sizes, and boiler capacity factor for plants out of
compliance were not significantly different from the industrywide values.

ACFL

     The ACFL is defined as the premium price for fuel that will meet the
applicable S02 emission regulation.  Determination of the actual premium paid
for complying fuel in the utility industry is beyond the scope of this study.
Also, the availability of complying fuel was not considered.  The ACFL selected
for the model runs ($0.35, $0.50, and $0.70/MBtu) were chosen to show the
effect  on potential volume of abatement acid.  However, the range covered
should  be representative of most actual situations.  Extreme values were used
to demonstrate that at low premium price, scrubbing is not competitive while
at high premium values, FGD is the economic choice.  The results of these
calculations for all plants estimated to be out  of compliance in 1978 are
shown in the following tabulation:


                           Reduction in Emissions
Clean fuel
premium,
cents /MB tu

Clea
ktons S
n fuel Scrubbing
Annual
Clean fuel
cost, $
Scrubbing
        25          4 440          -       1,172,406,000
                    '  eg        4 342       159,200,000   2,323,553,000
                     _9         ^440          -          2,866,244,000

                                      95

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TABLE 33.   POWER PLANT OPERATING CHARACTERISTICS PROJECTED FOR 1978
                                                        1978
                                           1978         plants
                                           all          out of
                                        U.S. plants    compliance

No. of power plants                             800           187
No. of boilers                                3,382           833
Total capacity, MW                          411,000        132,600
Total fuel
   Coal, ktons                               475,600        226,800
   Coal," GBtu                              10,408,300     5,125,100
   Oil, kbbl                                 620,300        110,200
   Oil, GBtu                                3,827,400        686,900
   Gas, Mft3                                2,556,000        108,200
   Gas, GBtu                                2,602,200        167,000
Average S content of coal,  %                    2.12           2.81
Average S content of oil,  %                    0.99           1.42
Emissions, equivalent tons  H2S04
   Total emitted                          29,552,100     17,562,300
   Required abatement                      9,912,600     9,912,600
Average  capacity factor,  %                    31.87          35.12
Average boiler generating capacity,  MW          122            159
Age of boilers, %
   0-5                                             5             10
   6-10                                             8             10
   11-15                                            8              6
   16-30                                           42             42
   >30                                            37             32
 Size of  boilers, %
   <200                                            82             75
   200-500                                      H.7             15
   501-1000                                       'fe              9
   XLOOO                                         0.3              1
 Capacity factor of  boilers, %
   <20                                            40             35
   20-40                                          20            17
   41-60                                          23             29
   >60                                            17             19
                                96

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     Based on the inputs used to  calculate  scrubbing costs in this  studv  -he
above tabulation indicates that at  $0.25/MBtu ACFL no scrubbers  won]^ be'used
Clean fuel would be the logical strategy for controlling emissions! V'cl^n'
fuel cost is >$1.50/MBtu heat input,  very little clean fuel would be used and
scrubbing would be the strategy for controlling the ma-jor portion of S02
emissions.  The scrubbing costs are based on the least-cost method  without
credit for byproduct sales which  is normally limestone scrubbing.

     The total costs shown illustrate that  if clean fuel were available at
$0.25/MBtu premium, annual cost of  compliance would be $1.17G (G =  1 billion)
while at a premium of $1.50  compliance would be mainly by scrubbing at a cost
of nearly $2.5G.


RESULTS AND ANALYSIS OF BYPRODUCT SMELTER ACID MARKET

     The first model run was made at a zero ACFL so that all power  plants
chose a clean fuel strategy  leaving only the smelters participating in the
market.  As was expected, the smelter acid  was fully integrated  into the acid
market projected for 1978.  When  the clean  fuel premium for the  utility in-
dustry was set at the $0.35/MBtu  ACFL level, eight power plants  produced and
sold acid in competition with the smelters.   The distribution changed slightly,
but the total smelter capacity, 1,756,000 tons, was moved into the  market.
When the ACFL was increased  further to $0.50/MBtu and $0.70/MBtu, competition
from power plant acid reduced the amount of byproduct acid that  can be sold by
the western smelters.  The results  of all the runs on smelter acid  distribution
are summarized in Table 34.  At the $0.50/MBtu level, power plant acid replaced
20% of the western smelter acid and at the  $0.70/MBtu level, over 70% of the
market for western smelter acid was lost to acid produced by power  plants.
Because of their close proximity  to the industrial areas of the  U.S., all of
the eastern and Canadian smelter  acid was sold in competition with  the power
plant acid at all levels of  clean fuel premium.  The analysis of model runs
indicates that the location  of the  western  smelters with respect to
the H2S04 market places them at a disadvantage in competition with  power
plants located in vicinity of the industrial sector of the Eastern  U.S.  If
the power plants develop such markets, the  western smelter would have to
equalize the price in order  to compete.   The only other option available to
the western smelter would be to neutralize  any excess byproduct  acid that
cannot be used for leaching  of low-grade feedstock.

     The supply points identified with the  sale of byproduct smelter acid in
each of the model runs are outlined in Appendix L.


RESULTS AND ANALYSIS OF POWER PLANT ABATEMENT ACID MARKET

Scrubbing Cost Generator Prescreen

     The scrubbing cost generator was used  to identify scrubbing candidates
for all 187 power plants operating  out of compliance at each of  the three
selected values of ACFL.  The results are tabulated as follows:
                                       97

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TABLE 34.  BYPRODUCT SMELTER ACID DISTRIBUTION IN MODEL RUNS

                           (ktons)
Eastern smelters
   Direct sales

     Total Eastern

Canadian smelters
   Via Buffalo terminal
   Via District terminal

     Total Canadian
                                     ACFL, cents/MBtu
                                         35     50
                                         70
                  818     818     818     811
                  818     818     818     818
                  165     165     200     200
                   35      35      -
                  200     200     200     200
Western smelters

     State     Terminal
   Arizona
Houston
   New Mexico  Chicago
               Baton Rouge
               St. Louis
               Houston
   Utah
   Montana
Memphis
St. Louis

St. Louis
Memphis
     Total Western
     Total byproduct smelter
     acid
118

304
 76
 96
 46
 98

738
118

304
 76
 96
 46
 98

738
118

155
 50
166
  9
                                                  96
                                  594
118

 81
                                                         199
                1,756   1,756   1,612   1,217
                            98

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                                         ACFL.  cervts/Mgtti
                                           35       50  '
               Plants with scrubbing
               costs lower than ACFL      19       74     116

               Plants with scrubbing
               costs higher than ACFL    168      113      71


     All power plants with an FGD acid-producing  potential of <66,000 tons/yr
were excluded from the acid-producing candidates  because acid plants with a
lower production capacity would be too small  to be competitive.  Such plants
were given the choice of choosing a limestone or  a clean fuel strategy in the
model.

     For some power plants with multiple boiler installations, a mix of
alternative methods produced the least-cost compliance strategy.  The results
of the prescreen are outlined in the following tabulation:


                           Total U.S. (187 plants)

                                               ACFL. cents/MBtu
           	Prescreen	 35      50	70

           1.   All clean fuel                 168     113      71
           2.   All limestone scrubbers          6      25      48
           3.   Mixed limestone scrubbers
                and clean fuel                  438
           4.   Potential MgO-acid scrubbers     9      40      58
           5.   Potential MgO-acid scrubbers
                and clean fuel                	0     	6_     	2_
                                              187     187     187


Compliance Strategies Selected by Power Plants in Model Runs

     The market simulation model was run to determine which of the potential
acid-producing power plants would be viable candidates for marketing abate-
ment acid in competition with byproduct acid  from smelters.  A summary of the
distribution of strategies at the ACFL is shown in the following tabulation:

                                              ACFL. cents/MBtu

1.
2.
3.

4.
5.

Compliance strategy
All clean fuel
All limestone scrubbers
Mixed limestone scrubbers
and clean fuel
MgO-acid scrubbers
Mixed MgO-acid scrubbers
and clean fuel

35
168
7

4
8
0
187
50
113
41

7
24
2
187
70
71
77

10
29
0
187
                                      99

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     Many of the potential acid-producing plants identified in the scrubber
cost generator prescreen run used limestone scrubbing in the long-term
equilibrium model solution.  The switch from recovery to a throwaway method
resulted from the increased transportation costs at the higher abatement acid
production levels.  The potential production and marketing of abatement acid
for the power plants that selected MgO-acid scrubbing strategy in each of the
model runs is outlined as follows:
                                           ACFL. cents/MBtu
                                           35
50
                                                           70
              Potential production and   2,554   5,108   5,595
              marketing acid, ktons

     A listing of the specific power plants that chose the acid scrubbing
strategy in each of the three alternative clean fuel model runs is outlined in
Tables 35-38.  The tables include plant number, location, megawatts, Btu
scrubbed, and tons of acid produced.


             TABLE 35.  EIGHT POWER PLANTS SCRUBBING, PRODUCING,

                    AND MARKETING ACID IN $0.35 ACFL RUN

Plant No.
1395000250
3800000800
4510000100
4740000300
4770003000
4770004100
4815000400
4820001800
Total
Average
Location
North Carolina
Pennsylvania
Alabama
Florida
Kentucky
Tennessee
Ohio
Michigan


MW
2,286
1,600
910
1,136
2,558
2,550
1,831
2,462
15,443
1,930
Btu
scrubbed
99,526,110
100,763,230
54,170,170
71,443,680
121,162,120
12,853,680
132,159,990
141,227,650
733,357,630
91,669,703
Tons of
acid
105,209
241,426
68,824
250,963
628,358
572,320
254,335
433,206
2,554,641
319,330

      A geographic distribution of  the  187  power plants  included in the model
 runs is outlined in Figure 17.   This figure  also identifies  the plants that
 chose a clean fuel strategy in the $0.70/MBtu  ACFL model  run as well as the
 plants that chose a scrubbing strategy.   In  the latter  group of 116 plants,
 29 produced and marketed acid,  and 81  used a clean fuel strategy.   A tabula-
 tion of estimated scrubbing and clean  fuel use in compliance strategies is
 presented in Appendix M.
                                      100

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TABLE 36.  TWENTY-FOUR POWER PLANTS SCRUBBING, PRODUCING, AND




              MARKETING ACID IN  $0.50 ACFL RUN

Plant No,
070Q000.550
0785000500
0790000100
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
4045000900
4510001000
4530000850
4740000300
4770Q03000
4770004100
4815000400
4820001800
5125000650
5125000700
5250001400
5540000250
Total
Average
Location
New York
Illinois
Illinois
Illinois
North Carolina
Florida
Georgia
Georgia
Kentucky
New York
Pennsylvania
Pennsylvania
Indiana
Alabama
Texas
Florida
Kentucky
Tennessee
Ohio
Michigan
Missouri
Missouri
Virginia
Missouri


MW
1,200
590
602
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
1,062
910
634
1,136
2,558
2,660
1,831
2,462
1,150
1,100
845
527
32,172
1,341
Btu
scrubbed
50,142,240
23,955,530
29,939,960
66,538,760
99,576,110
50,383,440
72,759,860
88,005,410
56,196,800
80,571,790
27,815,880
100,763,230
59,604,720
54,170,170
25,742,050
71,443,680
121,163,120
128,536,880
132,159,990
141,227,620
47,372,990
51,037,800
42,656,150
20,774,340
1,642,528,550
68,436,690
Tons of
acid
75,016
77,549
96,692
281,208
105,209
192,742
253,367
255,939
148,978
126,735
72,342
241,426
147,606
68,824
95,195
250,963
628,358
572,320
254,335
433,206
67,997
176,480
68,606
108,149
4,799,242
199,968
                            101

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    TABLE 37.   TWO POWER PLANTS SCRUBBING,  PRODUCING, AND MARKETING ACID

                IN $0.50 ACFL RUN,  BUT ALSO USING CLEAN FUEL
Plant No.
3455000400
4805000200
Total
Total
Location
Indiana
Ohio
($0.50 run)
MW
660
1,263
1,923
34,095
Btu
scrubbed
34,148,090
47,675,290
81,823,380
1,724,351,930
Btu using
clean fuel
4,731,910
3,061,600
Tons of
acid
132,291
177,166
309,457
5,108,699
     Production and sale of byproduct acid was the least-cost compliance
strategy at all levels of clean fuel premium for seven of the power plants.
This indicates that the combination of production costs and proximity to
markets makes these plants the most stable candidates for use of recovery
technology.  They are presented graphically in Figure 24 and listed as follows:
Plant No.
1395000250
3800000800
4510000100
4740000300
4770003000
4770004100
4815000400
Location
North Carolina
Pennsylvania
Alabama
Florida
Kentucky
Tennessee
Ohio
Incremental
cost, $/ton acida
0.00
4.09
0.42
16.72
15.18
10.01
7.02
Tons of
acid
105,209
241,426
68,824
250,963
628,358
572,320
254,335
              Total
2,121,435
         a.  Additional unit cost of producing abatement acid as
             compared to limestone scrubbing.

However, at least two of these plants plan to use compliance methods that were
not included as alternatives in the study.

     A summary of model results for smelter and power plant sales to acid
plant demand points for all model runs is outlined in Table 39.  These results
show the potential quantity of power plant acid in relation to the total
market.  At the $0.70/MBtu ACFL, the potential for production of acid (abate-
ment capacity) at a cost below the ACFL premium fuel cost exceeded the market
demand (sales) for the acid by 5 Mtons.  All acid produced was marketed, but
only the lowest cost producers could compete with existing supplies; the
remainder  used limestone scrubbing.  At the $0.35/MBtu level, essentially all
of the acid that could be produced economically compared to purchase of
complying  fuel was sold.  The small differential in sales between the $0.50
                                      102

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TABLE 38.  TWENTY-NINE POWER  PLANTS  SCRUBBING,  PRODUCING, AND




              MARKETING ACID  IN  $0.70  ACFL RUN

Plant No.
0700000550
0785000100
0785000500
0790000100
1000000050
1095000200
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
3840000500
4045000900
4510000100
4530000850
4740000300
4770001900
4770002100
4770003000
4770004100
4815000400
5125000650
5125000700
5250001400
5540000250
Total
Average
Location
New York
Illinois
Illinois
Illinois
Texas
Ohio
Illinois
North Carolina
Florida
Georgia
Georgia
Kentucky
New York
Pennsylvania
Pennsylvania
Pennsylvania
Indiana
Alabama
Texas
Florida
Tennessee
Tennessee
Kentucky
Tennessee
Ohio
Missouri
Missouri
Virginia
Missouri


MW
1,200
616
590
602
836
1,255
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
940
1,062
910
634
1,136
1,482
1,723
2,558
2,660
1,831
1,150
1,100
845
527
36,562
1,261
Btu
scrubbed
50,142,240
24,933,140
23,955,530
29,939,960
33,943,780
63,971,180
66,538,760
99,576,110
50,383,440
72,759,860
88,005,410
56,196,800
80,571,790
27,815,880
100,763,230
31,096,200
59,604,720
54,170,170
25,742,050
71,443,680
72,402,030
85,504,880
121,163,120
128,536,880
132,159,990
47,372,990
51,037,800
42,646,150
20,774,340
1,813,152,110
62,522,486
Tons of
acid
75,016
126,448
77,549
96,692
125,523
379,768
281,208
105,209
192,742
253,367
255,939
148,978
126,735
72,342
241,426
72,786
147,606
68,824
95,195
250,963
301,246
223,146
628,358
572,320
254,335
67,997
176,480
68,606
108,149
5,594,953
192,929
                           103

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Figure 24.  Geographic distribution of the seven best power plant  candidates
              for production and marketing of abatement t^SO^.

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       TABLE  39.   SUMMARY OF MODEL RESULTS FOR SMELTERS AND

           POWER PLANT SALES TO ACID PLANT DEMAND POINTS

                           (ktons of H2S04)

                                          ACFL, cents/MBtu

Eastern smelters
Capacity
Sales
Demand points
Western smelters
Capacity
Sales
Demand points
Canadian acid
Capacity
Sales
Demand points
Total smelter acid capacity
Sales
Demand
Mixed demand points
Steam plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur to 1^804 plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur only
0

818
818
15

738
738
15

200
200
4
1,756
1,756
32*
11

-
-
-
-

32,237
30,481
69a
11
58
35

818
818
13

738
738
8

200
200
4
1,756
1,756
24a
13

2,635
2,554
31a
9

32,237
27,926
50a
8
42
50

818
818
12

738
594
3

200
200
2
1,756
1,612
16a
15

8,497
5,108
57a
16

32,237
25,516
35a
5
30
70

818
818
14

738
498
3

200
200
3
1,756
1,516
19a
13

10,758
5,595
56a
14

32,237
25,126
31a
4
28
a.  Steam plants and eastern and western smelters can supply a common
    demand point.
                                 105

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and $0.70/MBtu level of ACFL indicates that the market for byproduct  acid
from power plants was nearly saturated at 5 Mtons, or approximately 15%  of  the
total market.  Further substitution of byproduct acid in the existing market
would depend on substantial increase in the price of S; $60 was assumed  for
the study.

     An analysis of the distribution of byproduct acid is presented in the
following section.

Operating Profile for Power Plants Associated with Compliance Strategies
Proposed for 1978

     A summary of the operating characteristics of the plants that are candi-
dates for use of scrubbing and for production of abatement acid are outlined
in Table 40.

     In general, plants with a high scrubbing cost (and therefore good candi-
dates for buying clean fuel) had small, old boilers with a low capacity factor,
and burned fuel with a higher than average S content.  Plants with low-to-
average scrubbing costs tended to have the opposite characteristics,  i.e.,
large, newer boilers with a higher capacity factor, and a lower S content fuel
than the average burned by plants out of compliance.

     Power plants that were the best candidates for production of acid were
generally bigger, newer, and had a much higher capacity factor than scrubbing
candidates in general.  The best candidates had boilers more than three times
as large as the average plant out of compliance.  The following statements are
generally true of the best candidates for acid scrubbing systems:   (1) they
burn coal; (2) the boilers have an average capacity factor of >60%; (3)  the
average boiler size is >600 MW (<15% of the boilers are smaller than 200 MW);
and (4) they have very few old boilers (almost none >30 yr old), and most of
their boilers are <10 yr old.

     Two other factors not shown directly in Table 40 also have a significant
impact in determining the best acid-producing candidates.   Location is
critical, since even though the economics of scrubbing to produce acid may be
favorable, high transportation costs can offset the advantage of production
cost.   The emission standard promulgated for a given  plant is important;  unless
large quantities of S02 removal are required (implying very low allowable
emissions, very high emission levels,  or a combination of both), scrubbing to
produce acid is not usually the most economical method.

     Changes in ACFL are more significant for scrubbing candidates that  produce
acid than for scrubbing candidates in general since market distribution is
impacted as more and more plants are considered for acid scrubbing.   Location
factors are responsible for changing the mix as additional candidates are
brought into the solution.   For example, seven of the eight power plants
producing acid in the $0.35 ACFL run yielded demand points to relatively
higher cost plants in the $0.50 ACFL run.   A further  change in distribution
?at«nr™r!™Tlted ln the $°'7° ACFL run'  16 °f 24 P°wer Plants Producing acid
in ?0.50 ACFL run yielded demand points  to other plants even though all  other
characteristics were economically superior.


                                     106

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TABLE 40.  OPERATING CHARACTERISTICS OF POWER PLANT CANDIDATES FOR USE OF SCRUBBING TECHNOLOGY
Scrubbing cost, <:/MBtu

No. of power plants
No. of boilers
Total capacity, MW
Total fuel
Coal, ktons
Coal, GBtu
Oil, kbbl
Oil, GBtu
Gas, Mft3
Gas, GBtu
Average S content of coal, %
Average S content of oil, %
Average capacity factor, %
Average boiler generating capacity, MW
Age of boilers, %
0-5
6-10
11-15
16-30
>30
Size of boilers, %
<200
200-500
501-1000
>1000
Capacity factor of boilers, %
<20
20-40
41-60
>60
<35
19
69
25,642

54,688
1,242,134
33,246
204,605
10,173
14,685
2.12
0.85
57.64
372

22
20
14
26
18

46
19
28
7

15
.4
29
52
<50
74
290
84,716

171,365
3,888,782
79,600
494,105
14,976
20,303
2.63
1.33
49.33
292

17
17
9
35
22

52
24
22
2

20
3
39
38
<70
116
457
109,518

213,613
4,825,282
96,193
598,090
28,274
34,482
2.78
1.36
46.83
240

15
14
7
45
19

60
24
15
1

17
12
41
30
>70
71
376
23,081

13,167
299,793
13,974
88,810
79,965
82,486
2.87
1.50
20.90
61

3
6
5
38
48

97
4
1
0

57
24
14
5
Acid-producing plants at ACFL,
C/MBtu
35
8
27
17,581

42,242
975,606
0
0
0
0
2.46
N/A
65.61
647

41
26
7
22
4

11
26
44
19

4
0
30
66
50
26
101
40,383

84,231
1,912,380
22,118
137,750
3,213
3,270
2.68
1.71
43.00
400

32
21
5
15
27

38
21
36
5

28
2
41
29
70
29
106
43,259

89,712
2,007,277
23,022
143,263
463
520
2.85
1.74
49.33
408

31
20
6
31
12

33
31
31
5

12
5
58
25

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RESULTS AND ANALYSIS OF DEMAND POINTS FOR ABATEMENT BYPRODUCT ACID

     The demand analysis involves a detailed review of the 1978 acid plant
operating profile assumed in this study.  Each acid plant (90 total) has three
alternative strategies for obtaining supplies:  (1) buying elemental S from
Port Sulphur via a marketing terminal and converting to H2S04, (2) buying
byproduct acid from a smelter, and (3) buying abatement acid from a steam
plant.  The model assumes that the acid plant will close down in the second
and third strategies and buy abatement byproduct acid if it can be delivered
equal to or below the avoidable cost of production in the existing plant.  The
feedstock analysis for the 90 acid plants considered is outlined as follows:


                    Feedstock Analysis for 90 Acid Plants

                                           ACFL, cents/MBtu	
                                        0	35	50	70

         Buying Port Sulphur only      58      42      30      28
         Buying from smelters only     21      11       1       5
         Buying from steam plants
          only                          0      22      41      41
         Buying from Port Sulphur
          and smelters                 11       6       2       1
         Buying from Port Sulphur
          and steam plants              0232
         Buying from Port Sulphur
          and smelters and steam
          plants                        0001
         Buying from smelters and
          steam plants                  0       7      13      12

              Total acid plants        90      90      90      90


     The specific plants associated with each purchase option identified in the
model run in accordance with the above tabulation are outlined in Appendix N,
Tables 1-12.  The geographic distribution of acid plants buying elemental S
only versus plants purchasing abatement byproduct acid is presented in Figure
25.

Best Candidates for Purchasing Abatement Byproduct Acid

     Four significant factors that affect the purchase of abatement acid by
current producers of H2S04 in this study are listed as follows:  (1) size,
(2) age,  (3) compliance with clean air standards, and (4) location.  The first
three factors are reflected in the avoidable cost of production.  The location
factor relates to transport cost.

     Acid plants considered in the study range in size from 6,000 tons/yr to
2,260,000 tons/yr.   Size is a critical factor in the solution results.  No
plant larger than 500,000 tons/yr (28 plants) was a potential buyer of abate-
ment acid,  while all plants <75,000 tons/yr (24 plants) were potential buyers
of abatement acid in the model solutions (see Appendix 0, Table 1).

                                      108

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                                SULFUR-BURNING  ACID PLANTS
                                • ELEMENTAL SULFUR ONLY
                                  POTENTIAL BYPRODUCT DEMAND
                                  POINTS
Figure 25.  Geographic distribution of S-burning acid  plants (1978).

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     Size and age parameters are somewhat related since technological advance-
ments in 1960 made it feasible to build much larger t^SC^-producing facilities
(6000  ton/day units).  Most of the larger plants are located on the Gulf
Coast in close proximity to the S supplies.  Acid plants built after 1960 have
an average production of 1680 tons/day and represent 49% of the total number
of plants in the study; they represent 76% of the total production capacity of
all plants.  About one third of the abatement byproduct acid in the $0.70
ACFL model run was delivered to these plants and replaced only 10% of their
total production capacity.  A listing of the ownership of plants by size is
outlined in Appendix 0; plants that purchase acid in the model run are shown.

     The older plants built prior to 1960 include 46 plants with 24% of the
total production capacity for all plants.  The average size is 520 tons/day.
These plants use 67% of the abatement byproduct acid in the $0.70 ACFL model
run which replaces 64% of their total production capacity.

     Appendix P presents a listing of the 20 acid plants which are projected
to operate out of compliance with clean air standards in 1978.  The plants
that are purchasing abatement acid in the model runs are identified in Table
P-l.    As the ACFL is raised an increasing number of these plants buy abate-
ment acid because the economic incentive for producing acid at power plants
increases and production from more favorable locations is available.  Only 30%
are purchasing abatement acid at the zero ACFL where only smelter acid is
marketed.

     An analysis of the size of firm associated with production capacity is
shown in Appendix 0.  There are 42 firms with 90 S-burning acid plants with
production capacity of 32,227,000 tons/yr.  The 15 largest firms have 48 acid
plants  (54% of all plants) equal to 80% of the total production capacity of
all plants.  These plants buy 48% of the abatement byproduct acid in the $0.70
ACFL run, but it replaces only 13% of their production capacity.

     The 27 small firms have 42 acid plants equal to 20% of total production
capacity of all plants.  They buy 52% of abatement byproduct acid which
replaces 64% of their production capacity.

     Table 41 identifies acid plants that purchase abatement byproduct acid in
more than one of the model runs at given ACFL.  Most of such plants are older,
smaller, and generally more remotely located from the Gulf Coast supplies of S
as compared to the total population, but there are exceptions.  Unique
location advantage for across-the-fence operation can preempt other factors.

     In the model runs, all the acid produced by a specific power plant was
sold, but the supply did not exactly equal the demand at the points of use.
Therefore, the incremental demand was met through production of acid from S.
This incremental amount represents an additional quantity of byproduct acid
that could be sold at the values calculated in the model.  Specific power
plants and smelters that could supply this additional demand if production
could be increased (higher load factor or higher S coal), were identified and
are listed in Tables 13-16 of Appendix N.  A summation of the additional
amounts at each level of clean fuel premium is as follows:
                                      110

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  TABLE 41.   ACID PLANTS BUYING  ABATEMENT ACID IN MODEL  RUNS
ONE ACID PLANT BOUGHT BYPRODUCT ACID IN THE SMELTERS ONLY RUN .\NT>  IX THE 50e
AND 70C ACFL POWER PLANT RUNS.  DID NOT BUY BYPRODUCT ACID IN THE  35c RUN.
                                                           Avoidable
                                                           production
                                                             cost,
                                                             S/ton
	C_0_mEany_	Location	Capacity  Year _ of_ncid

                          Desoto      KS   105,000   1940     40.29
 No.
 114    U.S.  Industrial Chem
 17   ACID PLANTS  BUYING ACID AT $.35,  $.50,  AND  $.70 BUT NOT IN SMELTERS ONLY
 RUN
10
13
20
28
33
46
48
49
50
61
70
96
102
109
116
119
120
Allied Chemical
Allied Chemical
American Cynamid
Army Ammunition Plant
Borden Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
W. R. Grace
LJ & M LaPlace
Royster Company
Stauffer Chemicals
Swift Chemicals
USS Agri-Chem
Weaver Fertilizer
Acme (Wright) Fertili
Nitro
Front Royal
Hamilton
Radford
Norfolk
Richmond
North Bend
Deepwater
Cleveland
Charleston
Edison
Mulberry
LeMoyne
Norfolk
Navassa
Norfolk
Acme
WV
VA
OH
VA
VA
VA
OH
NJ
OH
SC
NJ
FL
AL
VA
NC
VA
NC
135,000
160,000
95,000
212,000
80,000
90,000
175,000
125,000
200,000
42,000
75,000
325,000
250,000
35,000
70,000
35,000
48,000
1940
1945
1967
1940
1937
1946
1956
1937
1937
1937
1967
1967
1957
1946
1967
1967
1968
38.03
35.94
36.76
35.95
38.06
37.27
42.41
36.21
43.25
42.51
34.40
35.60
35.06
44.28
38.72
44.55
36.22
 12 ACID PLANTS BUYING BYPRODUCT ACID AT $.50 AND $.70 BUT NOT AT $.35
  11   Allied Chemical
  40   Cities Service
  53   Essex Chemical
  56   Gardinier
  62   W.  R.  Grace
  74   Mobil Oil
  77   Monsanto Company
  83   Occidental Ag Chem
 114   U.S.  Industrial Chem
 131   U.S.  Industrial Chem
 134   E.  I.  Dupont
 136   USS Agri Chem
Hopewell
Augusta
Newark
Tampa
Bar tow
Depue
El Dorado
Plainview
Desoto
Tuscola
Linden
Wilmington
VA
GA
NJ
FL
FL
IL
AR
TX
KS
IL
NJ
NC
200,000
125,000
180,000
450,000
320,000
420,000
100 , 000
100,000
105,000
170,000
325,000
70,000
1965
1967
1956
1937
1960
1967
1960
1963
1940
1975
1937
1968
35.50
32.51
33.20
34.17
33.81
31.19
35.03
36.84
40.29
32.12
32.78
33.94
 2   ACID PLANTS BUYING BYPRODUCT ACID  AT  $.70 BUT NOT AT $.35 OR $.50
  18    American Cynamid
  86    Olin Corporation
                          Savannah    GA   216,000   1967
                          Baltimore   MD   350,000   1941
29.80
32.48
                              111

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        Additional Byproduct Acid Production and  Sales  to  Acid Plants

          Without Changing the Optimal Solutions  in  Each Model Run


                            Cents/MBtu	Tons

                                  0      1,283,000
                                 35        706,565
                                 50        668,623
                                 70        632,282


      The model could be refined to incorporate those additional quantities, but
 the  impact on validity of conclusions drawn from  the study does not justify the
 significant added cost.  The capability to identify  the supply points and
 potential quantities as was done in the study is  adequate.


 SUPPLEMENTARY ANALYSIS

 Summary of S02 Emissions Control Strategies to Meet Compliance

      Table 42 summarizes the reduction in S02 emissions by each compliance
 strategy for all of the 187 power plants that were projected to be out of
 compliance in 1978.  S02 control by clean fuel strategy accounts only for the
 reduction required by SIP standards.  Use of scrubbing technology reduces the
 emissions further than that required by the regulations because the removal
 efficiency and amount of gas treated cannot be practically matched with the
 standard.  A constant removal efficiency was assumed and gas volume was based
 on increments of standardized-size scrubber modules.  The column labeled
 "excess removed by scrubbing" shows the total amount for both  limestone and
 MgO  scrubbing.

 Clean Fuel Demand Curve

     The use of clean fuel as an alternative to scrubbing can  be presented
 graphically in the form of a demand curve.  This  demand curve  is estimated by
plotting limestone scrubbing cost for all power plant boilers  or combinations
of boilers from highest to lowest cost versus the reduction in emission
accumulated as shown in Figure 26.   Scrubbing cost is presented in cents/MBtu
and is the maximum premium that can be paid for complying fuel.

     At the upper end of the curve there are a few small power plants that only
exceed SIP requirements by a small amount yet the law requires  compliance by
either an FGD system or the use of clean fuel.   In this instance the  power
plant can pay a very high premium for clean fuel as an alternative to scrubbing.
In the flat part of the curve the economies to scale associated with  large
scrubber systems or large power plants burning medium- to high-S coal  reduces
 the unit cost of scrubbing to the point that a relatively lower premium can be
paid for clean fuel as an alternative to scrubbing.  As the cost of clean fuel
                                      112

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TABLE 42.  1978 STRATEGIES SELECTED FOR REDUCING EMISSIONS
                    (ktons/yr


ACFL,
cents/MBtu
OO
70
50
35
0

Total
by scrubbing
13,598
12,583
9,503
2,885
0
Amount
required
by SIP
9,912
9,211
6,788
1,919
0

By MgO
scrubbing
-
5,595
5,108
2,554
0

By limestone
scrubbing
-
6,988
4,394
330
0

By using
clean fuel
-
700
3,123
7,993
9,912

Total
reduction
-
13,284
12,627
10,878
9,912
Excess
removed
by scrubbing
-
3,371
2,714
965
0

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           1234



                REDUCTION IN SULFUR EMISSIONS, TONS xlO6
Figure 26.  Clean fuel demand  curve - all plants (1978).
                             114

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is reduced  the more clean fuel is used  in lieu of scrubbing.   No scrubbin
would  occur <$0.25/MBtu heat input based on the costs of technology  used in
this study.

Power  Plant Supply Curve Based on Incremental Cost for Production of
Abatement Acid

    The incremental cost of production for power plants producing acid as
compared to limestone scrubbing  in each of the ACFL model runs can be  presented
in graphic  form as a supply curve by  plotting incremental cost from  lowest to
highest versus the accumulating  acid  production for each increment.  This is
presented in Figures 27, 28, and 29.  The incremental cost represents  the net
revenue required to justify production  of acid.   The average  of the  incremental
cost is calculated at $ll/ton for the $0.35 ACFL, $10.65/ton  for the $0.50
ACFL,  and $10.97/ton for the $0.70 ACFL.

Transportation Cost Analysis

     The transportation cost analysis is outlined in the following tabulation:


                                ktons of H2S04

       ACFL,     Power      U.S.      Canadian           Transport
    cents/MBtu   plants   smelters    smelters   Total    cost, $    $/ton
0
35
50
70

2,623
5,370
6,069
1,556
1,556
1,412
1,312
200
200
200
200
1,756
4,379
6,982
7,585
13,513
41,311
64,371
72,919
7.70
9.43
9.22
9.61
     The data show that as the volume  of  acid increases the  total  costs of
 transportation increases proportionately.   The fairly constant  unit cost of
 transportation results from  change  in  distribution pattern as additional
 producers supply demand points with location advantages so that total costs
 are minimized.  This is illustrated by the  fact that the demand points changed
 for 16 out of 24 power plants in  the $0.70/MBtu ACFL run as  compared to the
 $0.50/MBtu run, and only two additional demand points were needed  for the five
 additional power plant supply points.

 Impact of Barge Transportation

     Barge transport was utilized in the  model to handle deliveries of molten
 S from Gulf Coast to marketing terminals  where truck or rail transport was
 used to reach acid plants, but only rail  transportation was  used to distribute
 abatement acid.  Numerous power plants are  located on navigable waterways.
 Barge transport would be a viable option  for shipping byproduct acid from these
 plants.   Barge transportation of  acid  could be included in the  model.  However,
 rates are not standard and a major  effort would be required  to  estimate
negotiated rates for all points.
                                      115

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   30
   20
in
o
u
z
u
Z
UJ
DC
u
z
10
               0.5        1.0        1.5        2.0        2.5

                 TONS OF SULFURIC  ACID PRODUCED x I06
                                                                3.0
   Figure 27.   Abatement acid supply curve for $0.35  ACFL model run.
                                   116

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 z
 o
 I-
 •N.
-w-
(O
o
o
z
Ul
z
Ul
cc
o
                   2468


                   TONS OF  SULFURIC  ACID PRODUCED x I06
10
   Figure 28.  Abatement acid supply curve for $0.50 ACFL model run.
                                      11?

-------
   80
o 60
-w-
O
0 40
UJ
2
UJ
K
S2 20
                I
          I
I
2         4          6          8         10
 TONS OF SULFURIC ACID PRODUCED x 106
                                                                   12
   Figure 29.  Abatement acid supply curve for $0.70  ACFL model run.
                                   118

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     An estimate of potential  savings by barge shipments was prepared for three
candidates for MgO-acid  scrubbing that are located on the inland waterway
system.


        Rail and Barge Shipments from Power Plants to 42 Acid Plants

                         on  the Inland Waterway System
FPC No.
4770003000
4770004100
4815000400
Location
Kentucky
Tennessee
Ohio
Tons shipped
628,358
572,320
254,355
Rate/ton
Average
Highest
Lowest
Average
Highest
Lowest
Average
Highest
Lowest
Rail, $
19.22
30.28
10.20
19.58
32.05
10.20
26.43
47.09
11.09
Barge, $
16.63
32.93
8.64
16.06
32.03
7.89
19.84
39.37
7.39
     The potential savings  for  utilizing barge shipment in three model runs,
 $0.35, $0.50, and $0.70/MBtu  ACFL,are presented in Table 43.

     The net reduction  in transport cost resulting from barge  transport for
 each of the model runs  is listed as follows:

                                      ACFL, cents/MBtu   	
                                   35	50	70

               Reduced cost, $   483,101   644,931   725,308

However, these results do not necessarily represent optimal  solution of a
linear programing model, even for the three plants  selected.  If the model were
actually run with the barge transport option the optimum production and distri-
bution of abatement acid could  change significantly.   The only conclusion that
can be made in the absence  of such a model run is that  transportation costs
would be lower.  Therefore,  the potential savings to both industries would be
greater as compared to model solutions presented in this study.

Sensitivity of the S Price

     One of the key inputs  in the analysis of the potential  market for abate-
ment byproduct acid is the  price of elemental S.  All of the results of this
study are based on S price  of $60/ton f.o.b.  Port Sulphur.   A $20-00 dejreaw
the price of S lowers the avoidable cost  of production  for H2S04 at each
respective acid plant by $6.11/ton of acid produced.   This ^£™wll as
structure would reduce the  quantity of both byproduct smelter acid as well


                                      119

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              TABLE 43.   COST REDUCTION BY BARGE SHIPMENT
 FPC
number
Location         At 35C/M ACFL
2.  4770003000   Kentucky

    10 Allied Chemicals

3.  4770004100   Tennessee

    16 American Cyanamid

4.  4815000400   Ohio

    10 Allied Chemical
    52 Eastman Kodak
                    Reduction
                    by barge
                    3.70/ton
                    0.26/ton
                                                      Tons
 97,330
  6,000
                                                                   Reduced
                                                                     cost
                    3.03/ton        37,670       114,140.00
                    0.28/ton        26,000         7,280.00
360,111.00
  1,560.00
                                  At 50C/M ACFL
 2.  4770003000   Kentucky

    96 Royster

 3.  4770004100   Tennessee

    126 American Cyanamid

 4.  4815000400   Ohio

    10 Allied Chemical
                    0.26/ton       134,350        34,931.00
                    2.21/ton        50,000       110,500.00
                    3.70/ton       135,000       499,500.00
                                  At 70C/M ACFL
 2.   4770003000   Kentucky

     62  W. R.  Grace
     96  Royster

 3.   4770004100   Tennessee

     96  Royster

 4.   4815000400   Ohio

     10  Allied Chemical
                    0.26/ton
                    0.26/ton
239,600
141,250
 62,296.00
 36,725.00
                     0.69/ton       183,750        126,787.00
                     3.70/ton        135,000       499,500.00
                                   120

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 the abatement acid from power plants  that can be marketed in  fh«
 estimate of the extent of reduction is  shown in Table 44   TK   moaei-  An
 plants  and acid plants affected are presented in Appendii Q    Spe°ltlc power

      The estimates were based on manual calculations rather than a m  i
 model run because the $40 S price  is  arbitrary and was Selected onlv 7
 the effect of price.   The above analysis shows that the quantity of  £°,
 byproduct acid that could be sold  in  the existing m£^ u    e  edt
 a significant amount.                                             reauced
 OTHER USES  OF THE MODEL

      The  development of data bases and programs  for use of the model to predict
 byproduct market potential resulted in capability  to perform other highly
 relevant  calculations.

 Investment  Costs

      The  scrubber cost generator may be used to  estimate the investment of
 alternative scrubbing systems for all existing and planned power plants.  In
 this  study,  costs were estimated for limestone,  MgO, and Wellman-Lord/Allied
 scrubbing systems for all plants projected to be out of compliance in 1978.
 For use in  the study, relativity of investment costs was the primary interest.
 However,  the input cost data could be refined to reflect special design
 considerations for specific plants to improve the accuracy of estimates not
 only  for  the plants included in this study but for the total current and
 future population.   This capability would be particularly helpful in evaluating
 conversion  from gas or oil to coal.  Moreover, the alternative methods  for
 compliance  could be expanded to include other scrubbing systems,  coal cleaning,
 production  of clean fuels from coal, or other advanced technology for use of
 coal.

     An example of  use  of the model to estimate  investment costs  is  shown
 below  in  the cumulative total capital required for limestone  scrubbing  for the
 187 plants considered in the study.


                          ACFL,          Investment
                        cents/MBtu   for scrubbing,  $

                            oo         6,937,543,000
                           70         5,501,613,000
                           50         4,058,091,000
                           35         1,079,165,000

Operating Costs

     The scrubber cost  generator  can  also  be  used to estimate operating costs
with the same degree  of  flexibility as  discussed  in the  investment cost
description.  For this  study, only  the  first  year operating costs were
estimated for the three  scrubbing methods  at  each plant  out of compliance.  If


                                      121

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TABLE 44.   EFFECT OF $20 REDUCTION IN S PRICE




   ON SUPPLY AND DEMAND FOR BYPRODUCT ACID

Reductions
At 35C clean
Supply: 2
4
Demand : 6
At 50c clean
Supply : 6
2
Demand : 10
At 70c clean
Supply: 8
2
Demand: 10
fuel alternative
power plants
smelters
acid plants
fuel alternatives
power plants
smelters
acid plants
fuel level
power plants
smelters
acid plants
Tons of acid

246,311
437,000
Total 683,000
683,000

639,722
498,000
Total 1,137,722
1,137,722

939,163
417,000
Total 1,356,163
1,356,163
                   122

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the  projected  load factors over the life  of  the  power plants were available
the  lifetime operating costs could be developed.   This information is necessarv
to estimate revenue requirements from present  worth costs  to cover the
additional cost of operation, including amortization of  investment.  A major
revision  of the model would be required to estimate revenue requirements
However,  a program in Fortran language is available from another study.

     The  estimated total first year operating  costs for  use of limestone
scrubbing and  clean fuel at the 187 plants defined earlier is as follows:
ACFL,
cents /MI
oo
70
50
35
Operating cost, $
5tu Scrubbing
2,886,245,000
2,037,721,000
1,513,241,000
406,877,000
Clean fuel
0
267,351,000
636,280,000
1,225,907,000
Total
2,886,245,000
2,305,072,000
2,149,521,000
1,632,784,000
     Use of clean fuel at some of  the plants  compared  to scrubbing at all
plants results in savings to the utility  industry  of:


                           ACFL,
                         cents/MBtu  Savings,  $

                            70        561,172,000
                            50        716,723,000
                            35       1,233,461,000

Change in Regulations

     The procedure for evaluating  compliance  status based on applicable
standards and FPC projection of fuel characteristics may be used to estimate
the effect of changing emission standards on  the cost  of compliance.  This
study was based on the SIP regulations  that were in effect as of June 1976.
The program would be useful in evaluating the cost use benefit of alternative
standards, provided that valid information could be developed for projecting
costs for these processes at various S02  removal efficiencies.  Also,
information is needed on economic  effect  of various emission rates.

Evaluation of Other Abatement Products

     The model can be modified to  include byproducts other than S and H2S04
and to evaluate potential for restructuring end use markets to take into
account location advantages.

Use of Transportation Model

     The transportation model that was  developed to distribute byproduct acid
from supply points to areas of use is a sophisticated  program that *as
potential for extensive use.  The  model calculates actual rate-base mileage

                                      123

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between any two points on the established railway network.   For  this  study,
tariffs were incorporated for 1^804 movements.  Available tariffs  for any other
commodity could be incorporated to calculate actual  transportation costs
between any two points.  The model can be used to estimate  cost  of rail ship-
ments for any of the materials that may be needed in compliance  programs
including coal, raw materials for scrubbing systems, byproducts  for disposal
or use, clean fuels derived from coal, and equipment.  Usefulness  of  the  model
in other areas of the industrial community is obvious.

     Truck and barge transportation costs are not as easily defined as rail
shipments but meaningful approximation could be developed to extend the
capability of the model.  A significant amount of work would be  necessary.

Social Cost Consideration

     An important conceptual use of the marketing model is  shown in Figure 30.
This figure is the classical presentation of economic benefit  to consumers of
a product (consumer surplus) and the benefit to the producer (producer surplus).
The use of the term surplus indicates that the action represented  results in a
reduction in resources required to match the supply with the demand.   The
combined economic benefit is defined as net social gain.  The  area under  the
demand curve DD' out to supply quantity Q (DRQS) is the total  gain to consumers
(acid plants) from the purchase of Q tons of l^SO^.  (It should  be recognized
that marketers cannot give preferential treatment to certain customers because
of antitrust laws; therefore, in the optimum solution, all  customers  pay  the
same price for abatement acid.)  Consumers pay a total of P $/ton  for Q tons
that results in a total cost represented by the rectangle (PSQR).   Similarly
this same total revenue pays for producing acid at the power plants where the
total cost for production is the area (RSQ) below the supply curve SS'  out to
supply quantity Q.  Consumer surplus is the indicated area  (DPR).   Producer
surplus is the area below P and above the supply curve as indicated (PRS).  At
equilibrium the most marginal consumer and producer neither gain nor  lose, but
all others in the solution have an economic advantage; net  social  gain is the
total savings by both.  Methodology used in this study does not  address
division of net social gain between producer and consumer.   It is  assumed this
will be determined in the market place.

     The above theory can be related to results of the study.  The linear
programing model summarized the least-cost solutions associated  with  each
model run.  The results are outlined in Table 45 entitled "Total Cost of  Acid
Production for Model Runs."  The reduction in total cost of acid is the net
social gain that results from productive use of abatement byproduct acid  in
the existing market.  Distribution of the savings between the  utility industry
and the acid industry will depend on negotiations between the  two.
                                      124

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0
o

o
a:
(O
UL
O

Ul
O

QL
Q.
           CONSUMER SURPLUS
                        PRODUCER
                        SURPLUS   '
                      QUANTITY OF SULFURIC ACID
Figure 30.  Conceptual  demand curve for I^S
            curve for  abatement production.
                                              and supply
                             125

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           TABLE 45.   TOTAL COST OF ACID PRODUCTION FOR MODEL RUNS

                                         	ACFL, cents/MBtu
        Acid industry cost, $	35	50	70

     Acid from S                    965,377,000   965,377,000   965,377,000
     Byproduct acid + acid
      from S                        885,043,000   846,421,000   842,500,000
     Reduction in cost of acid       80,335,000   118,956,000   122,887,000
Tons of acid utilized
Total from steam plants
Total from smelters
$/ton saving
4,379,000
2,623,000
1,756,000
18.34
6,982,000
5,370,000
1,612,000
17.04
7,585,000
6,069,000
1,516,000
16.20

CONCLUSIONS

     The overall objective of the study, to identify potential markets for
abatement byproducts from electric utility FGD systems,was accomplished.  In
the conduct of the study, a large volume of useful data was assembled and
procedures were developed for use of the information in the market studies and
in related work.

     The entire U.S. electric utility industry was characterized from FPC data
with respect to fuel type, capacity, load factors, and SQ2 emission rates.
Out of a total of 3,382 generating units at 800 power stations, 833 boilers at
187 power stations were projected to be out of compliance with current appli-
cable emissions regulations in 1978.  The total S02 emissions from these 187
plants was equivalent to 17.5 Mtons of 1^304; total H2S04 consumption in the
U.S. was estimated to be 32.2 Mtons in 1978.  Therefore, the total market is
nearly twice the potential byproduct production.

     A market simulation model was developed to estimate:

   1.  Potential quantity of byproduct resulting from recovery being the
       least-cost compliance method

   2.  Quantity of byproduct could be sold in a competitive market
       environment

   3.  Best power plant candidates for production

   4.  Most likely consumption points


Through use of a scrubber cost generating model, it was determined that lime-
stone scrubbing is generally the least-cost scrubbing method when credit for
byproduct sales is not included and when credit is applied, production of


                                     126

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byproducts becomes  competitive.  Costs for production of S bv rh<> n IT
Allied process were higher in all cases studied than production of J so"
Projected savings in  distribution costs for S compared to H,SO, did not^h-
set the incremental production costs.  Costs for use of the Wellman-Lon'/AH- A
technology will be  more  clearly defined during the current full-scale  d
stration, partially funded by EPA, at the Mitchell Station of the Northern""
Indiana Public Service Company.   Revised information will be included  in the
model.  Also, EPA is  currently sponsoring work with ESEERCO and Niagara Mohawk
to develop the Atomics International process for producing S from SO?  in stack
gas.  This technology and other work involving use of solid reductants could
lead to lower costs for  production of S as an alternative to producing H2SOA
Several factors that  are difficult to incorporate into a generalized economic
model could have a  significant influence on the choice of byproducts.  The
incentive for production of S is high because it is a safe, noncorrosive,
convenient material to handle, and can be easily stockpiled for long periods
of time at relatively low cost.   Because of the latter advantage,  S could be
incorporated more easily into the existing market.  Moreover, fluctuations
in market demand could be met with less impact to both the producer and con-
sumer.  It is likely  that a mix of marketable byproducts will ultimately
provide the least cost compliance with S02 regulations in the utility
industry.  Technology for production of S should be fully developed so that
the choice is available  and so that accurate information is available for
cost comparisons with other methods of control.

     An alternative to use of scrubbing was provided by comparing  the cost
of scrubbing with selected values of premium cost of complying fuel.  When
the clean fuel premium was set at $0.70/MBtu, the mix of least-cost compliance
methods was:
                    Purchase complying fuel    71 plants
                    Use  limestone scrubbing    87 plants
                    Produce byproduct acid     29 plants

The amount of acid  produced and marketed totaled approximately 5.6 Mtons; an
additional 5 Mtons  could have been produced at a lower cost than the alter-
native compliance method selected but could not  be sold in competition with
acid produced from  elemental S priced at $60/ton.  The simulation model was
designed to allow the nonferrous smelter industry to compete with  the utility
industry for byproduct markets.   The total byproduct acid supplied from both
industries was 7.11 Mtons or 22% of the total ^804 market.

     Power plants that were the best candidates  for production of  byproduct
acid were generally bigger, newer plants with high load factors.   The dis-
tinctive characteristics were:
   1.  Most boilers <10  yr old
   2.  Average size about 600 MW (<15% smaller than 200 MW)

   3.  Average capacity  factor about 60%

The average load factor  for potential acid-producing plants  was more than
three times as high as the average of all plants considered.

     When the clean fuel premium was set at $0.50 /MBtu .the amount of acid
supplied by the utility  industry was reduced to  5A Mtons   ^    acid
elemental S was reduced  from $60 to S40/ton, tne amount uj  yv
could be sold to replace production from existing conventional sources was
reduced from 5.6 to 4.2  Mtons.
                                     127

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     Abatement acid produced in the model run from the utility industry at the
$0.70/MBtu clean fuel premium was distributed to 55 different demand points in
23 states.  The current supply that was replaced by byproduct acid was
generally from smaller, older plants remotely located from the elemental S
production points.  The larger, more efficient plants generally can produce acid
at costs lower than the delivered cost of abatement byproducts.  However, there
are exceptions.  Savings in transportation cost because of location advantage
can offset production cost differential.

     The model assumed distribution of byproduct acid by rail shipment.  Several
of the potential producers are located on navigable waterways and could use
barge transportation.  As an example of possible savings on shipment costs,
estimates were made for barge shipments of selected production totaling 700,000
tons.  The cost differential between rail and barge transportation totaled
$725,000 or about $l/ton of acid.  This potential savings is 11% of the average
transport cost.

     The results of the study show that a significant amount of byproduct acid
produced by the utility industry could be incorporated in an orderly manner
into existing ^804 markets.  The control of S02 emissions in the utility
industry through use of recovery technology could contribute 56% of the
estimated total reduction needed for the industry to be in compliance.  Further
use of recovery technology will depend primarily on substantial increases in
elemental S prices which are difficult to predict.  Reduction in the cost of
control technology would also increase the potential for increased production
of byproducts, but the costs are not likely to improve significantly.  The
costs may be understated in this study because a 1975 basis (escalated to 1978)
was used for the investment and operating cost estimates.  Reduction in
transportation costs is a more realistic possibility for improving economics of
marketing byproduct acid.  Higher levels of clean fuel premium would not affect
the results since the acid supply at the maximum value studied exceeded the
demand.  It should be emphasized that some of the plants that are good
candidates for use of recovery technology may be implementing other compliance
plans.

     The development of data bases and programs for use of the model to predict
byproduct market potential resulted in capability to perform other highly
relevant calculations.

     The scrubber cost generator may be used to estimate the investment of
alternative scrubbing systems for all existing and planned power plants.  In
this study, costs were estimated for limestone, MgO, and sodium sulfite
scrubbing systems for all plants projected to be out of compliance in 1978.
For use in the study, relativity of investment costs was the primary interest.
However, the input cost data could be refined to reflect special design
considerations for specific plants to improve the accuracy of estimates not
only for the plants included in this study but for the total current and
future population.  This capability would be particularly helpful in evaluating
conversion from gas or oil to coal.  Moreover, the alternative methods for
compliance could be expanded to include other scrubbing systems, coal cleaning,
production of clean fuels from coal, or other advanced technology for use of
coal.

                                     128

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     The  scrubber cost generator can  also be used to estimate operating
with  the  same  degree of flexibility as  discussed in the investment  cost
description.   For this study, only the  first year operating costs were
for the three  scrubbing methods at each plant out of compliance  if  the
projected load factors over the life  of the power plants were available  the
lifetime  operating costs could be developed.  This information is necessary to
estimate  revenue requirements from present worth costs to cover the additional
cost  of operation, including amortization of investment.  A major revision of
the model would be required to estimate revenue requirements.

     The  procedure for evaluating compliance status based on applicable
standards and  FPC projection of fuel  characteristics may be used to estimate
the effect of  changing emission standards on the cost of compliance.  This
study was based on the SIP regulations  that were in effect as of June 1976.
The program would be useful in evaluating the cost to  benefit ratio of alternative
standards, provided that valid information could be developed for projecting
costs for these processes at various  S02 removal efficiencies.  Also, in-
formation is needed on economic effect  of various emission rates.

     The  model can be modified to include byproducts other than S and H2S04
and to evaluate potential for restructuring end use markets to take into
account location advantages.

     The  transportation model that was  developed to distribute byproduct acid
from supply points to areas of use is a sophisticated program that  has potential
for extensive  use.  The model calculates actual, legal mileage between any two
points on the  established railway network.  For this study, tariffs were
incorporated for H2SOA movements.  Available tariffs for any other  commodity
could be  incorporated to calculate actual transportation costs between any two
points.   The model can be used to estimate cost of rail shipments for any of
the materials  that may be needed in compliance programs including coal, raw
materials for  scrubbing systems, byproducts for disposal or use, clean fuels
derived from coal, and equipment.  Usefulness of the model in other areas of
the industrial community is obvious.

     An important finding was that while long-run competitive equilibrium
solutions predict what may happen in  competitive markets they do not identify
net social gain.  The linear programing model solutions present a running
account of minimum cost solutions associated with each model run for both
industries.  The savings to both industries at the $0.70/MBtu clean fuel
premium run resulting from absorption of abatement byproduct acid in the
existing  market amounted to $122,877,000 or $l6.20/ton of acid utilized.


RECOMMENDATIONS

     Information on current compliance  programs for existing power  plants and
for additional planned capacity was not available during the period of this
study. The results of the work show  that the potential for use of  «covery
technology is  good and the initial follow-on work should focus ™J%£»
where compliance alternatives are still flexible.  A survey of =«P^J  w
Plans should be carried out and the option of producing byproduct acid should
                                      129

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be evaluated by incorporating specific information on those plants into the
program data base.  This evaluation would be particularly helpful in the
planning process for future coal-fired power plants or for those that may be
required to convert from gas or oil to coal.

     In order for the program to remain meaningful, the data bases will have
to be updated periodically.  The period should be keyed to the annual FPC
report on the utility industry.  Investment and operating cost data on
alternative FGD technology should be refined to permit more accurate estimation
of emission control cost for specific plants and for the overall power industry.

     Use of the simulation models and the associated data bases is presently
limited to TVA personnel familiar with the complex program.  The program is
being documented and included along with procedures in a users manual that,
as a minimum, will define the capability of the system.   If the demand for
use of any part of the program justifies the expense, the files can be
maintained online so that qualified users can access the system through time-
sharing facilities.

     An extension of the program is planned, subject to availability of funds,
to evaluate effect of product end use pattern on market potential for by-
products.  For example, availability of byproduct H2S04 in the Midwest could
favor production of fertilizer materials near the point of use rather than
near the location of traditional raw materials.
                                     130

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                                  REFERENCES


 1.   Pearse, G.  H.  K.   Sulphur-Economics  and  New Uses.   Presented at the
     Canadian  Sulfur Symposium, May 30-June 1,  1974.   Industrial Mineral
     Section,  Minerals and Metals Division, Energy  Mines and Resources
     Canada, Ottawa, Ontario.                                         '

 2.   Federal Power  Commission.  Steam-Electric  Plant  Air and Water Quality
     Control Data,  for the year ended December  31,  1973,  based on FPC Form
     No.  67, FPC S-253, January 1976.  184 pp.

 3.   U.S. Department of Interior, Bureau  of Mines.  Sulfur in 1976.  Mineral
     Industry  Surveys, June 13, 1977.  17 pp.

 4.   Waitzman, D. A.,  J.  L. Nevins, and G. A. Slappey.   Marketing H2S04 from
     S02  Abatement  Sources — The TVA Hypothesis.   (TVA Bull. Y-71; EPA-650/2-
     73-051),  NTIS  PB 231 671, December 1973.   100  pp.

 5.   Corrigan, P. A.  Preliminary Feasibility Study of Calcium- Sulfur Sludge
     Utilization in the Wallboard Industry.  TVA report  S-466 (prepared for
     EPA), June  21,  1974.   66 pp.

 6.   Bucy, J.  I., J. L. Nevins, P. A. Corrigan,  and A. G. Melicks.   The
     Potential Abatement Production and Marketing of  Byproduct Elemental
     Sulfur and  Sulfuric Acid in the United States.   TVA report S-469 (pre-
     pared for EPA), March 1976.  100 pp.

 7.   McGlamery,  G.  G. , et al.  Detailed Cost Estimates for Advanced Effluent
     Desulfurization Processes.  (TVA Bull. Y-90; EPA-600/2-75-006) ,  NTIS  PB
     242  541/1WP, January 1975.  418 pp.

 8.   U.S. Department of Interior, Bureau of Mines.  Sulfur.  A Chapter  from
     Mineral Facts  and Problems, 1975 Edition.   Preprint from Bull.  667.   22 pp.

 9.   Nelson, C.  P.   A Look at Sulphur - Today and Tomorrow.  Paper  presented at
     Chemical Market Research Association Meeting,  New York,  March  1977.

10.   Hazelton, Jared E.  Economics of the Sulfur  Industry.  Resources for  the
     Future, Inc.,  Washington, D.C., 1970.

11.   Horseman, M. N.  J.  World Sulphur Supply and Demand, 1960-1980.  Document
     ID/76.  United  Nations, New York, 1973.   165 pp.
12.   Hicks, G.  C.,  et al.   Technical and Economic Evaluation of
     Intermediates  for Use by Developing Countries.  TVA Bull. Y-3 (prepared
     for AID),  1970.   54 pp.

13.   U.S. Department  of Commerce, Bureau of the Census.  Sulfuric Acid - 1976.
                                  Series M28A(76)-14, Supplement 1, June 1977.
    Current Industrial  Reports.   Series M28A(76)
    7 pp.
                                     131

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14.   Harre, E. A.  Records of the Economics Market Research  Section,  Division
     of Agricultural Development, Tennessee Valley Authority, Muscle  Shoals,
     Alabama.  TVA World Fertilizer Production Capacities  (from  Computer  Data
     File), 1975.

15.   Eckert, G. F.,  Jr.  Sulphur-Brimstone Demand Quickened  in  '76.   Eng.
     Mining J., 178(3):118-120, 122, March 1977.

16.   Harre, E. A.  The Supply Outlook for Phosphate Fertilizers.  TVA Bull.
     Y-96.  In:  Proceedings of the TVA Fertilizer Conference, Louisville,
     Kentucky, July 29-31, 1975.  pp. 36-44.

17.   U.S. Department of Agriculture, Crop Reporting Board of the Statistical
     Reporting Service.  Commercial Fertilizers, Final Consumption for Year
     Ended  June 30, 1976.  SpCr 7(77), April 1977.  30 pp.

18.   U.S. Department of Agriculture, Statistical Reporting Service.   Fertilizer
     Used on Selected Crops in Selected States, 1971.  February  9, 1972.  4 pp.

19.   Harre, E. A.  What's Ahead in Fertilizer Supply-Demand.  TVA Bull. Y-106.
     In:  Proceedings of the TVA Fertilizer Conference, Cincinnati, Ohio,
     July 27-28, 1976.  p. 18.

20.   Williams, G. G., J. R. Douglas, and E. A. Harre.  Fertilizer Oversupply—
     Not for Long.  In:  Proceedings of the 10th Hawaii Fertilizer Conference,
     Honolulu, April 25, 1977.  Cooperative Extension Service, University of
     Hawaii  (Misc. publication No. 146).

21.   Bixby, D. W.  Sulfur Requirements of the Phosphate Fertilizer Industry.
     The Role of Phosphorus in Agriculture, Soil Science Society of America,
     Madison, Wisconsin, 1978.  (In press)

22.   U.S. Department of Commerce, Bureau of the Census.  Inorganic Fertilizer
     Materials and Related Products - December 1976.  Current Industrial
     Reports.  Series M28B(76)-12, February 1977.  6 pp.

23.   U.S. Department of Commerce, Bureau of the Census.  U.S. Exports:
     Schedule B Commodity by Country.  Report No. FT 410/December 1976.
     April 1977.  603 pp.

24.   Harre, E. A., M. N. Goodson, and J. D. Bridges.  Fertilizer Trends - 1976.
     TVA Bull. Y-lll.  Tennessee Valley Authority, Muscle Shoals, Alabama,
     March 1977.  43 pp.

25.   Chemical Marketing Reporter, 207(13):40, March 31, 1975.

26.   Crenshaw, J. D., et al.  State Implementation Plan Emission Regulations
     for Sulfur Oxides:  Fuel Combustion.  (EPA-450/2-76-002) NTIS PB 251 174,
     March 1976.  74 pp.

27.   Federal Power Commission.  Steam-Electric Plant Construction Cost and
     Annual Production Expenses.  Twenty-Sixth Annual Supplement-1973, FPC
     S-250.  185 pp.

                                     132

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                                 APPENDIX A




                          BASIC SYSTEM  FLOW  DIAGRAM







                                  CONTENTS




Figures                                                                  Page
  w                                                                      -S£	



  A-l   Flow diagram for major system design requirements	   134




  A-2   Supply subsystem  	   135




  A-3   Transportation subsystem  	   136




  A-4   Demand subsystem  	   137



                                                                         i ^ft
  A-5   Linear programing model subsystem	   •L->0
                                      133

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               BYPRODUCT MARKETING MODEL
                       BASIC  SYSTEM
     SUPPLY
   DATA BASE
 POWER PLANTS,
  REGULATIONS,
 COST ESTIMATES
 TRANSPORTATION
   DATA  BASE
    TARIFFS
  RAIL MILEAGE
 BARGE MILEAGE
    DEMAND
   DATA BASE
      ACID
    PLANTS
 SCRUBBING
   COST
     GENERATOR
TRANSPORTATION
   COST
     GENERATOR
ACID  PRODUCTION
   COST
      GENERATOR
                      MARKET  SIMULATION
                           LINEAR
                        PROGRAMMING
                           MODEL
                         EQUILIBRIUM
                          SOLUTION
                           RESULTS
Figure A-l.  Flow diagram for major system design requirements.
                            134

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                                    FPC
                                 NEW PLANT
                                PROJECTIONS
                                    FOR
                                    1978
  FPC
FORM 67
 DESIGN
  DATA
                                 EPA
                                ENERGY
                                 DATA
                               SYSTEMS
                              DATA BASE
   OPERATIONAL
                                                  COMPLIANCE
                                                     DATA
                                                   SYSTEMS
                                                     DATA
                                                     BASE
         SUPPLY
       SUBSYSTEM
         DATA
         BASE
GEOGRAPHIC
  U.S.  BUREAU
  OF  MINES
SPECIAL REPORT
                               PEDCO
                              REPORTS
    ENGINEERING
       COST
    ESTIMATES
                   COST  FACTORS
                  AND  PARAMETERS
                        ALL SUPPLY
                      DATA  PROJECTED
                            TO
                            1978
INTERACTIVE
 TERMINAL
 INQUIRIES
    AND
 ANALYSIS
       SCRUBBING
         COST
       GENERATOR
              Figure  A-2.   Supply subsystem.
                             135

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         DOCKET
          28300
                                                 CENTRE
                                               GEOGRAPHIC
                                                  DATA
 SUPPLY
 POINTS
                   TRANSPORTATION
                    DATA  BASE
                                             BARGE
                                         TRANSPORTATION
                                              DATA
DEMAND
POINTS
INTERACTIVE
 TERMINAL
 INQUIRIES
   AND
 ANALYSIS
                   TRANSPORTATION
                        COST
                     GENERATOR
                                                        TRUCK POINTS
                                                        LATITUDES	
                                                        LONGITUDES
                                                        STANDARD POINT
                                                         LOCATOR CODES
                                                        PIPS  CODES
INLAND WATERWAY
 RATES	
DEEP WATER RATES
 FOR COASTAL
 LOCATIONS	
TERMINALS ON
 WATERWAYS
             Figure A-3.   Transportation subsystem.
                                  136

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                TVA
              WORLDWIDE
              FERTILIZER
              RELATED
                DATA
                BASE
COMPLIANCE
   DATA
  SYSTEMS
   DATA
   BASE
                             CENTRE
                           GEOGRAPHIC
                              DATA
                     SULFUR
                 TRANSPORTATION
                     DATA
    DEMAND
   SUBSYSTEM
     DATA
     BASE
      SULFUR
    TERMINALS
                         STANFORD
                         RESEARCH
                         INSTITUTE
                          REPORTS
      PRODUCTION
     COST  FACTORS
    AND PARAMETERS
  INTERACTIVE
   TERMINAL
   INQUIRIES
     AND
   ANALYSIS
NATIONAL
EMISSIONS
  DATA
 SYSTEMS
  DATA
  BASE
                          DEMAND DATA
                          PROJECTED  TO
                              1978
ACID PRODUCTION
     COST
   GENERATOR
               Figure  A-4.   Demand subsystem.
                              137

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I SUPPLY
DATA  AND
 COSTS
              TRANSPORTATION
                DATA AND
                  COSTS
                                  DEMAND
                                 DATA AND
                                   COSTS
          INTERACTIVE
           TERMINAL
           INQUIRIES
             AND
           ANALYSIS
    LINEAR  PROGRAMMING MODEL
                                                          ru
 REPORTS OF
    LINEAR
 PROGRAMMING
  SOLUTIONS
 AND RESULTS
 LINEAR PROGRAMMING
SOLUTIONS  AND RESULTS
FOR COMPUTER ANALYSIS
          Figure A-5.   Linear  programming model subsystem.
                               138

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           APPENDIX B




A MATHEMATICAL STATEMENT OF MODEL
                 139

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                                APPENDIX B

                     A MATHEMATICAL STATEMENT  OF MODEL
CURRENT MATHEMATICAL MODEL

Demand Sector

     i = 1, 2, . . . , n demand point numbers

    C^ = Avoidable cost at demand point i per ton of byproduct

    D^ = The quantity of byproduct which demand point i would purchase
         at price C^ or less


Utility Sector

     j = 1, 2, . . . , m utility supply point numbers

   CB. = Average cost per ton of byproduct for producing at utility
         supply point j to meet SIP compliance
   CL-: = Average cost in cents/MBtu of producing and disposing of
         limestone slurry at utility j to meet SIP compliance

   CF.: = Average cost in cents/MBtu of using the best  clean fuel
         alternative to bring utility j into compliance with SIP

  BTU. = The number of Btu input that would have to be scrubbed or
         cleaned to bring utility into compliance with SIP

    s.: = Tons of byproduct produced per Btu input that would have to
         be scrubbed to bring utility j into compliance with SIP

   CA-: = Average cost per ton of byproduct for the best alternative
         to byproduct production and marketing

       = Sj * MIN (CLj, CFj),  if out of compliance

       = 0,  if within  compliance

    S.: = Tons of byproduct produced to bring utility j into
         compliance with SIP

       = Sj * BTUj  (j = 1, 2,  .  . . , m)


                                     140

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Society
    J.  = Cost per ton of byproduct incurred by either the demand or
         supply sector in transferring a. unit of byproduct from
         utility j to demand point i
    j-
       = Tons of byproduct transferred from utility j to demand point i
   fj_  = Tons of byproduct used by demand point i from current source
         of supply
   TSC = Total social cost or total cost of implementing the
         Clean Air Act to both the utility and demand sectors.
           m
      ZCA.S. 4- MIN J
        3 1  (x  j
j = 1          1J
 Z  cixi«
                                            m
                                                    n
i = 1
                                         +  ^     V* (CB.-CA. + T. .)
                                            L,     L,   3   j     ij
                                            j  = 1   i =  1
   subject to:
                   m
                   X
                j = 1
                    n
               Xij   ^  Sj
                   i = 1
                        X. . > 0
                            —
                                       = L 2,  .  .  ., ro)
                                         (i = 0, 1, 2,  .  .  .  , n)
                                         (j = 1, 2,  .  .  .  , m)
                                     141

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                                APPENDIX C

               THE END-USE INPUT REQUIREMENTS FOR S AND H2S04


                                  CONTENTS

Table                                                                   Page
 C-l   Tons of Elemental S or Equivalent l^SO^ Required in
       Manufacture of One Ton of Indicated Product ..........    144
                                    143

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      TABLE C-l.  TONS  OF ELEMENTAL  S  OR EQUIVALENT H2S04 REQUIRED IN

               MANUFACTURE OF ONE TON OF INDICATED PRODUCT
                                                        Short
                                                    Tons of Sulfur
                                                    or Equivalent     Equivalent
                                                    Sulfur Per Ton       Tons
Product                                               of Producta      of
Fertilizers
   Diammonium phosphate  (DAP) 18-46-0 Grade             0.443b          1.355
   Granular triple  superphosphate  (GTSP) 0-46-0 grade   0.311b          0.951
   P205  in 547. ?2°5 wet  phosphoric acid                 0.943b          2.885
   Wet phosphoric acid  (547« P205)                       0.509b          1.557
   Granulated ammonium polyphosphate  (CAPP) 12-57-0     0.538b          1.646
   Normal superphosphate  (NSP) 0-20-0 grade             0.121           0.370
   Liquid fertilizer 11-37-0 grade                      0.646b          1.976
Sulfuric acid, 100%                                     0.338C          1.000
Synthetic fiber  intermediates
   Hydrogen cyanide (Modacrylic fiber)                  0.081           0.248
   Caprolactan (Nylon 6  fiber)                          1.019d          3.117
Acetate rayon (fibers, photographic film, etc.)         0.034           0.104
Synthetic rubber  (SBR)                                  0.005           0.015
Vulcanized synthetic rubber (SBR)                       0.012           0.037
Carbon disulfide  (fibers, cellophane, other chemicals)  0.936           2.863
Paper pulp                                              0.109           0.333
Indigo dye                                              0.297           0.909
Pheno-fonnaldehyde plastic moulding compound            0.0003          0.001
Phenol by sulfonation (plastics)                        0.441           1.349
Explosives
   Nitrocellulose                                       0.169           0.517
   Black powder                                         0.100           0.306
   Nitroglycerine                                       0.014           0.043
Lithopone paint pigment                                 0.105           0.321
Leather tanning
   Vegetable tan                                        0.007           0.021
   Chrome tan                                           0.076           0.232
Bordeau mixture  (4-4-50)  (fungicide)                    0.002           0.006
Treflan  (10070) (Herbicide)                              0.420           1.285
Alum, 177o A^OS  (water treatment chemical)              0.150           0.459
Sodium dichromate (tanning, dyeing, paint pigments, etc) 0.142           0.434
Uranium 235                                            18.090          55.341
Sodium sulfate (1007o)                                    0.226e          0.691
Ammonium sulfate (1007°)                                  0.243f          0.743
 All values are from Shreve, R.N. Chemical Process Industries 3rd Edition,
 McGraw-Hill Book Company, New York, 1967, unless otherwise noted.
 Unpublished TVA data.
cAverage of several published values.
dAnon. Chemical Week, June 26, 1974, p. 41.
eAssuming direct neutralization of sulfuric acid with sodium hydroxide
 with no losses.
^Assuming direct neutralization of sulfuric acid with ammonium hydroxide
 with no losses.

                                    144

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                                 APPENDIX D

                             FRASCH  S  PRODUCTION



                                 CONTENTS

Tables                                                       '           Page
  D-l    Frasch S Production - Effect of Natural Gas Cost on
          Production Cost of Frasch S for Various Plant Heating
          Water Capacities	   148

  D-2    Frasch S Production - Effect of Plant Heating Water
          Capacity on Total Capital Investment 	   149

  D-3    Frasch S Production - Effect of Natural Gas Cost on
          Operating Cost for Various Water Rates 	   150
                                    145

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                                 APPENDIX D

                             FRASCH S PRODUCTION
TECHNOLOGY

     Wells which vary in depth from 200-2000 ft are sunk into a S dome using
a method similar to that of sinking oil wells.  The most economical way to
get S out of the dome formation is to melt it and pump it out.  This involves
the use of superheated water at 330°F which is pumped into the dome.

     The well consists of three concentric pipes and a casing.  Inside the
casing an 8-in. pipe is sunk through the cap rock over the dome to the bottom
of the S deposit.  Its lower end is perforated.  A 4-in. pipe is lowered to
within a short distance of the bottom.  Last and innermost is a 1-in. pipe
for compressed air reaching more than halfway to the bottom of the well.  The
superheated water is forced down the space between the 8- and 4-in. pipes and
out into the S-bearing formation where it melts the S.  The molten S collects
at the bottom of the well where the pressure of the water forces it part of
the way up the 4-in. pipe.  The compressed air from the 1-in. pipe aerates
and lightens the liquid S so that it will rise the rest of the way to the
surface.

     Once on the surface the hot, yellow S is pumped to a relay station for
air removal and then either to heated tanks for storage in liquid form or to
vats where it cools and solidifies.  At this point, it is ready for marketing.
ECONOMICS

     The primary information source for S mining economics is Jared E.
Hazleton's  The Economics of the Sulfur Industry,  published by Resources for
the Future, The John Hopkins Press, Baltimore and London, 1970.  Investment
costs given by Hazleton were updated to the third quarter of 1974 and mid-
1978, as were the costs of labor, supervision, and utilities.  The costs
given exclude loading, royalties, and severance taxes.  They also exclude all
costs of exploration and development.  They do include the drilling of new
production wells since, on the average, one well will only produce for
approximately 1 yr and will mine S from about 1/2 acre of a S dome.

     The cost of mining Frasch S is very dependent upon the hot water rate
associated with each mine, where the water rate is defined as the number of
gallons required to produce 1 ton of S.  The water rate varies drastically
frcm mine to mine because, of the widely divergent geological nature of S-
containing salt domes  (mines).  Since the water is usually heated with
natural gas, mining costs are very sensitive to the price of natural gas.


                                      146

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Within the framework of the third quarter 1974 estimates,  the cost  of natural
gas was varied from $0.20-$3.00/kft3 with an  intermediate value  of  $1.00/kft3.
The $0.20/f t3 rate  is typical of existing contracts  for old  gas, the  $1.00
rate is about that presently being paid under more recent  contracts,  and  the
$3.00 figure is a projected rate.  For the mid-1978  estimates,  the  cost of
natural gas was pegged at $2.50/kft3.
DISCUSSION OF RESULTS

     Using a constant water per ton of S rate of 1,600 gal, total heating
water rates were varied for S production rates of 218,750, 875,000, and
1,750,000 long tons (LT)/yr.  Costs were also estimated for a production rate
of 350,000 LT/yr of S at a water rate of 4,000 gal of water per ton S, and
a production rate of 155,400 LT/yr of S at a water rate of 9,000 gal of water
per ton of S with a constant total heating water rate of 4 Mgal/day for both
cases.  It is felt that these ranges  adequately represent the various Frasch
S mining operations in the U.S. now and in the foreseeable future.

     From the data in Table D-l, it can be seen that for mines with identical
water rates (1600 gal/LT) the unit operating cost for the third quarter of
1974 for mining Frasch S decreases with increased mining rates and, of course,
plant size.  At a natural gas price of $1.00/kft^, the unit cost decreases
from $18.19/LT at a production rate of 218,750 LT/yr to $11.47/LT at a produc-
tion rate of 1,750,000 LT/yr.  Similar reductions are shown for mid-1978 costs.
The marked sensitivity of operating costs to the price of natural gas is also
shown in Table D-l.

     The effect of plant heating water capacity and plant capacity upon total
capital investment is shown in Table D-2, where the investment required per
long ton per year decreases from $24.69 at a production rate of 218,750 LT/yr
to $14.81 at a production rate of 1,750,000 LT/yr for third quarter 1974 costs.

     In Table D-3 the effect of water rate and price of natural gas on cost
of production for a mine having a capacity of 4 Mgal of water per day is
given.  These data show that as the water rate increases from 1600 to 9000
gal/LT at a natural gas cost of $1.00/kft3, the operating cost for the third
quarter of 1974 increases from $12.71 to $71.57/LT.  Similar increases are
shown for mid-1978 costs.
                                     147

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         TABLE D-l.  FRASCH S PRODUCTION -

 EFFECT OF NATURAL GAS COST ON PRODUCTION COST OF

FRASCH S FOR VARIOUS PLANT HEATING WATER CAPACITIES

           (Water rate:  1600 gal/LT S)


S production    Plant capacity,   Operating cost,
rate, LT/yr    gal of water/day	$/LT of S
Third Quarter 1974 Costs
           Natural Gas Cost:  $0.20/kft3
    218,750
    875,000
  1,750,000
1,000,000
4,000,000
8,000,000
13.68
 8.25
 7.05
           Natural Gas Cost:  $1.00/kft3
218,750
875,000
1,750,000
1,000,000
4,000,000
8,000,000
18.19
12.71
11.47
           Natural Gas Cost;  $3.00/kft3
    218,750
    875,000
  1,750,000
1,000,000
4,000,000
8,000,000
29.45
23.86
22.51
Mid-1978 Costs
           Natural Gas Cost:  $2.50/kft3
    218,750
    875,000
  1,750,000
1,000,000
4,000,000
8,000,000
30.04
23.07
21.42
                         148

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                 TABLE D-2.  FRASCH S PRODUCTION -

EFFECT OF PLANT HEATING WATER CAPACITY ON TOTAL CAPITAL INVESTMENT

                   (Water rate:  1600 gal/LT S)


S production    Plant capacity,   Total capital   Capital invest-
rate, LT/yr	gal of water/day   investment, $    ment, $/LT/yr


Third Quarter 1974 Costs

    218,750       1,000,000         5,400,000         24.69
    875,000       4,000,000        16,992,000         19.42
  1,750,000       8,000,000        25,920,000         14.81


Mid-1978 Costs

    218,750       1,000,000         6,939,000         31.72
    875,000       4,000,000        21,835,000         24.95
  1,750,000       8,000,000        33,307,000         19.03
                                149

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      TABLE D-3.  FRASCH S PRODUCTION -

EFFECT OF NATURAL GAS COST ON OPERATING COST

          FOR VARIOUS WATER RATES

(Plant heating water capacity:  4 Mgal/day)


Water rate,   S production   Operating cost,
  gal/LT      rate, LT/yr	$/LT	
Third Quarter 1974 Costs
        Natural Gas Cost:  $0.20/kft3
   1,600
   4,000
   9,000
875,000
350,000
155,400
   1,500
   4,000
   9,000
875,000
350,000
155,400
  8.25
 20.64
 46.44
        Natural Gas Cost:  $1.00/kft3
 12.71
 31.82
 71.57
        Natural Gas Cost:  $3.00/kft3
1,600
4,000
9,000
875,000
350,000
155,400
23.86
59.76
134.41
Mid-1978 Costs
        Natural Gas Cost:  $2.50/kft3
   1,600
   4,000
   9,000
875,000
350,000
155,400
 23.07
 57.78
129.97
                      150

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                                 APPENDIX E

                         S  STORAGE TERMINAL OPERATION


                                 CONTENTS

Table                                                                   Page

  E-l    S Storage Terminal Operation - Effect of Throughput
          Capabilities on Total Capital Investment and Operating
          Costs	154
                                    151

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                                 APPENDIX E

                        S STORAGE TERMINAL OPERATION
TECHNOLOGY

     The liquid S from the mines is pumped through insulated and steam-heated
carbon steel pipe lines directly to terminals where it is stored either as
a liquid in insulated and heated welded carbon steel tanks or to outdoor vats
where it is cooled and solidified.  Steam coils at pressures between 35 and
70 psig are used to maintain the molten S in the tanks at temperatures between
260 and 270°F (126-133°C).  From the marketing terminal, the molten S is
transported by barge, truck, or rail directly to the point of consumption in
insulated vessels.

     The solid S in the vats is broken out by modified bulldozers or power
shovels.  If it is to be reshipped as a solid, it is moved by conveyor belts
to conventional road, rail, or water carriers.  This method of reclaiming
solid S generates considerable S dust which not only represents a monetary
loss but has an adverse effect upon the environment.  For this and other
reasons such as contamination of the solid S during handling and shipping in
dirty equipment, most S shipments are now made in the molten state.  The dust
problem may be minimized somewhat by processing the molten S into solid slates
or prills for stockpiling and reclaiming.  However, in the present study the
cost of shipping solid S is based on reclamation from vats as described above.


ECONOMICS
     The primary information source is  World Sulfur Supply and Demand, 1960-
1980  published in New York by the United Nations Industrial Development
Organization, Vienna.  Much valuable information was also obtained from
"Technical and Economic Evaluation of Fertilizer Intermediates for use by
Developing Countries" prepared for the Agency for International Development
by TVA (TVA Bulletin Y-3).

     Investment costs given in the above publications were updated to the
third quarter of 1974 and mid-1978 as were the costs of labor, supervision,
and utilities.  In all cases the annual throughput was taken as four times
the primary storage capacity.  Costs were estimated for primary storage
capacities of 20,000, 40,000, and 60,000 LT, giving annual throughputs of
80,000, 160,000, and 240,000 LT respectively.  Costs were estimated for
terminals receiving solid S and redelivering 60% of the S as a liquid and
terminals receiving all S in the liquid form and redelivering as the liquid.
Solid S storage capital costs include site preparation, foundations, and cost
of handling facilities such as conveyors.  Liquid S storage costs  include
tanks (excluding piling), all onsite lines, valves, meters, etc.,  but not
delivery or discharge lines beyond battery limits.  Tank capacities and hence
costs are based on standard units 40 ft high with varying diameters.

                                    152

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     Except for the terminal with a throughput of 240,000 LT/yr  (60% of the
S delivered as a liquid), one melter of the appropriate size was considered
the most economical.  In the 240,000 LT/yr terminal, two melters were
assumed.  All terminals receiving solid S were assumed to reship 60% of the
throughput as liquid.

     For those terminals receiving and delivering molten S only, the terminal
with the annual throughput of 80,000 LT/yr was assumed to have two storage
tanks holding 10,000 LT each; the terminal with the throughput of 160,000 LT
was assumed to have two tanks holding 20,000 LT each; the terminal with a
throughput of 240,000 LT was assumed to have two tanks holding 30,000 LT each.
DISCUSSION OF RESULTS
     As shown in Table E-l,  increasing the size of the terminals decreases the
unit storage costs.  For those terminals which receive solid S and redeliver
60% of the S in the molten form, the estimated costs as of the third quarter
of 1974 are $4.67/LT for a terminal with an annual throughput of 80,000 LT,
$3.71/LT for a throughput of 160,000 LT, and $3.26/LT for a throughput of
240,000 LT.  Capital costs in dollars per long ton per year are $9.00, $7.20,
and $6.87 respectively.

     The terminals which handle only molten S have even lower costs, resulting
primarily from the elimination of the labor- and maintenance-intensive solid
S handling operation.  For these terminals the estimated costs, as of the
third quarter of 1974, are $4.14/LT for an annual throughput of 80,000 LT;
$2.85/LT for a throughput of 160,000 LT, and $2.47/LT for a throughput of
240,000 LT.

     Greater throughput rates, up to eight times the primary storage capacity,
are possible in S terminal operations.  These greater throughput rates would
significantly decrease unit operating and capital costs.
                                      153

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            TABLE E-l.   S STORAGE TERMINAL OPERATION -

        EFFECT OF THROUGHPUT CAPABILITIES ON TOTAL CAPITAL

                  INVESTMENT AND OPERATING COSTS


Throughtput,   Total capital   Capital investment,   Operating cost,
   LT/yr	investment, $	$/LT/yr	$/LT of S


Third Quarter 1974 Costs


      Terminals Receiving Solid S and Redelivering 60% Liquid

   80,000          720,000            9.00                4.67
  160,000        1,151,700            7.20                3.71
  240,000        1,648,390            6.87                3.26


          Terminals Receiving and Redelivering All Liquid

   80,000          647,840            8.10                4.14
  160,000          820,600            5.13                2.85
  240,000          928,568            3.87                2.47


Mid-1978 Costs


      Terminals Receiving Solid S and Redelivering 60% Liquid

   80,000          925,200           11.57                6.36
  160,000        1,479,900            9.25                5.11
  240,000        2,118,200            8.83                4.56


         Terminals Receiving and Redelivering All Liquid

   80,000          832,500           10.41                5.90
  160,000        1,054,500            6.59                4.26
  240,000        1,193,200            4.97                3.78
                               154

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                                APPENDIX F

         PRODUCTION,  STORAGE,  AND RETROFIT OF EMISSION CONTROLS

                      TO H2S04  PLANTS USING ELEMENTAL S


                                 CONTENTS

Tables                                                                  Page

  F-l    H2S(>4 Production from Elemental S - Effect of Acid Plant
          Capacity on Total Capital  Investment and Operating Costs
          for Single Contact-Single  Absorption (SC-SA) and Dual
          Contact-Dual Absorption  (DC-DA) l^SO^ Plants ........    158
  F-2    H2S(>4 Storage Terminal Operation - Effect of Throughput
          Capabilities on Total Capital Investment and Operating
          Costs  ...........................    161

  F-3    Retrofit of Emission Controls to H SO^ Plants Using
          Elemental S - Effect of Acid Plant Capacity on  the Total
          Capital Investment for Emission Control Systems   ......    165

  F-4    Retrofit of Emission Controls to H2S04 Plants Using
          Elemental S - Effect of Acid Plant Capacity on  the
          Operating Costs of Emission Control  Systems  ........    166
                                     155

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                                 APPENDIX F

           PRODUCTION, STORAGE, AND RETROFIT OF EMISSION CONTROLS

                      TO H2S04 PLANTS USING ELEMENTAL S


H2SC>4 PRODUCTION FROM ELEMENTAL S

Technology

     Basically H2S04 is produced by burning S or S-bearing materials to form
S02-  The S02 is oxidized by air in the presence of a catalyst to form sulfur
trioxide  (803) which combines with water vapor to form 112804.

     The various sources of S02 for manufacture of H2S04 include (1) elemental
S,  (2) pyrites  [sulfide ores of iron (Fe), Cu, Pb, or Zn], (3) t^S from sour
gas or petroleum,  (4) S-bearing ores of volcanic origin, (5) waste gases from
metallurgical refining operations, and (6) waste gases from combustion of
S-containing fuels.  This study is concerned only with the production of acid
from elemental S.  In addition to the S02 source alternatives listed above,
there are also alternate methods of conversion of S02 to 803.

     There are two principal processes for conversion of S02 to the trioxide
form:  the chamber and the contact processes.  The older chamber process which
was introduced in  the 18th century uses nitrogen oxides  (NOX) as the oxygen-
carrying catalyst  for the conversion of S02 to 803.  The reactions which
produce the 803 and H2S04 take place either in huge lead chambers or packed
towers.

     The modern contact process facilitates conversion of S02 to 803 by use
of a metal or metal-oxide catalyst.  The 803 is then passed through an absorp-
tion tower where it is absorbed in recirculating concentrated acid.  The major
advantages of the  contact process are that concentrated acid of high purity
can be produced directly and compact plants of high capacity are feasible.
Plants of 1000 ton/day capacity are now rather commonplace and plants having
capacities of 2000 tons/day and above have recently been constructed.  Very
few of the old chamber process plants are still in operation in the U.S. and
the vast majority of plants use the more efficient contact process.  For this
reason, the present study is confined to ^804 produced by the contact process.

     Contact H2S04 plants built prior to 1960 average 95.5% conversion of
elemental S to ^804.  Plants built after 1960 are more efficient with 97%
conversion.   However, neither of these classes of plant can meet present
emission standards which require a conversion efficiency of 99.7%.

     Those existing contact plants which fail to meet emission standards are
of the single contact-single absorption type; i.e., the gas stream containing
the 802 fr°m the S burner is passed through a converter where, in contact with


                                    156

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the catalyst, the SC>2 is oxidized to 803 and  the oxidized  gases are passed
through an absorber where most of the 803  is  removed  to  form  acid.  However,
the tail gas leaving the absorber contains too much unconverted S02 to meet
emission standards,  One method of solving this problem  is  to pass the gases
from the absorber through a second converter  and a second absorber.  This
second conversion and absorption results in an overall conversion efficiency
of 99.7% or greater, thus meeting emission standards.  Existing single contact-
single absorption plants can be retrofitted with an additional converter-
absorber system to enable them to meet emission standards.  Other systems are
also available for this purpose and will be discussed in another section of
this report.  Virtually all new H^SO^ plants  are built with two converter-
absorber systems in series in order to meet emission  standards; these are
called dual contact-dual absorption plants.   Cost data for both types of
plants have been developed.

Economics

     Monsanto Enviro-Chem Systems, Inc., The  Ralph M. Parsons Company, and
Davy Powergas, Inc., were the primary sources of capital cost data and utility
and labor requirements for both the single contact-single absorption and the
dual contact-dual absorption plants.  Other valuable  information was obtained
from  Chemical Process Industries  by R. Norris Shreve, McGraw-Hill Book
Company;  The Economics of Su~l:furic Acid Production   prepared for the Agency
for International Development by TVA (TVA Bulletin"Y-28);  The Fertilizer
Manual  published by the United Nations Industrial Development Organization,
New York; and  The Manufacture of Sulfuric Acid  edited by Werner W. Duecker
and James R. West, Reinhold Publishing Corporation, New York.

     Investment costs from the above sources  were calculated  for the third
quarter of 1974 and mid-1978, as were the costs of labor, supervision, and
utilities.  The cost of S was excluded from the estimates because of its
variability.  Credit for byproduct steam was  included.  Investment costs
include capital costs for 30 days' storage of acid and S for  each plant size
investigated.

     Costs for single contact-single absorption plants having capacities of
50, 100, 250, 750, and 1500 tons/day of 100%  H2S04 were estimated as well as
costs for dual contact-dual absorption plants having  capacities of 100, 250,
750, and 1500 tons/day.  Costs for dual contact-dual  absorption plants of
50 ton/day capacity were not estimated as  it  is doubtful if plants of such
small capacity will ever be built.  All plants were assumed to operate 330
days/yr.

Discussion of Results

     As with most chemical plants there is a  decided  unit  cost advantage with
increasing capacity.  Although this cost advantage is substantial at all
levels of capacity explored, it decreases with increasing  size of the acid
plant as shown in Table F-l.
                                     157

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                TABLE F-l.   H2S04 PRODUCTION FROM ELEMENTAL S -




   EFFECT OF ACID PLANT CAPACITY ON TOTAL CAPITAL INVESTMENT AND OPERATING




             COSTS FOR SINGLE CONTACT-SINGLE ABSORPTION (SC-SA)




            AND DUAL CONTACT-DUAL ABSORPTION (DC-DA)  H2S04 PLANTS

Acid plant
capacity,
tons of 100%
H?SOA/day
Third




1,
Quarter
50
100
250
750
500
Total capital
investment, $
SC-SA
DC-DA
Capital investment,
$/ton
of 100% H?SOA/yr
SC-SA
DC-DA
Operating cost,
$/tona
of 100% H2SO£
SC-SA
DC-DA
1974 Costs
2,737
3,220
4,913
9,494
14,600
,000
,000
,800
,500
,800
—
3,942,000
6,443,000
11,211,000
18,088,000
165.
97.
5£.
38.
29.
88
58
56
36
50

119
78
45
36
-
.45
.10
.30
.54
41.
23.
12.
7.
4.
06
13
92
10
85
-
26.35
15.44
7.33
5.00
Mid-1978 Costs




1,
50
100
250
750
500
3,517
4,138
6,314
12,200
18,762
,000
,000
,000
,000
,000
-
5,065,000
8,279,000
14,406,000
23,243,000
213.
125.
76.
49.
37.
15
39
53
29
90

153
100
58
46
—
.48
.35
.21
.96
51.
29.
16.
8.
5.
96
11
10
68
80
—
33.26
19.16
8.76
5-76

a.  Does not include the cost of S.
                                    158

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     For example, for single contact-single absorption  plants  built  in  the
third quarter of 1974, the capital  investment  required  in  terms  of dollars
per ton of 100% t^SO/^/yr is $165.88 for a  50 ton/day  plant  and  $29,50 for a
1500 ton/day plant, while the unit  capital  investment for  a 750  ton/day  plant
is $38.36, only $8.86/ton of acid per day greater than  that for  the  1500 ton/
day plant.  First year operating costs (excluding S) for single  contact-single
absorption plants built in the third quarter of 1974 are $41.06/ton  of 100%
H2S04 for a 50 ton/day plant and $4.85/ton for a 1500 ton/day plant, while
the operating cost for a 750 ton/day plant is  $7.10/ton, a  difference of only
$2.25/ton greater than that for the 1500 ton/day plant.   These trends can
also be seen in the data for dual contact-dual absorption plants.

     The data given above also show that dual contact-dual  absorption plants
are more costly to build and generally more costly to operate even though
they have a somewhat higher S recovery efficiency than  single contact-single
absorption plants (an exception will be discussed below).   For example,  the
capital investment required in terms of dollars per ton of  100%  K^SO^/yr for
100 ton/day planes built in the third quarter of 1974 is $97.58  for a single
contact-single absorption plant and $119.45 for a dual  contact-dual absorption
plant.  First year operating costs  (excluding S) for a  100  ton/day plant
built in the third quarter of 1974 are $23.13/ton of 100% H2SC>4  for a single
contact-single absorption plant and $26.35/ton for a dual contact-dual
absorption plant, while the operating costs for 1500 ton/day plants are $4.85/
ton for a single contact-single absorption plant and $5.00/ton for a dual
contact-dual absorption plant.

     The major factor contributing to the decreasing difference  in operating
costs between single contact-single absorption and dual contact-dual absorption
plants with increasing size is the greater thermal efficiency of the larger
dual contact-dual absorption plants.  The higher thermal efficiency of these
plants results in the production of more byproduct steam for which an operating
cost credit can be taken.  This proportionately larger byproduct steam genera-
tion credit, coupled with the relatively higher credit value for this commodity
in mid-1978 as contrasted with the projected values of  the  other utilities,
actually results in a slightly lower operating cost for a 1500 ton/day dual
contact-dual absorption plant than the same sized single contact-single
absorption plant in mid-1978, i.e., $5.76/ton for the dual  contact-dual
absorption plant versus $5.80/ton for the single contact-single  absorption
plant.  The operating costs before steam credits are taken  are $8.52/ton and
$7.90/ton respectively.  However, since single contact-single absorption
plants will not be built in mid-1978 unless emission standards for H2S04
plants are greatly relaxed, this comparison between the two  types of plants
is of academic interest only.
                                     159

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H2SO,  STORAGE TERMINAL OPERATION


Technology

     Concentrated (93-98%) H2S04 is usually stored in carbon steel vessels
with an expected life of about 25 yr.   Carbon steel is suitable because a
protective sulfate film formed on the steel surfaces inhibits corrosion.
However, this film can be eroded where flow velocities are excessive.  Hence,
tank nozzles, pipe lines, valves, and pumps must be properly sized if carbon
steel is used.  If flow velocities are excessive, stainless steel is recom-
mended for pipe lines, etc.  Plastic-lined material may also be used.  Plastic
pipe by itself is not recommended as it may be easily broken by a falling
object or some other shock.

     H2S04 tanks are usually designed for no additional pressure above the
weight of the acid.  Steel plates 3/8 in. thick are usually used in tank con-
struction, with the joints welded both inside and out.

     All storage tanks are above ground on concrete piers or saddles so spaced
and of such a height that leaks may be detected by visual inspection of the
bottom sections of the tanks.  Each tank is equipped with a vent to allow air
to move in and out of the tank as the rcid level changes, or as breathing
takes place because of temperature changes.  The vent or breather is equipped
with a drying agent such as silica gel, which is inert to acid fumes, in
order to prevent dilution of the acid (dilute acids are more corrosive) with
the moisture in the air and to prevent interface corrosion of the tank wall.
           exhibits an unusual freezing point curve.  The freezing point of
93% H2S04 is minus 30°F and the freezing point of 98% ^804 is 35°F.  There-
fore, suitable precautions must be taken when storing acids of different
strengths at various temperatures.

Economics

     The concept of shipping ^804 from the point of manufacture to a storage
terminal for transshipment to the consumer instead of direct shipment from
the producer to the consumer is relatively new.   Hence, not much data exists
on costs of operating such a terminal.  Data in the study  Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes  by G. G. McGlamery,
et al. (EPA-600/2-75-006 or PB-242 541/1WP, January 1975) was used to estimate
operating costs for H2S04 terminals.   These costs were based on the use of
carbon steel storage tanks on concrete piers surrounded by an earthen dike,
carbon steel acid pumps, valves and piping, and a railroad car loading dock.


     Costs were estimated for three sizes of terminals having primary storage
capacities of 4,680, 11,376, and 21,960 tons of 100% H2S04 and yearly through-
put rates of 45,300, 110,400, and 213,500 tons of 100% H2S04 respectively.
These annual throughput rates are about 10 times the primary storage capacity.
Costs were estimated for the third quarter of 1974 and mid-1978.
                                     IhO

-------
Discussion of Results

     The data in Table F-2 show that the economies of scale prevail—the
larger the storage capacity the lower the unit investment and operating costs.
For example, a terminal with a throughput of 45,200 tons/yr of 100% H^SO^ has
a unit investment cost in the third quarter of 1974 of $5.97,/ton of 100%
H2S04/yr and a total operating cost of $1.68/ton of 100% H^SO^  The corre-
sponding figures for a terminal with a throughput of 213,500 tons of 100%
H2SO^/yr are $3.37 and $0.77 respectively.  The mid-1978 costs show the same
trend.
               TABLE F-2.  H2S04 STORAGE TERMINAL OPERATION ~

                   EFFECT OF THROUGHPUT CAPABILITIES ON

               TOTAL CAPITAL INVESTMENT AND OPERATING COSTS


                              Total        Capital
            Throughtput,     capital     investment,    Operating
             tons 100%     investment,   $/ton 100%    cost, $/ton
                                                       100% H?SOA
            Third Quarter 1974 Costs

               45,200       270,000         5.97          1.68
              110,400       475,000         4.30          1.05
              213,500       720,000         3.37          0.77
            Mid-1978 Costs

               45,200       347,000         7.68          2.18
              110,400       610,000         5.53          1.38
              213,500       925,200         4.33          1.02
                                    161

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RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS USING ELEMENTAL S

Technology

     As mentioned in the preceding section, most existing I^SO^ plants are
contact plants of the single contact-single absorption type which have 95-97%
S conversion efficiencies.  Since a minimum of 99.7% S conversion efficiency
is required to meet present emission standards for new and modified plants,'
these existing single contact-single absorption plants must be retrofitted
with some system which will enable them to meet these standards.  There are
four major methods for doing this.

   1.  Adding another converter-absorber system (dual contact-
       dual absorption)

   2.  Scrubbing the stack gas with a sodium sulfite-bisulfite
       solution  (Wellman-Lord process)

   3.  Scrubbing the stack gas with an ammonium sulfite-bisulfite
       solution  (NH3 absorption process)

   4.  Adsorbing the contaminants in the stack gas on molecular
       sieves (Purasiv S process)

     In the dual contact-dual absorption system, the tail gas from the
absorber of the existing acid plant is passed through a booster blower to
provide the pressure necessary to force the gas through the remaining
additional equipment.  The tail gas must then be heated before passing
through the additional converter where most of the unreacted S02 in the tail
gas is converted to SOo.  Heating of the gas can be done either by bleeding
in a portion of the hot gases from the S furnace or employing a separate
fuel-fired heater.  The fuel-fired heater is generally used for retrofit
because of smaller capital costs and less downtime for tie-in of the abate-
ment system to the acid plant.  An air heater is included in the fuel-firing
system to minimize fuel consumption.  The. gas from the converter is passed
through an additional absorber where the SOo is removed to form more acid.
The tail gases from this second absorber, after passing through a mist elimi-
nator, can be vented to the atmosphere without exceeding emission limitations.
A mist eliminator is also added to the absorber of the existing plant to
protect the booster blower and heat exchangers from corrosion by acid carry-
over from the absorber.

     In the Wellman-Lord process the tail gas from the acid plant is scrubbed
in an absorber with a regenerable sodium sulfite-bisulfite solution.  The
resulting solution is thermally regenerated in an evaporator-crystallizer and
the S02 driven off is returned to the drying tower in the acid plant.  The
slurry from the regenerator is redissolved in water from the condenser on
the evaporator-crystallizer and returned to the absorber.  The small portion
of the sodium sulfite which is oxidized to sulfate is removed in a purge
stream along with a small amount of sodium thiosulfate which forms in the
process.


                                      162

-------
     The NH3 absorption process consists of scrubbing  the  SC>2  in  the  tail
gases from the existing acid plant in a solution of  ammonium sulf ite-bisulf ite
and discharging the scrubbed gases to the atmosphere through a high-efficiency
particulate collector (such as a Brink mist eliminator)  in order  to remove
the extremely fine particles of ammonium sulf ite-bisulf ite from the gas
stream.  The scrubbing solution from the absorber-scrubber is  acidified with
H2SC-4 and the resulting ammonium sulf ate [(NH^^SO^  ]  solution is air stripped
to remove S02 which is returned to the drying  tower  of the I^SO^  plant.  The
resulting (NH^^SO^ solution can be used in a  diammonium phosphate process or
processed in a separate crystallization operation.

     The Purasiv S process uses beds of molecular sieves to remove the SC>2
from the tail gas of the existing acid plant.  The tail  gas is  passed through
one of two parallel beds of molecular sieves.  While one adsorbent bed is
treating the gases, the other is being regenerated with  hot air.  The regene-
rated S02~air stream is returned to the drying tower of  the acid plant where
it substitutes for the dilution air usually drawn into the tower.  Bed switch-
ing is accomplished without any interruption in flow or  removal of SC^ from
the tail gas stream.  The cleaned gas is vented to the atmosphere.

Economics

     Capital and operating costs for the dual  contact-dual absorption system
were obtained from The Ralph M. Parsons Company, Monsanto  Enviro-Chem, Inc.,
and Davy Powergas, Inc.  Costs from these sources were essentially the same
and were averaged for use in the estimates.  The capital costs  include all
of the equipment mentioned in the section on technology  plus the necessary
valves, piping, foundations, engineering costs, contractor fees, etc.

     The Wellman-Lord process is proprietary and the source of  information
concerning the process was Davy Powergas.  Neither credit  for  possible sales
of the sodium sulfate byproduct nor disposal costs if  the  product is not
marketable is included in the cost estimates.

     The source of information concerning the  NH3 absorption process was also
Davy Powergas.  In the cost estimates, no credit was taken for  the byproduct
(NH^SO^.  The estimates include costs of the absorber, stripper, mist
eliminator, pumps, piping, foundation, engineering costs,  etc., but do not
include any equipment for crystallization of the
     The Purasiv S process which uses beds of molecular sieves to remove the
SC>2 from the acid plant tail gas is  the property of  the Union Carbide
Corporation and all cost information was obtained  from them.  The estimates
include the cost of the parallel bed system, the furnace for heating the
regeneration air, fans, ducts, foundations, engineering costs, etc., as well
as an expansion of an existing substation, a cooling water tower, and fuel
oil storage.  Because of the specialized nature of the adsorbent, a service
contract for its renewal is included in the estimate  rather than outright
purchase of new adsorbent and reprocessing of spent  material.
                                      163

-------
     Since all four methods of abating the emissions from H2S04 plant  stack
gases result in an increased recovery of S, a credit is given in  the cost
estimates for the equivalent S recovered.

     Cost estimates were prepared for each of the four methods for  con-
trolling emissions from existing single contact-single absorption H2SC-4
plants having capacities of 50, 100, 250, 750, and 1500 tons of 100% H2S04/
day and operating 330 days/yr.  Costs were calculated for the third quarter
of 1974 and for mid-1978.

Discussion of Results

     The data in Table F-3 show that of the four retrofit systems evaluated,
the NH3 absorption scheme is the least capital intensive, varying from $21.70/
ton of 100% H2S04/yr for a 50 ton/day plant tc $3.96 for a 1500 ton/day plant
for the third quarter of 1974.  The Wellman-Lord system is somewhat more
capital intensive with corresponding costs of $27.12 and $4.81.   The two most
capital intensive systems are the dual contact-dual absorption system  with
costs of $33.61/ton of 100% H2S04/yr for a 50 ton/day plant and $6.91  for a
1500 ton/day plant, and the molecular sieve scheme, with values of  $44.06
and $7.27 respectively.  The mid-1978 costs exhibit the same trend.

     However, the data in Table F-4 show that there is considerable variation
in overall operating costs,depending upon plant size and the retrofit  system
used.  The lowest average cost for the third quarter of 1974 for  all plant
sizes evaluated is that for the dual absorption system, $4.36/ton of 100%
H2SC>4, followed by the molecular sieves at $4.96, the NH3 absorption system
at $5.05fand the Wellman-Lord scheme at $5.78.  The same trend is exhibited
by the data for mid-1978.

     The situation changes when comparisons are made on individual plant
sizes.  The third quarter of 1974 data indicate that the dual absorption and
molecular sieves schemes are cheaper to operate for 50 and 100 ton/day plants,
with costs of $7.49 and $5.17/ton of 100% H2SC>4, respectively, for  the dual
absorption system and $9.16 and $6.12 for the molecular sieve scheme;  the
corresponding figures for the NH3 absorption scheme are $10.55 and  $6.35,
while for the Wellman-Lord system they are $11.79 and $7.22.  For the  250
ton/day plants, the dual absorption and NH3 absorption systems are  the least
expensive to operate with almost identical third quarter 1974 costs of $3.87
and $3.89/ton of 100% H2S04 respectively; the corresponding costs for  the
molecular sieves and Wellman-Lord systems are $4.43 and $4.55.  The cheapest
operating costs for the 750 and 1500 ton/day plants are associated with the
NH3 absorption system, with costs of $2.50 and $1.98 respectively.  The
operating costs for the other systems for the 750 ton/day plants  are almost
identical, varying from $2.96 to $2.99/ton of 100% H2S04; for the 1500 ton/day
plants the operating costs of the other systems vary from $2.14 for the
molecular sieves scheme to $2.36 for the Wellman-Lord system.

     The mid-1978 operating costs also vary widely between plant  sizes and
abatement systems, with roughly the same trends as the third quarter 1974
costs.


                                      1C, 4

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               TABLE F-3.   RETROFIT OF EMISSION CONTROLS TO  H2SO^ PLANTS USING ELEMENTAL S -

       EFFECT  OF ACID  PLANT CAPACITY ON  THE TOTAL  CAPITAL INVESTMENT FOR EMISSION CONTROL SYSTEMS

Acid plant
capacity,
tons
of 100%
H2S04/day
Retrofit system
Dual contact-dual absorption
Total
capital
investment, $
Investment,
$/ton 100%
H2S04/yr
Wellman-Lord
Total
capital
investment, $
Investment,
$/ton 100%
H2S04/yr
Ammonia absorption
Total
capital
investment , $
Investment,
$/ton 100%
H2S
-------
TABLE F-4.   RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS USING




        ELEMENTAL S - EFFECT OF ACID PLANT CAPACITY ON




        THE OPERATING COSTS OF EMISSION CONTROL SYSTEMS

Acid plant
capacity,
tons of .100%
H2SOi/day a
Operating cost,
Dual
bsorption
Wellman-
Lord
Third Quarter 1974 Costs
50
100
250
750
1,500
Average
Mid-1978 Costs
50
100
250
750
1,500
Average
7.49
5.17
3.87
2.96
2.30
4.36
10.40
7.41
5.74
4.53
3.68
6.35
11.79
7.22
4.55
2.99
2.36
5.78
15.50
9.72
6.36
4.38
3.58
7.91
$/ton 100% 1
NH3
absorption
10.55
6.35
3.89
2.50
1.98
5.05
14.11
8.81
5.71
3.95
3.28
7.17
*2S04
Molecular
sieves
9.16
6.12
4.43
2.97
2.14
4.96
12.54
8.62
6.43
4.59
3.44
7.12
                              166

-------
     In actual application the NH^ scrubbing system would probably have a
distinct advantage over the others if the byproduct (NH^nSO/ could be
utilized, such as would be the case for a captive acid plant located in a
fertilizer complex.  If no credit can be taken for the (NH^^SCU, then the
decision as to which system to use becomes largely dependent upon individual
acid plant factors such as location, space available for retrofit, etc.
                                      167

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                                 APPENDIX G




                      DEMAND SCHEDULE FOR H2S04 PLANTS







                                  CONTENTS




Tables                                                                   Page




 G-l     Demand Schedule for H2S04 - Eastern Acid Plants	    170




 G-2     Demand Schedule for H2S04 -Western Acid Plants 	    172
                                      169

-------
TABLE G-1.   DEMAND SCHEDULE FOR
              - EASTERN ACID PLANTS
Annual Avoidable
capacity, cost of
ktons production,
6.00
17.00
52.00
67.00
87.00
152.00
176.00
201.00
266.00
306.00
436.00
468.00
524.00
564.00
599.00
634.00
739.00
789.00
989.00
1,031.00
1,206.00
1,232.00
1,342.00
1,452.00
1,502.00
1,607.00
1,705.00
1,780.00
1,835.00
1,910.00
1,980.00
2,015.00
2,147.00
2,233.00
2,313.00
2,411.00
2,546.00
2,666.00
2,756.00
2,856.00
2,951.00
2,999.00
90.47
66.35
57.91
56.44
51.70
50.35
49.51
46.96
46.19
45.66
45.58
45.25
44.82
44.70
44.55
44.28
44.27
44.08
43.25
42.51
42.41
41.19
40.50
40.44
40.31
40.29
39.68
39.36
39.15
38.91
38.72
38.62
38.42
38.12
38.06
38.05
38.03
37.68
37.27
36.84
36.76
36.22
$ Plant name
Eastman Kodak
Home Guano Company
Detroit Chemical Co.
Kerr-McGee
Royster Company
Minn Min and Smelt
Columbia Nitrogen
American Cyanamid
American Cyanamid
Swift Chem Company
Allied Chemical Corp
Swift Chem Co.
Marion Manufacturing
Borden Chemical
Weaver Fertilizer
Swift Chem Co.
Olin Corporation
American Cyanamid
E. I. Dupont De Nem
W. R. Grace and Co,
E. I. Dupont De Nem
American Cyanamid
E. I. Dupont De Nem
Pennsalt Chemicals
American Cyanamid
U.S. Industrial Chem
W. R. Grace and Co.
Delta Chemical
Reichhold Chemicals
E. I. Dupont De Nem
USS Agri-Chem
Cities Service Oil
Army Ammunition Pit
El Paso Products
Borden Chemical
U.S. Industrial Chem
Allied Chemical Corp
Stauffer Chemical Co.
E. I. Dupont De Nem
Occidental Ag Chera
American Cyanamid
Acme (Wright) Pert Co.
Location
Rochester
Do than
Detroit
Cottondale
Norfolk
Copley
Moultrie
Kalamazoo
Bound Brook
Calumet City
Cleveland
Wilmington
Indianapolis
Streator
Norfolk
Norfolk
N. Little Rock
Joliet
Cleveland
Charleston
North Bend
Mobile
Gibbstown
Tulsa
Fortier
Desoto
Joplin
Searsport
Tuscaloosa
Cornwells Hts.
Navassa
Monmouth Jet
Tyner
El Paso
Norfolk
Dubuque
Nitro
Ft. Worth
Richmond
Plainview
Hamilton
Acme

NY
AL
MI
FL
VA
OH
GA
MI
NJ
IL
OH
NC
IN
IL
VA
VA
AR
IL
OH
SC
OH
AL
NJ
OK
LA
KS
MO
ME
AL
PA
NC
NJ
TN
TX
VA
IA
WV
TX
VA
TX
OH
NC
(continued)
    170
    v

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TABLE G-l (continued)

Annual Avoidable
capacity. cost of
ktons production,
3,124.00
3,336.00
3,496.00
3,821.00
4,021.00
4,271.00
4,371.00
4,446.00
4,896.00
5,161.00
5,231.00
5,551.00
5,731.00
6,056.00
6,276.00
6,401.00
6,881.00
7,231.00
7,351.00
7,521.00
7,970.00
8,853.00
9,413.00
9,833.00
10,288.00
11,568.00
11,968.00
12,468.00
13,825.00
14,070.00
14,286.00
14,816.00
15,096.00
16,146.00
17,346.00
17,886.00
18,376.00
18,901.00
20,121.00
20,621.00
22,271.00
23,497.00
24,687-00
25,347.00
26,897.00
28,097.00
30,257.00
32,237.00
36.21
35.95
35.94
35.60
35,50
35.06
35.03
34.40
34.17
34.04
33.94
33.81
33.20
32.78
32.73
32.51
32.49
32.48
32.30
32.12
31.76
31.72
31.41
31.19
31.12
30.96
30.88
30.30
30.30
29.82
29.80
29.75
29.12
28.56
28.45
27.92
27.60
27.53
27.27
27.26
26.87
26.50
26.35
26.21
25.85
25.64
25.23
25.19
$ Plant name
E. I. Dupont De Nem
Army Ammunition Pit
Allied Chemical Corp
Royster Company
Allied Chemical Corp
Stauffer Chemical Co.
Monsanto Company
LJ + M LaPlace Cde
Gardinier
Monsanto Company
USS Agri-Chem
W. R. Grace and Co.
Essex Chemical Co.
E. I. Dupont De Nem
Swift Chem Co.
Cities Service Oil
W. R. Grace and Co.
Olin Corporation
Monsanto Company
U.S. Industrial Chem
Texasgulf Inc.
Gardinier
NL Industries Inc.
Mobil Oil
NL Industries Inc.
W. R. Grace and Co.
Engelhardt McConser
Olin Corporation
Texasgulf Inc.
American Cyanamid
American Cyanamid
American Cyanamid
USS Agri-Chem
Gardinier
Agrico Chem-Williams
USS Agri-Chem
Borden Chemical
Beker Industries
Miss Chem Corp.
Allied Chemical Corp.
Occidental Ag Chem
Farmland Industries
CF Industries Inc.
CF Industries Inc.
CF Industries Inc.
Agrico Chem-Williams
Freeport Minerals
International Miner
Location
Deepwater
Radford
Front Royal
Mulberry
Hop ewe 11
LeMoyne
El Dorado
Edison
Tampa
E. St. Louis
Wilmington
Bartow
Newark
Linden
Agrico la
Augusta
Bartow
Baltimore
Everett
Tuscola
Lee Creek
Tampa
Sayreville
Depue
St. Louis
Bartow
Nichols
Pasadena
Lee Creek
Warner (Linden)
Savannah
Fortier
Bartow
Tampa
Donaldsonville
Ft. Meade
Pt. Manatee
Taft
Pascagoula
Geismar
White Springs
Pierce
Bonnie
Bonnie
Plant City
Pierce
Uncle Sam
Bonnie

NJ
VA
VA
FL
VA
AL
AR
NJ
FL
IL
NC
FL
NJ
NJ
FL
GA
FL
MD
MA
IL
NC
FL
NJ
IL
MO
FL
FL
TX
NC
NJ
GA
LA
FL
FL
LA
FL
FL
LA
MS
LA
FL
FL
FL
FL
FL
FL
LA
FL
           171

-------
TABLE G-2.   DEMAND SCHEDULE FOR
                                         - WESTERN ACID PLANTS
 Annual
capacity,
  ktons
        Avoidable
         cost of
       production, $
   15.00
  156.00
  191.00
  246.00
  312.00
  452.00
  527.00
  667.00
  867.00
1,092.00
1,467.00
1,732.00
2,392.00
3,042.00
          43.72
          37.61
          34.29
          33.83
          31.95
          30.43
          30.00
          29.33
          29.31
          27.35
          26.97
          26.45
          21.26
          20.53
     Plant name
    Location
Georgia Pacific
Kerr-McGee
Phelps Dodge
Union Carbide Corp.
Valley Nitrogen Prod.
Allied Chemical Corp.
Phelps Dodge
Anaconda Company
Allied Chemical Corp.
Occidental Ag Chem
Valley Nitrogen Prod.
Valley Nitrogen Prod.
Beker Industries
J. R. Simplot Co.
Bellingham     WA
Grants         NM
Jeffrey City   WY
Uravan         CO
Bena           CA
Pittsburg      CA
Riverton       WY
Yerington      NV
Richmond       CA
Lathrop        CA
Helm           CA
Helm           CA
Conda          ID
Pocatello      ID
                                172

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                                 APPENDIX H

   BYPRODUCT H2SC>4 PRODUCTION FROM SMELTER GASES INCLUDING ESTIMATES OF

           RETROFIT TAIL GAS CLEANUP AND LIMESTONE NEUTRALIZATION


                                  CONTENTS

Tables                                                                  Page

  H-l    H^SO, Production from Smelter Gas - Effect of Acid Plant
          Capacity on Total Capital Investment at Various  S02
          Levels in Smelter Gas	176

  H-2    H2S04 Production from Smelter Gas - Effect of Acid Plant
          Capacity on Operating  Cost at Various  S02 Levels in
          Smelter Gas	176

  H-3    Retrofit of Emission Controls to ^804  Plants Using
          Smelter Gas - Dual Contact-Dual Absorption  System -
          Effect of Acid Plant Capacity on Total Capital
          Investment at Various  S(>2 Levels in Smelter Gas	178

  H-4    Limestone Neutralization of H2SC>4 - Effect of System
          Capacity on Total Capital Investment and Operating Cost  .  .  .  180
                                     173

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                                 APPENDIX H

    BYPRODUCT H2S04 PRODUCTION FROM SMELTER GASES INCLUDING ESTIMATES OF

           RETROFIT TAIL GAS CLEANUP AND LIMESTONE NEUTRALIZATION


H2S04 PRODUCTION FROM SMELTER GAS

Technology

     As in an elemental S-burning acid plant, the S02 in the smelter gases  is
oxidized to 503 by the contact process to produce 1^504.  While the SC>2 gas
stream to the converter in an elemental S acid plant is clean and requires
little if any cleanup to protect the catalyst in the converter, the gases from
smelter plants are dirty and require extensive treatment to remove dust and
fume.  Most of the dust and fume are removed in dry cyclones and bag filters.
At  this point the gas is discharged to the atmosphere if S02 removal is not
necessary.

     If the SC>2 is to be recovered in an acid plant, the remaining dust and
fume must be removed, usually in a wet scrubber.  In the scrubber the small
amount of 503 formed during the smelting process -reacts with the water to form
a weak solution of H2S04-  Some of the acid formed leaves the scrubber as a
mist and must be removed in an electrostatic precipitator (ESP).  The weak
acid from the scrubber and precipitator is contaminated with dust and is
discarded.  The cleaned gases, having been passed through a wet scrubber, are
saturated with water vapor.  Part of this water must be removed so that the
ratio of water:S02 in the gas does not exceed that required to produce
concentrated acid (100% H2S04 has a water:S02 mol ratio of 1).  The excess
water is removed by cooling the gas directly by contact with product acid or
indirectly in a water-cooled heat exchanger, or both.  The cleaned and cooled
gases are now ready for conversion of the S02 to H2S04 in a conventional
contact plant.

Economics

     Smelter gas acid plants are more expensive to build and operate than S-
burning plants,  primarily because the smelter off-gases must be thoroughly
cleaned before processing in the acid plant.  Another factor is the varying
S02 content of the several gas streams from a smelter, ranging from <1% from
reverberatory copper smelting furnaces to about 15% from fluid-bed roasters.
For technical and economic reasons, the S02 content of the gases fed to a
contact acid plant is limited to the range of about 4-12%.  The higher limit
is imposed by the fact that the S02~bearing gases to the converter of a
contact acid plant must contain sufficient oxygen to oxidize the S02 to SO^.
Also, as the S02 content of the gases increases, the amount of heat released
by the oxidation of S02 to S03 in the converter increases and the resulting
higher temperature may damage the catalyst.  The lower limit is imposed by
economic considerations.  Concentrations of S02 lower than 4% in the feed gas
are technically feasible but uneconomic because to accommodate the larger gas

                                      174

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flows necessary to maintain a  reasonable  production rate,  the size of  the
equipment, and thus its cost,  become  prohibitive.   Some of the gas streams
from a smelter may be blended  to  give a composition suitable for feeding to an
acid plant, but even so, some  of  the  dilute SC>2 gases are  vented to the at-
mosphere after particulate removal  when S02 emission standards permit.

     The above considerations  make  it desirable to have cost data for  several
sizes of smelter acid plants,  each  receiving feed  gases of varying S02
content.  Hence, cost estimates were  prepared for  smelter  acid plants  having
capacities of 250, 750, and 1500  tons of  100% H2S04/day, operating 330 days/yr,
and processing gases containg  4,  8, and 12% S02-   Costs were calculated as of
the third quarter of 1974 and  mid-1978.

     The capital and operating cost data  were obtained primarily from  System
Study for Control of Emissions -  Primary  Nonferrous Smelting Industry  by
Arthur G. McKee and Company, San  Francisco, California, June 1969-   The
capital investments for these  plants  include, in addition  to the acid  plant
itself, only the gas cleaning  and cooling equipment required to protect the
catalyst in the acid plant converter; the cost of  the preliminary gas-cleaning
equipment required to meet particulate emission standards  is a necessary cost
for processing those gas streams  which are to be vented to the atmosphere
without S02 removal, and thus, is not considered as an expense chargeable to
S02 recovery.

     Since most of the existing smelter acid plants are of the single  contact-
single absorption type, this technology was used in preparing the cost
estimates.  Costs for retrofitting these  plants to meet acid plant emission
standards will be found in the appendix of this report.

Discussion of Results

     The data in Table H-l indicate that  unit capital investment decreases
both with increased acid plant size and with increased concentration of S02 in
the feed gases.  The unit capital cost in $/ton of 100% H2S04/yr for the third
quarter of 1974 decreases from $106.19 for a 250 ton/day plant receiving gases
containing 4% S02 to $68.82 for a 1500 ton/day plant also  receiving 4% S02
gases.  Similar trends occur for  plants processing 8 and 12% S02 gases.  The
unit capital cost decreases from  the  $106.19 figure mentioned above for a
250 ton/day plant being fed gases containing 4% S02 to $61.05/ton of 100%
         for the same sized plant processing 12% S02 gases.
      Operating  costs  in $/ton of 100% H2S04 also decrease with increasing  size
 of  acid plants  and  increasing concentration of S02 in the feed gases  as  shown
 in  Table H-2.   The  operating cost for a 250 ton/day plant processing  4%  S02
 gases  is $24.79/ton of 100% H2S04 for third quarter 1974 costs,  while the
 operating  cost  for  a  1500 ton/day plant, also processing 4% S02  gases, is
 $14.38.  When the concentration of S02 in the feed gases is increased to 12%,
 the operating cost  for the 250 ton/day plant processing 4% S02 gases  decreases
 from  the $24.79 figure to $14.44 for the same sized plant processing  12% S02
 gases.  The  trends  illustrated above also apply to the mid-1978  data.
                                     175

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    TABLE H-l.   H2SC>4 PRODUCTION FROM SMELTER GAS -




EFFECT OF ACID PLANT CAPACITY ON TOTAL CAPITAL INVESTMENT




          AT VARIOUS S02 LEVELS IN SMELTER GAS
Acid plant
capacity,
tons of 100%
H2S04/day
Third Quarter
250
750
1,500
Mid-1978 Costs
250
750
1,500
Capital investment,
Total capital investment, $ $/ton 100% H2S04/yr
4% S02 8% S02 12% S02 4% S02 8% S02 12%
1974 Costs
8,760,960 5,513,230 5,036,900 106.19 66.82 61
19,891,100 12,460,300 11,791,700 80.37 50.34 47
34,065,850 21,119,390 19,281,110 68.82 42.67 38
11,258,000 7,084,500 6,472,400 136.46 85.87 78
25,560,000 16,011,500 15,152,300 103.27 64.69 61
43,774,600 27,138,400 24,776,200 88.43 54.83 50

S02
.05
.64
.95
.45
.22
.05

TABLE H-2. H2S04 PRODUCTION FROM SMELTER GAS -
EFFECT OF ACID PLANT CAPACITY ON OPERATING COST AT
VARIOUS S02 LEVELS IN SMELTER GAS



Acid
plant capacity, Operating cost,
tons of 100% $/ton 100% H2S04
H2S04/day 4% S02 &% S02 12% S02
Third Quarter 1974 Costs
250 8.34 3.87 2.38
750 6.45 2.96 1.80
1,500 5.06 2.30 1.38
Mid-1978 Costs
250 12.37 5.74 3.54
750 9.76 4.53 2.76
1,500 8.08 3.68 2.22

                            176

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RETROFIT OF EMISSION CONTROLS  TO  H2S04  PLANTS USING SMELTER GAS

Technology

     Smelter gas H2S04 plants  can be retrofitted for control of tail gas
emissions using the technology previously discussed in this report in the
section on retrofitting  elemental S-burning plants.   The information developed
in that section of the report  showed that, for all the acid plant sizes in-
vestigated, the dual contact-dual absorption alternative had the lowest
overall average operating  cost.   For this reason only the dual contact-dual
absorption system was evaluated for use on smelter gas acid plants.


Economics

     In S~burning acid plants  the gas to the. converter contains about 8% S02-
Since retrofitting costs have  been developed for such plants in a prior section
of this report, these developed capital costs are used directly as the capital
costs for retrofitting smelter gas acid plants also being fed gases  containing
8% S02-  The capital costs for smelter  gas (or other) acid plants are directly
proportioned to gas flow,   For a  given  acid production rate gas flow translates
inversely to SO;; content.   Hence  the capital costs for smelter gas acid plants
being fed gas  streams containing  4% and 12% SCb were calculated from the costs
of acid plants being fed 8% S02 using appropriate scaling factors.

     Costs for retrofitting smelter gas acid plants  with dual contact-dual
absorption systems having  capacities of 250s 750, and 1500 tons of 100% K2S04/
day and being  fed gases  containing 4%s  8%s and 12% S02 were estimated for the
third quarter  of 1974 and  mid-1978.


Discussion of  Results

     The data  in Table H-3 show the same trend in unit capital costs for
retrofitting smelter gas acid  plants with dual contact-dual absorption systems
as the data for capital  costs  of  the smelter gas acid plants themselves.  The
unit capital investment  required  decreases as the size of the plant and the
concentration  of S02 in  the feed  gases  increases.  For example, the unit
capital investment in the  third quarter of 1974 for a 250 ton/day plant
receiving gases containing 8%  S02 is $13.87/ton of 100% H2S04 produced/yr
while a 1500 ton/day plant requires only $6.91.  The third quarter 1974 unit
investment cost for a 250  ton/day plant is $28.94/ton of 100% acid/yr when
the feed gas contains 4% S02 while the  corresponding cost when the feed gas
contains 12% S02 is $8.45.

     Operating costs show  the  same trend.  In the third quarter of 1974, the
operating costs for a 250  ton/day plant processing gases containing 8% S02 is
$3.87/ton of 100% 1^804  while  the corresponding cost for a 1500 ton/day plant
is $2.30.  When a 250 ton/day  plant processes gases containing 4% S02, the
operating cost is $8.34/ton of 100% H2S04 while the cost of processing gases


                                      177

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 containing  12% S02 is  $2.38.  These trends  for both unit  capital  and  operating
 costs  are also reflected in the mid-1978 costs.


         TABLE H-3.  RETROFIT OF EMISSION CONTROLS TO H2S04  PLANTS

          USING  SMELTER GAS - DUAL CONTACT-DUAL ABSORPTION SYSTEM -

               EFFECT  OF ACID PLANT CAPACITY ON TOTAL CAPITAL

               INVESTMENT AT VARIOUS S02 LEVELS IN SMELTER GAS

     Acid
 plant  capacity,                                         Capital investment,
  tons  of 100%        Total capital investment, $          $/ton 100%
    H?S04/day _ 4%  S02 _ 8% SO? _ 12%  SO?     4%  S09    8%  SO?    12% SO?

 Third Quarter  1974  Costs

      250          2,387,530    1,144,000     729,900    28.94     13.87       8.45
      750          5,296,800    2,538,000   1,619,240    21.40     10.25       6.54
    1,500          7,133,400    3,418,000   2,180,700    14.41      6.91       4.41

 Mid-1978  Costs
250
750
1,500
3,068,000
6,663,400
9,166,400
1,470,000
3,261,300
4,392,100
937,900
2,080,700
2,802,200
37.19
26.92
18.52
17.82
13.18
8.87
11.37
8.41
5.66

 LIMESTONE NEUTRALIZATION OF H2S04

 Technology

     At  the present time no detailed information is available concerning  large-
 scale neutralization of H2S04.  Therefore, the information given in  this  report
 is based on a conceptual design and cost study presented in  Neutralization of
 Abatement Derived Sulfuric Acid  prepared for EPA by Process Research, Inc.,
 EPA Report No. EPA-R2-73-187.  In this conceptual design, the H2S04  is
 neutralized with a slurry of ground limestone.  The resulting gypsum is
 disposed of by ponding.

     The ground limestone is slurried with the overflow from the gypsum pond.
 The slurry is pumped to a neutralization tank where the acid is added.  The
 gases evolved (mostly C02) are vented to the atmosphere through the  limestone
 slurry tank to trap any 803 vapor which might be liberated by the heat
 generated during the neutralization step.  The neutralized slurry is pumped to
 the gypsum settling pond where the remaining heat of reaction is dissipated by
 the evaporation of water from the pond.  The overflow from the pond  is
 collected in a sump where makeup water is added to compensate for that lost in
evaporation and for that occluded or combined in the gypsum sludge.  The  amount


                                     178

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of makeup water required will be reduced in proportion to the rainfall collected
by the pond.  The strength of the acid neutralized will also affect the water
balance,  In this study, 93% H2SC>4 is neutralized.  However, except in the
wettest regions of  the  U.S., such as the Gulf Coast, the amount of  water lost
from the circuit by evaporation and by retention in the gypsum sludge will
exceed the amount added by rainfall, ranking the use of makeup water necessary.
This may occur during  the  dry season in the arid regions of the West where  the
neutralization of smelter  acid may become important because of the  Jack of
markets for the abatement  acid.  However, in this study, it is assumed that
neither will makeup water  be required, nor will disposal of surplus water be
necessary.

     The gypsum pond dikes are constructed of soil excavated from the interior
area.  The bottoms  of  the  ponds and the inside slopes of the dikes  are covered
with a 6-in. layer  composed of selected excavation materials into which
bentonite has been  mixed.   Another 4- to 6-in. layer of excavated material  is
placed on top of  the bentonite-treated layer.  The outside faces and tops of
the dikes are finished with a layer of topsoil.  The pond overflow  is collected
in a structure located opposite the slurry inlet and includes an adjustable
weir gate and a sump containing a pump,  The pond or ponds are all  20 ft deep,
No acid storage facilities are included, in the system since the acid storage
associated with the acid plants is assumed to be adequate.

Economics

     The conceptual design used in this report is essentially the same as the
one appearing in  the previously mentioned report  Neutralization of Abatement
Derived Sulfuric  Acid.    The Process Research report assumed the initial
purchase of land  for 10 annual gypsum ponds and the construction of only one
annual pond; however,  a single 30-yr pond concept was used in this  report.

     Investment and operating costs were calculated for neutralization
facilities having dally capacities of 250, 750, and 1500 tons/day of 100%
H2S04 and operating 330 days/yr.  The 1500 ton/day unit was assumed to have
two neutralization tanks  and dual ball mills for grinding the limestone; the
other units have  a single  neutralization tank and one ball mill. Costs were
calculated  for  the third  quarter of 1974 and mid-1978.

Discussion of Results

     The data in  Table H~4 indicate that, as might ba expected, the economies
of size are present in this operation; that is, as the size of the .facility
increases, both  the unit  investment and operating cost decrease. For a
neutralizing system treating 250 tons/day of 100% H2S04, the unit investment
cost in the third quarter  of 1974 is $84.74/ton of 100% H2S04/yr and the
operating cost  is $25.13/tori of 100% H2S04 neutralized, while for a 1500
ton/day installation the  comparable figures are $38.52 and $12.95.   The costs
for mid-1978 show a similar trend.

     Since the  gypsum  pond accounts for about 80% of the capital investment,
both the investment costs  and the operating costs will be reduced considerably
                                       179

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when a neutralization plant is built for an acid plant which has only  10-  or
15-yr life expectancy and is not scheduled for replacement.


               TABLE H-4.  LIMESTONE NEUTRALIZATION OF H2S04 -

                 EFFECT OF SYSTEM CAPACITY ON TOTAL CAPITAL

                        INVESTMENT AND OPERATING COST


     System capacity,        Total       Capital investment,    Operating
    tons of 100% H2S04      capital          $/ton 100%        cost, $/ton
     neutralized/day	investment, $	H?SO^/yr	100% H?SO&

    Third Quarter 1974 Costs

          250              6,991,300           84.74              25.13
          750             13,029,200           52.64              16.60
        1,500             19,067,100           38.52              12.95

    Mid-1978 Costs

          250              8,983,800          108.89              34.28
          750             16,742,500           67.65              23.21
        1,500             24,501,200           49.50              18.40
                                     180

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                                APPENDIX I







             H2S04 TRANSPORTATION RATES FROM WESTERN SMELTERS




                           TO EASTERN TERMINALS







                                 CONTENTS




Table                                                                   Ia8e




 1-1    Unit Train H2S04 Rates, $/Ton	182
                                     181

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                                      TABLE 1-1.  UNIT TRAIN H2S04 RATES, $/TONa
Co
ho

Point of origin
Hay den
AZ
21.80
24.42
24.42
24.42
19.60
-
-
Hurley
MM
16.79
18.86
18.86
18.86
13.36
-
-
Separ
NM
16.79
18.86
18.86
18.86
13.36
-
-
Kellogg
ID
22.05
22.95
22.95
41.85
41.85
-
-
Anaconda
MT
19.00
19.40
19.40
35.65
33.15
-
-
Garfield
UT Canada
18.75
17.85
17.85
30.50
26.50
5.45
6.85
Eastern terminals
Location
Chicago
St. Louis
Memphis
Baton Rouge
Houston
Buffalo
Detroit

IL
MO
TN
LA
TX
NY
MI

               a.  A  terminal  handling charge of $1.50/ton will be added at each terminal.

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               APPENDIX J




PROJECTION OF STEAM PLANT DATA BASE, 1978
                     183

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                                 APPENDIX J

                  PROJECTION OF STEAM PLANT DATA BASE, 1978


     FPC Form 67 was the basic data source used in developing the steam plant
data base and converting the information into a form useful for calculation of
scrubbing cost by any of the processes considered.  Projections for 1978 made
by the utilities were taken as accurate projections of power demand in 1978
for each plant.

     Many of the projections made by the industry and reported to FPC were
plant level projections.  To calculate scrubbing cost it was necessary to
convert plant level data to boiler level.  Specific data requirements neces-
sary to calculate costs included boiler age, air rate, heat rate, boiler size,
and fuel type, quantity, Btu content, and S content.

     Boiler age and size were given for each plant.  For new plants boiler age
was obtained from other FPC reports.

Fuel Projections

     The FPC data from Form 67 only reported megawatts to be generated and
fuel consumption at the plant level.  For purposes of cost estimation it was
necessary to convert plant level projections to boiler level projections of
fuel use by type and amount.  Normally Btu content and S content of fuels to
be used were given.  When no values were given, the following standard values
were assumed:  S content of fuel, coal 3.5%, oil 2.5%, gas 0%; Btu content of
fuel, coal 12,000 Btu/lb, oil 149,000 Btu/gal, and gas 1,000 Btu/ft3.  In
some cases plant projections for 1978 were not made.  The following briefly
describes the methods and procedures followed to develop fuel projections to
be used in the steam plant data base.

     In some cases boilers were listed as existing that apparently were no
longer in service except possibly on a standby basis.  That is, the sum of
reported boiler capacity exceeded reported plant capacity.  Recognizing that
scrubbing facilities would not be installed on these unused boilers, they were
dropped from consideration.  The procedure for dropping was to eliminate any
boiler >30 yr old that had a capacity equal to or less than the difference
between boiler capacity and plant capacity when boiler capacity was greater
than plant capacity.  After this algorithm was completed, all remaining
boilers were considered candidates for scrubbing.

     Boilers are used at <100% of capacity, depending on a number of factors
including power demand.  Projections made by the utilities were assumed to
                                      184

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reflect power demand in 1978.   Boiler age is the most general determinant  of
using the boiler or its capacity  factor.   The projected boiler capacity  factor
was used as the key factor  in  allocating  fuel input requirements  to  individual
boilers.  The capacity factor  used  was based on historical (1969-73)  capacity
factor versus age of reported  boiler operation. That relationship is  shown i\
Figure 16.  It represents the  average capacity factor of each boiler  for the
5-yr period (about 15,000 observations).   This relationship was used  to
predict boiler capacity factor as a function of age.   The data indicated a
startup period lasting for  about  10 yr.   During this  period,  the  relationship
was assumed linear and positive of  the type y - a + bx,   BoiJers  ^rnns
on stream in 1978 are assumed  to  operate  at a capacity factor of  50%,
Operation is assumed to increase  at an annual rate of 1.5% through 10 yr of
age.  Between ages 10 and 15,  operation is assumed constant At a  65%  capacity
factor,  After age 15, the  capacity factor is assumed to decline  linearly at
an annual rate of 1,8%/yr to a minimum of 2% at 50 yr by the equation
y = a + bx.

     Once boiler capacity  (given  from FPC) and its capacity factor were
established it was then possible  to calculate megawatts to be generated by
each boiler and to calculate Btu  of heat  input required.  This calculation
was based on the given  or the  assumed plant heat rate.

     At this point,  t«ro algorithms  were used.  If a plant had projected its
own megawatt production and fuel  level, the projection by the utility was
assumed correct.  If fuel requirements at the boiler level, based on  calcu-
lated capacity factors, were less than plant level projections of megawatts to
be generated by the  plant,  each boiler capacity factor was adjusted upward
by a constant percentage.   If  fuel  requirements exceeded plant megawatt
projections, then boiler  capacity factors were adjusted downward  by a constant
percentage.  If a 30-yr-old or older boiler existed and plant megawatt could
be generated by existing  newer boilers at the calculated capacity factor, the
capacity  factor of the  old  boiler was reduced to zero.  (No fuel  was  allocated
to those boilers.)

     When the utility did not  project megawatts to be generated and/or fuel
use in  1978, each boiler  was assumed to operate at the calculated capacity
factor  based on boiler  age. Megawatts to be generated and fuel requirements
were calculated accordingly.

     Completion of the  above steps  provided an estimate of total  Btu  heat
input requirements to meet  projected 1978 power demands.  Btu requirements
were, at  the same time, projected to each individual boiler to be used in
generating  electricity  in 1978.  The next step was to calculate fuel  type and
amount  to meet projected  Btu requirements.

Plant Level Fuel Type,  1978

     When plant level projections of fuel requirements were made, fuel type
and Btu content were also given and usually S content of each fuel was also
given.  Five separate  cases were  identified requiring slightly different
procedures  to project  fuel  type and amount.  In all cases, amount of  fuel  is
a function  of Btu content of the  fuel and Btu heat input requirements.


                                      185

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Case 1

     This case covers all plants that reported 1973 data and that projected
fuel on Form 67.  When the plant level projections for 1978 were made on
Form 67, they were assumed to be correct in all cases except when the
quantities of fuel projected would cause the plant to exceed megawatt capacity.
Where fuel quantities would cause the plant to exceed the reported capacity,
fuel quantities were reduced proportionally to operate the plant at 80% of
reported capacity.  There were 625 plants in this category.  In this and all
other cases projected megawatts to be generated were used as the factor to
check against and adjust to if fuel projections and megawatts to be generated
did not match.

Case 2

     This case covers all plants existing in 1973 that reported plant level
fuel consumption in 1973, but did not project megawatts to be generated or
fuel quantities in 1978, and did not project an increase of >100 MW of
capacity between 1973 and 1978.  The historical capacity factor profile
presented earlier is used to calculate megawatts to be generated and Btu heat
input requirements.  The proportion of the total projected Btu requirements
to be met from each fuel source is assumed to be the same as used in 1973.
There were 107 plants included in this category.

Case 3

     This is the same as Case 2 above except that it considers plants where
capacity has increased by >100 MW between 1973 and 1978.  Fuel consumption in
1978 on the capacity existing in 1973 is calculated the same as in Case 1
above.  Additional fuel consumption for the new increased capacity will be
based on the projected capacity factor as in Case 2, and the fuel type will
be determined as follows:  If the plant burned oil in 1973, but no coal, the
additional fuel will be oil; otherwise, the additional fuel will be coal.
There were seven plants included in this category.

Case 4

     This case covers all new plants coming online after 1973 that did not
report 1973 data, and did not project megawatts or fuel consumption for 1978.
They are projected to burn coal and to operate at the projected capacity
factor based on the historical data.  There were 43 plants included in this
category.

Case 5

     This case covers all new plants (coming online after 1973) that did
project megawatts to be generated and fuel consumption for 1978.  This is the
same as Case 1, but a separate case number was used to allow identification
of new plants.   There were 18 plants included in this category.
                                      186

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     Once these calculations were  completed,  Btu input requirements per
boiler had been established.   The  remaining problem was to determine what fuel
type each boiler will use when the plant projects more than one  fuel type.  It
will be recalled that when  fuel type  was not projected, only coal  or oil was
projected as a fuel source  and in  no  case were fuel sources mixed.  Oil was
projected only if  the plant had never burned coal in any boiler  from 1969-73.
Where projections  of mixed  fuel sources were made, an algorithm  was developed
to allocate all projected gas  consumption first.  Gas was first  projected
to the largest exclusive gas boiler.   If that did not take up ill  gas  then
remaining, gas was allocated  to boilers that had historically used gas until
projected consumption was met.  Oil was allocated next in the same fashion as
gas.  First to largest  exclusive oil boiler, and so on, until ail  projected
oil was consumed.  Coal was allocated last as above to the largest exclusive
coal boilers and as needed  to  fill any remaining need for Stu heat input re-
quirements at any  boiler.   The steam plant data base is complete at this
point.

     Historical and projected 1978 fuel usage by type is shown in  the  following
 tabulation:

              Actual Fuel Use  byJType (1969-73)  and Projected_	

                               Use by Type (19781

                          Coal,         Oil,          Gas,
                  Year     ktons    k  (42-gal) bbl 	Mft?	

                  1969     30,379      252,654       3,319,330
                  1970   314,749      323,291       3,704,726
                  1971   324,271      377,030       3,728,747
                  1972   348,694      458,390       3,707,278
                                       187

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                  APPENDIX K





VARIABLE COST OF LIMESTONE AND  SLUDGE DISPOSAL
                         189

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                                 APPENDIX K

               VARIABLE COST OF LIMESTONE AND SLUDGE DISPOSAL
     The delivered cost of limestone is a major input cost item and is subject
to wide variation due to availability and f.o.b. cost of limestone.  A 1972
study (Availability of Limestones and Dolomites - Task No.  1 Final Report,
by J. J. O'Donnell and A.  G.  Sliger of the M. W. Kellogg Company) estimated
delivered cost of high-Ca limestone in 1972 to  37 selected power plants, most
of which were located in the eastern half of the U.S.  Delivered costs ranged
from $1.95-$13.00/ton.  Delivered costs were under $4/ton to half the plants
and all but three in the study could have been  supplied at under $6/ton.
Previous TVA studies had assumed limestone cost at $4/ton to each utility.
Because of the variability in cost found in the Kellogg study previously
mentioned, a limestone data base was developed  to use in this and other
studies.  This data base provides for the calculation of delivered cost of
limestone to each utility from the nearest limestone quarry.  The f.o.b. price
used is the state average price in 1975 inflated by 10% to reflect 1978 costs.
Dolomite sources are excluded from the data base.  According to information
developed, delivered costs of limestone in 1978 will range from $2.07-$11.23/
ton.  All but 50 plants in the U.S. can be supplied at a delivered cost of
<$6/ton in 1978.

     The data do not assure that limestone is of the quality required for use
in scrubbing.  Further, there is no assurance that sufficient quantities exist
at producing locations to meet long-term utility needs.

     The limestone data base was developed from information provided
specifically for use in this study by  BOM.

     A few existing plants do not have adequate land available for onsite
disposal of throwaway Ca  solids from the slurry process.   When this was
the case, offsite disposal charges were added.  Land cost was assumed the
same.  Some cost areas were different between onsite and offsite disposal
but in sum total investment was approximately equal.  Miles to disposal area
were added into the cost model and transportation costs were calculated.
Costs were based on a charge of $l/ton for distances up to 3 mi and then
charges were assumed to decline linearly to a minimum of $0.20/ton mi for
distances up to 20 mi.
                                     190

-------
     The calculated delivered costs of limestone are shown in the  following
tabulation for selected power plants.
Plant No.
0700000550
0785000100
0785000500
0790000100
1000000050
1095000200
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
3840000500
4045000900
4510000100
4530000850
4740000300
4770001900
4770002100
4770003000
4770004100
4815000400
5125000650
5125000700
5250001400
5540000250
Plant name
Rose ton
Cof feen
Newton
Edwards
Deely
Conesville
Power ton
Belews Creek
Crystal River
Wans ley
Bowen
Ghent
Northport
Homer City
Martins Creek
Eddystone
Cayuga
Gas ton
Harrington
Big Bend
Johns onvi lie
Kingston
Paradise
Cumberland
Stuart
Rush Island
Sioux
Yorktown
Columbia
Mine
MW price, $/ton
1,200
616
590
602
836
1,255
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
940
1,062
910
634
1,136
1,482
1,723
2,558
2,660
1,831
1,150
1,100
845
527
2.66
2.37
2.37
2.37
2.21
2.41
2.37
2.44
2.06
2.67
2.67
2.22
8.24
2.62
2.62
2.62
2.22
2.39
1.90
2.06
2.35
2.24
2.35
2.35
2.41
2.37
2.37
2.44
1.91
Transport
cost, $/ton
1.61
1.15
1.61
2.07
1.15
1,61
1.61
2.30
1.61
2.07
1.15
1.15
2.30
1.61
1.15
1.61
2.07
1.15
2.07
2.07
2.30
2.07
1.15
2.07
1.61
1.61
1.61
3.45
1.15
Delivered
cost, $/ton
4.27
3.52
3.98
4.44
3.36
4.02
3.98
4.44
3.67
4.74
3.82
3.37
10.54
4.23
3.77
4.23
4.29
3.54
3.97
4.13
4.65
4.31
3.50
4.42
4.02
3.98
3.98
5.89
3.06
                                      191

-------
                                APPENDIX L

         SPECIFIC SUPPLY POINTS FOR SALE OF BYPRODUCT SMELTER ACID


                                 CONTENTS

Tables                                                                 Page

 K-l      Fourteen Western Smelters . ,	,  .    194

 K-2      Eastern Smelters Selling Byproduct Acid in $0.00/MBtu
          and $0.35/MBtu ACFL Runs	    195

 K-3      Smelters Selling Byproduct Acid  in $0.50/MBtu ACFL Run  .  .    196

 K-4      Smelters Selling Byproduct Acid  in $0.70/MBtu ACFL Run  •  •    197
                                      193

-------
TABLE L-l   FOURTEEN WESTERN SMELTERS

No.
065
150
151
152
153
154
155
156
157
158
159
160
175
182

Company
Gulf Resources
Phelps Dodge
Kennecott Copper
American Smelting (ASARCO)
Phelps Dodge
Magma Copper Company
Hecla Mining Company
Inspiration Con Corp
Anaconda Company
Kennecott Copper
Kennecott Copper
American Smelting (ASARCO)
Anaconda Company
Phelps Dodge
Total
Location
Kellogg
Morenci
Hayden
Hayden
Ajo
San Manual
Casa Grande
Inspiration
Anaconda
Hurley
Gar field
Tacoma
Anaconda
Hidalgo Co.

ID
AZ
AZ
AZ
AZ
AZ
AZ
AZ
MT
NM
UT
WA
MT
NM

Capacity
250,000
600,000
250,000
260,000
100,000
525,000
89,000
460,000
230,000
200,000
600,000
50,000
100,000
580,000
4,294,000
                  194

-------
TABLE L-2.   EASTERN  SMELTERS SELLING BYPRODUCT  ACID

           IN $0.00 AND $0.35/MBTU  ACFL RUNS
	 ' 	 • 	 • 	 	 	 	 ~— — ~ 	 — , 	 	 	 __ 	
Company
New Jersey Zinc Company
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhard-Nat ' 1 Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmerton
Herculaneum
Corpus Christi
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middle ton
Langeloth
Ft. Madison

PA
MO
TX
IL
MO
OK
PA
TO
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average


Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
                      CANADIAN SMELTERS


                    Terminal   Tons sold
                    Buffalo
                    Detroit
165,000
 35,000
                         Total  200,000
                      WESTERN  SMELTERS
State Terminal Tons soia
Arizona
New Mexico
Utah
Montana
Houston
Chicago
Baton Rouge
Memphis
St . Louis
Memphis
118,000
304,000
76,000
96,000
46,000
98,000
                  Total
                                       738,000
                      TOTAL SMELTER ACID
                      East
                      West
                      Canada
 818,000
 738,000
 200,000
                       Total   1,756,000
                           195

-------
TABLE  L-3.   SMELTERS  SELLING BYPRODUCT ACID

            IN  $0.50/MBTU ACFL RUN
"
Company
New Jersey Zinc
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhard-Nat ' 1 Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmerton
Herculaneum
Corpus Christ!
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middleton
Langeloth
Ft. Madison

PA
MO
TX
IL
MO
OK
PA
TN
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average


Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
              CANADIAN SMELTERS

            Terminal   Tons sold

            Buffalo     200,000
            Detroit           0
             Total
200,000
             WESTERN SMELTERS
      State
     Total
                 Terminal
                              Tons sold
Arizona
New Mexico
Utah
Montana
Houston
Chicago
St. Louis
Baton Rouge
Houston
St. Louis

118,000
155,000
166,000
50,000
9,000
96,000
0
                               594,000
            TOTAL SMELTER ACID

            East     818,000
            West     594,000
            Canada   200,000

            Total  1,612,000
                    196

-------
TABLE L-4.   SMELTERS SELLING BYPRODUCT ACID

            _IN_$0. 70/MBTU ACFL RUN
Company
New Jersey Zinc
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhardt-Nat'l Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmer ton
Herculaneum
Corpus Christi
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middleton
Langeloth
Ft. Madison

PA
MO
TX
IL
MO
OK
PA
TN
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average


Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
                CANADIAN SMELTERS

             Terminal   Tons  sold
             Buffalo
             Detroit
200,000
	0
200,000
               WESTERN SMELTERS
       State
                   Terminal
       Tons sold
     Arizona      Houston

     New Mexico   Chicago

     Utah

     Montana

        Total
        118,000

         81,000

              0

        	0

        199,000
               TOTAL  SMELTER ACID
               East
               West
               Canada
 818,000
 199,000
 200,000
                Total   1,217,000
                       197

-------
                                APPENDIX M

                 SCRUBBING VERSUS CLEAN FUEL WHEN A.CFL IS

                           $0.70/MBTU HEAT INPUT


                                 CONTENTS

Tables                                                                  Page

 L-l    Estimated Compliance Strategies for the Thirty-Seven Eastern
        States		   200

 L-2    Estimated Compliance Strategies for the Western States ....   201
                                      199

-------
     TABLE M-l.   ESTIMATED COMPLIANCE STRATEGIES FOR THE
   THIRTY-SEVEN EASTERN STATES SCRUBBING VERSUS CLEAN FUEL
              WHEN ACFL IS $0.70/MBTU HEAT INPUT


Scrubbed
(-70c) Clean fuel (>70
-------
 TABLE M-2.  ESTIMATED COMPLIANCE STRATEGIES FOR THE WESTERN STATES
   SCRUBBING VERSUS CLEAN FUEL WHEN ACFL IS $0.70/MBTU HEAT INPUT


State
AZ
CA
NV
NM
WA
WY
Total
East
& West
Scrubbed

No. of
plants
0
0
2
0
0
1
3
116a 4
(<$0.70)
Abatement
capacity ,
ktons
STT c n
07 ^>U^


14,794 45,314


15,708 48,114
30,502 93,413
,108,963 12,583,699
Clean

No. of
plants
2
1
1
1
1
0
6
81a
fuel (>$0.70)
Abatement
capacity,
ktons
S H7
4,443 13
317
307
70
26

5,163 15
228,849 700




,609
971
940
214
80

,812
,850

a.  Ten plants are scrubbing and using clean fuel.
                                 201

-------
                                 APPENDIX N

         FEEDSTOCK ANALYSIS FOR S-BURNING ISO  PLANTS IN MODEL RUNS
                                  CONTENTS

Tables                                                                  Page

 N-I     Acid Plants Buying Abatement Byproduct Acid in  $0.00/MBtu
         ACFL Model Run .........  .  .............  .   205

 N-2     Acid Plants Buying Abatement Byproduct Acid in  $0.35/MBtu
         ACFL Model Run .  .  .....................  .   206

 N-3     Acid Plants Buying Abatement Byproduct Acid in  $0.50/MBtu
         ACFL Model Run .........  .  .  ..........  ...   207

 N-4     Acid Plants Buying Abatement Byproduct Acid in  $0.70/MBtu
         ACFL Model Run ....  ..............  ......   208

 N-5     Acid Plants Buying Abatement Byproduct Acid and Frasch S
         in $0.00/MBtu ACFL Model Run .......  ,  .  . .  ......   209

 N-6     Acid Plants Buying Abatement Byproduct Acid and Frasch S
         in $0.35/MBtu ACFL Model Run ....  ........  .....   210

 N-7     Acid Plants Buying Abatement Byproduct Acid and Frasch S
         in $0.50/MBtu ACFL Model Run ...............  .  .   211

 N-8     Acid Plants Buying Abatement Byproduct Acid and Frasch S
         in $0.70/MBtu ACFL Model Run .................   212

 N-9     Fifty-Eight Acid Plants Buying Frasch S Only in $0.00/MBtu
         ACFL Model Run ........................   213

 N-10    Forty-Two Acid Plants Buying Frasch S Only in $0.35/MBtu
         ACFL Model Run ........................   214

 N-ll    Thirty Acid Plants Buying Frasch S Only in $0.50/MBtu
         ACFL Model Run ........................   215

 N-12    Twenty-Eight Acid Plants Buying Frasch S Only in $0.70/MBtu
         ACFL Model Run ........................   216
                                 (continued)

                                     203

-------
                           APPENDIX N (continued)






                                  CONTENTS




Tables                                                                   Page




 N-13    Set I - $0.00/MBtu ACFL Model Run	217




 N-14    Set II - $0.35/MBtu ACFL Model Run	  .  218




 N-15    Set III - $0.50/MBtu ACFL Model Run	219




 N-16    Set IV - $0.70/MBtu ACFL Model Run	220
                                     204

-------
TABLE N-l.  ACID PLANTS BUYING ABATEMENT  BYPRODUCT ACID




              IN  $0.00/MBTU ACFL MODEL RUN
• 	 —
«
15
16
17
19
27
32
44
51
52
60
68
72
75
79
85
88
91
95
98
104
107
108
113
114
126
128
130
132
133
135
137
138
Company
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Borden Chemical
Detroit Chemical
E. I. Dupont
Eastman Kodak
W. R. Grace
Kerr-McGee
Minn Mine & Smelt
Monsanto Company
NL Industries
Olisi Corporation
Olin Corporation
Pennsalt Chemicals
Reichhold Chemical
Royster Company
Stauffer Chera
Swift Chemicals
Swift Chemicals
US Industrial
US Industrial
American Cyanamid
Home Guano Co
Columbia Nitrogen
Marion Mfg
E. I. Dupont
Cities Service
Allied Chemical
El Paso Products
TOTAL
Location
Bound Brook
Mobile
Joliet
Ka lama? oo
Tyner
Streator
Detroit
Cornwell Hghts
Rochester
Joplin
Cottondale
Copley
E. St. Louis
St. Louis
N. Little Rock
Pasadena
Tulsa
Tuscaloosa
Norfolk
Ft. Worth
Calumet City
Wilmington
Dubuque
Desoto
Fortier
Do than
Moultrie
Indianapolis
Gibbstown
Monmouth Jet
Cleveland
El Paso
i
NJ
AL
IL
MI
TN
IL
MI
PA
NY
MO
FL
OH
IL
MO
AR
TX
OK
AL
VA
TX
IL
NC
IA
KS
LA
AL
GA
IN
NJ
NJ
OH
TX
3
Average size
Average size
Capacity
65,000
26,000
50,000
25,000
132,000
40,000
35,000
75,000
6,000
98,000
15,000
65,000
265,000
455,000
105,000
500,000
110,000
55,000
20,000
120,000
40,000
32,000
98,000
105,000
50,000
11,000
24,000
56,000
110,000
35,000
130,000
86,000
,039,000
TPY
TPD
Year
1945
1967
1937
1967
1941
1951
1937
1941
1930
1954
1950
1942
1937
1958
1947
1946
1937
1957
1937
1925
1942
1942
1940
1940
1967
1937
1947
1947
1957
1971
1909
1967
94,968
286
Steam
plants Smelters
65,000
26,000
50,000
25,000
132,000
40,000
35,000
65,000
6,000
7,000
15,000
65,000
265,000
95,000
105,000
118,000
9,000
55,000
20,000
83,000
40,000
32,000
93,000
60,000
50,000
11,000
24,000
56,000
20,000
35,000
38,000
16,000
1,756,000

Port
Sulphur
0
0
0
0
0
0
0
10,000
0
91,000
0
0
0
360,000
0
382,000
101,000
0
0
37,000
0
0
5,000
45,000
0
0
0
0
90,000
0
92,000
70,000
1,283,000

Avoidable
production
cost
46.19
41.19
44.08
46.96
38.42
44.70
57.91
38.91
90.47
39.68
56.44
50.35
34.04
31.12
44.27
30.30
40.44
39.15
51.70
37.68
45.66
45.25
38.05
40.29
40.31
66.35
49.31
44.82
40.52
38.62
45.58
38.12

            Average year
                              1946
                        205

-------
TABLE N-2.  ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID




             IN $0.35/MBTU ACFL MODEL RUN
. . - 	 . 	 • — '

//
10
13
15
16
17
19
20
27
28
32
33
44
46
48
49
50
51
52
60
61
68
70
72
75
79
85
88
91
95
96
98
102
104
107
108
109
113
116
119
120

126
128
130
132

133
135
137
138


Company
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Army Ammunition
Borden Chemical
Borden Chemical
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Eastman Kodak
W. R. Grace
W. R. Grace
Kerr-McGee
LJ & M LaPlace
Minn Mine & Smelt
Monsanto
NL Industries
Olin Corporation
Olin Corporation
Pennsalt Chemicals
Relchhold Chemical
Royster Company
Royster Company
Stauffer Chemicals
Stauffer Chemicals
Swift Chem Co
Swift Chem Co
Swift Chem Co
US Industrial
USS Agri-Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer
American Cyanamid
Home Guano
Columbia Nitrogen
Marion
Manufacturing
E. I. Dupont
Cities Service
Allied Chemical
El Paso Products
TOTAL

Location
Nitro
Front Royal
Bound Brook
Mobile
Joliet
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Joplin
Charleston
Cottondale
Edison
Copley
E.St. Louis
St. Louis
Little Rock
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Navassa
Norfolk

Acme
Fortier
Do than
Moultrie

Indianapolis
Gibbstown
Monmouth Jet
Cleveland
El Paso




Capacity
WV
VA
NJ
AL
IL
MI
OH
TO
VA
IL
VA
MI
VA
OH
NJ
OH
PA
NY
MO
SC
FL
NJ
OH
IL
MO
AR
TX
OK
AL
FL
VA
AL
TX
IL
NC
VA
IA
NC
VA

NC
LA
AL
GA

IN
NJ
NJ
OH
TX

135
160
65
26
50
25
95
132
212
40
80
35
90
175
125
200
75
6
98
42
15
75
65
265
455
105
500
110
55
325
20
250
120
40
32
35
98
70
35

48
50
11
24

56
110
35
130
86
5,086
Average
Average
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000

,000
,000
,000
,000

,000
,000
,000
,000
,000
,000
TPY
TPD
Average Year

Year
1940
1945
1945
1967
1937
1967
1967
1941
1940
1951
1937
1937
1946
1956
1937
1937
1941
1930
1954
1937
1950
1967
1942
1937
1958
1947
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1967
1967

1968
1967
1937
1947

1947
1957
1971
1909
1967
2,
105,958
321
1948
Steam
plants
135,000
107,837
0
26,000
0
0
95,000
132,000
78,000
0
80,000
35,000
90,000
175,000
99,000
200,000
32,426
6,000
91,000
0
15,000
0
11,000
0
0
105,000
0
101,000
55,000
250,963
20,000
250,000
0
0
32,000
35,000
0
70,000
35,000

3,209
0
11,000
0

56 , 000
110,000
0
81,000
0
623,435



Avoidable
Port production
Smelters


65

50
25


134
40




26

42

7
42

57
54
265
455

127
9




83
40


60




50

24



35
49
16
1,756



0
0
,000
0
,000
,000
0
0
,000
,000
0
0
0
0
,000
0
,574
0
,000
,000
0
,426
,000
,000
,000
0
,000
,000
0
0
0
0
,000
,000
0
0
,000
0
0

0
,000
0
,000

0
0
,000
,000
,000
,000



Sulphur
0
52,163
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
17,574
0
0
0
0
373,000
0
0
74,037
0
0
37,000
0
0
0
38,000
0
0

44,791
0
0
0

0
0
0
0
70.000
706,565



cost
38.03
35.94
46.19
41.19
44.08
46.96
36.76
38.42
35.95
44.70
38.06
57.91
37.27
42.41
36.21
43.25
38.91
90.47
39.68
42.51
56.44
34.40
50.35
34.04
31.12
44.27
30.30
40.44
39.15
35.60
51.70
35.06
37.68
45.66
45.25
44.28
38.05
38.72
44.55

36.22
40.31
66.35
49.51

44.82
40.50
38.62
45.58
38.12




                           206

-------
TABLE N-3.  AC1.D PLANTS BUYING ABATEMENT  BYPRODUCT ACID




             IN $0.50/MBTU ACFL MODEL RUN
	
Steam
#
10
11
13
15
16
17
19
20
27
28
32
33
40
44
46
48
49
50
51
52
53
56
60
61
62
68
70
72
74
75
77
79
83
85
88
91
95
96
98
102
104
107
108
109
113
114
116
119
120

126
128
130
131
132

133
134
135
136
137
138

Company
Allied Chemical
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Army Ammunition
Borden Chemical
Borden Chemical
Cities Service
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Eastman Kodak
Essex Chemical
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Kerr-Mc.Gee
LJ & M LaPlace
Minn Mine & Smelt
Mobil Oil
Monsanto Co
Monsanto Co
NL Industries
Occidental Ag Chem
Olin Corporation
Olin Corporation
Fennsalt Chemicals
Reichhold Chemical
Royster Company
Royster Company
Stauffer Chemical
Stauffer Chemical
Swift Chemicals
Swift Chemicals
Swift Chemicals
US Industrial
US Industrial
USS Agri-Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer Co
American Cyanamid
Home Guano Co
Columbia Nitrogen
US Industrial Chem
Marion
Manufacturing
E. I. Dupont
E. I. Dupont
Cities Service Oil
USS Agri-Chem
Allied Chemicals
El Paso Products
TOTAL
Location
Nitro
Hopewell
Front Royal
Bound Brook
Mobile
Joliec
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Augusta
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Newark
Tampa
Joplin
Charleston
Bartow
Cottondale
Edison
Copley
Depue
E. St. Louis
El Dorado
St. Louis
Plainview
N. Little Rk
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Desoto
Navaasa
Norfolk

Acme
For tier
Dothan
Moultrie
Tuscola

Indianapolis
Gibbstown
Linden
Monmouth Jet
Wilmintgon
Cleveland
El Paso


WV
VA
VA
NJ
AL
IL
MI
OK
TN
VA
IL
VA
GA
MI
VA
OH
NJ
OH
PA
NY
NJ
FL
MO
SC
FL
FL
NJ
OH
IL
IL
AR
MO
TX
AR
TX
OK
AL
FL
VA
AL
TX
IL
KC
VA
IA
KS
NC
VA

NC
LA
AL
GA
IL

IN
NJ
NJ
NJ
NC
OH
TX

Average
Average
Capacity
135,000
200,000
160,000
65,000
26,000
50,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
175,000
125,000
200,000
75,000
6,000
180,000
450,000
98,000
42.000
320,000
15,000
75,000
65,000
420,000
265,000
100,000
455,000
100,000
105,000
500,000
110,000
55,000
325,000
20,000
250,000
120,000
40,000
32,000
35,000
98,000
105,000
70,000
35,000

48,000
50,000
11,000
24,000
170,000

56,000
110,000
325,000
35,000
70,000
130,000
86,000
7,651,000
TPY 127
TPD
Average Year
Year
1940
1965
1945
1945
1967
1937
1967
1967
1941
1940
1951
1937
1967
1937
1946
1956
1937
1937
1941
1930
1956
1937
1954
1937
1960
1950
1950
1942
1967
1937
1960
1958
1963
1947
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1940
1967
1967

1968
1967
1937
1947
1975

1947
1957
1937
1971
1968
1909
1967

,516
386
1950
Plants
135
200
160
65
26
50
25
95
132
12
40
80
125
35
90
175
99
198
75
6
28
450
91
42
6
15
26

420
145
100
176
95
92

101
55
325
20
250
37
40
32
35
98
45
70
35

48
50
11
24
170

56
110
46
35
70
94

5,370



,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,265
,000
,000
,000
,431
,000
,735
0
,000
,546
,000
,480
,195
,974
0
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000

,000
,000
,000
,000
,000

,000
,000
,751
,000
,000
,000
0
,377



Smelters









200






26
2


151

7



48
65

119

278

12
498
9




83




60














36
16
1,612



0
0
0
0
0
0
0
0
0
,000
0
0
0
0
0
0
,000
,000
0
G
,735
0
,000
0
0
0
,265
,000
0
,454
0
,520
0
,026
,000
,000
0
0
0
0
,000
0
0
0
0
,000
0
0

0
0
0
0
0

0
0
0
0
0
,000
,000
,000



Port
Sulphur
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
313,569
0
0
0
0
0
0
0
4,805
0
2,000
0
0
0
0
0
0
0
0
0
0
0
0
0

0
0
0
0
0

0
0
278,249
0
0
0
70,000
668,623



Avoidable
production
cost
38.03
35.50
35.94
46.19
41.19
44.08
46.96
36.76
38.42
35.95
44.70
38.06
32.51
57.91
37.27
42.41
36.21
43.25
38.91
90.47
33.20
34.17
39.68
42.51
33.81
56.44
34.40
50.35
31.19
34.04
35.03
31.12
36.84
44.27
30 . 30
40.44
39.15
35.60
51.70
35.06
37.68
45.66
45.25
44.28
38.05
40.29
38.72
44.55

36.22
40.31
66.35
49.51
32.12

44.82
40.50
32.78
38.62
33.94
45.58
38.12




                           207

-------
TABLE N-4.   ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID




             IN $0.70/MBTU ACFL MODEL RUN
	 . — . 	 . 	 . 	 , 	 , 	 • 	 • "

	 tl_
10
11
13
15
16
17
18
19
20
27
28
32
33
40
44
46
48
49
50
51
52
53
56
60
61
62
68
70
72
74
75
77
79
83
85
86
88
91
95
96
98
102
104
107
108
109
113
114
116
119
120

126
128
130
131
132

133
134
135
136
137
138





Company
Allied Chemical
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Array Ammunitions
Army Ammunitions
Borden Chemical
Borden Chemical
Cities Service
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E, I. Dupont
E. I. Dupont
Eastman Kodak
Essex Chem Co
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Kerr-McGee
LJ & M LaPlace
Minn Mine & Smelt
Mobil Oil
Monsanto
Monsanto
NL Industries
Occidental Ag Chem
Olin Corporation
Olin Corporation
Olin Corporation
Pennsalt Chemical
Reichhold Chemical
Royster Company
Royster Company
Stauffer Chemical
Stauffer Chemical
Swift Chem Co
Swift Chem Co
Swift Chem Co
US Industrial
US Industrial
USS Agri Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer Co
American Cyanamid
Home Guano Co
Columbia Nitrogen
US Industrial
Marion
Manufacturing
E. I. Dupont
E. I. Dupont
Cities Service
USS Agri Chem
Allied Chem
El Paso Products
TOTAL




Location
Nitro
Hopewell
Front Royal
Bound Brook
Mobile
Joliet
Savannah
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Augusta
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Newark
Tampa
Joplin
Charleston
Bartow
Cottondale
Edison
Copley
Depue
E. St. Louis
El Dorado
St. Louis
Plainview
N. Little Rck
Baltimore
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Desoto
Navassa
Norfolk

Acme
Fortier
Do than
Moultrle
Tuscola

Indianapolis
Gibbstown
Linden
Monmouth Jet
Wilmington
Cleveland
El Paso






WV
VA
VA
NJ
AL
IL
GA
MI
OH
TN
VA
IL
VA
GA
MI
VA
OH
NJ
OH
PA
NY
NJ
FL
MO
SC
FL
FL
NJ
OH
IL
IL
AR
MO
TX
AR
MD
TX
OK
AL
FL
VA
AL
TX
IL
NC
VA
IA
KS
NC
VA

NC
LA
AL
GA
IL

IN
NJ
NJ
NJ
NC
OH
TX





Capacity
135,000
200,000
160,000
65,000
26,000
50,000
216,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
175,000
125,000
200,000
75,000
6,000
180,000
450,000
98,000
42,000
320,000
15,000
75,000
65,000
420,000
265,000
100,000
455,000
100 , 000
105,000
350,000
500,000
110,000
55,000
325,000
20,000
250,000
120,000
40,000
32,000
35,000
98,000
105,000
70,000
35,000

48,000
50,000
11,000
24,000
170,000

56,000
110,000
325,000
35,000
70,000
130,000
86,000
8,217,000
Average
Average
Average

Year
1940
1965
1945
1945
1967
1937
1967
1967
1967
1941
1940
1951
1937
1967
1937
1946
1956
1937
1937
1941
1930
1956
1937
1954
1937
1960
1950
1967
1942
1967
1937
1960
1958
1963
1947
1941
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1940
1967
1967

1968
1967
1937
1947
1975

1947
1957
1937
1971
1968
1909
1967

TPY
TPD
year
Steam
plants
135,000
200,000
59,000
65,000
26,000
9,000
216,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
173,000
99,000
200,000
75,000
6,000
75,016
450,000
91,000
42,000
320,000
15,000
56,947
65,000
420,000
0
100,000
420,000
95,195
105,000
35,037
0
87,000
55,000
325,000
20,000
250,000
120,000
0
0
35,000
98,000
45,000
20,000
35,000

0
50,000
11,000
24,000
170,000

56,000
110,000
0
35,000
0
130,000
5,523
6,068,718
132,532
401
1950
Avoidable
Port production
Smelters


101


41










2
26



104

7



18


265

35



500
23





40
32


60
50


48







76

70

16
1,516



0
0
,000
0
0
,000
0
0
0
0
0
0
0
0
0
0
,000
,000
0
0
0
,984
0
,000
0
0
0
,053
0
0
,000
0
,000
0
0
0
,000
,000
0
0
0
0
0
,000
,000
0
0
,000
,000
0

,000
0
0
0
0

0
0
,963
0
,000
0
,000
,000



Sulphur
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
0
4,805
0
314,963
0
0
0
0
0
0
0
0
0
0
0
0
0
0

0
0
0
0
0

0
0
248,037
0
0
0
64,477
632,282



cost
38.
35.
35.
46.
41.
44.
29.
46.
36.
38.
35.
44.
38.
32.
57.
37.
42.
36.
43.
38.
90.
33.
34.
39.
42.
33.
56.
34.
50.
31.
34.
35.
31.
36.
44.
32.
30.
40.
39.
35.
51.
35.
37.
45.
45.
44.
38.
40.
38.
44.

36.
40.
66.
49.
32.

44.
40.
32.
38.
33.
45.
38.




03
50
94
19
19
08
80
96
76
42
95
70
06
51
91
27
41
21
25
91
47
20
17
68
51
81
44
40
35
19
04
03
12
84
27
48
30
44
15
60
70
06
68
66
25
28
05
29
72
55

22
31
35
51
12

82
50
78
62
94
58
12




                            208

-------
TABLE N-5.  ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH S




                   IN $0.00/MBTU ACFL MODEL RUN

Number
51
60
79
88
91
104
113
114
133
137
138

Acid plant
E. I. Dupont DeNeiaours
W. R, Grace
N. L. Industries
Olin Corporation
Permsalt Chemical
Stauffer Chemicals
U.S. Industrial Chemical
U.S. Industrial Chemical
E. I. Dupont DeNemours
Allied Chera Corporation
El Paso Products

Smelter Location
Canada-Buffalo
Amax Lead Company Salem (Buick) , Mo
St. Joe Minerals Herculaneum, Mo
American Metal (Amax)
Arizona-Houston
Engelhard-National Zinc Bartlesville, Ok
American Smelt (Asarco) Corpus Christi, Tx
New Mexico-Chicago
Climax Molybdenum Ft. Madison, la
New Jersey Zinc Co. Palmerton, Pa
Armco Steel
Climax Molybdenum Langeloth, Pa
Amer Smelt (Asarco) El Paso, Tx
Acid demand balance
Addition
acid
demand
tons/yr
10,000
91,000
360,000
382,000
101,000
37,000
5,000
45,000
90,000
92,000
70,000
1,283,000
                                 209

-------
TABLE N-6.  ACID PLANTS  BUYING ABATEMENT BYPRODUCT  ACID AND FRASCH S




                     IN  $0.35/MBTU ACFL MODEL RUN

Number
70
88
104
113
138
Number
13
96
120
Acid plant Smelter
LJ & M Canada-Buffalo
Olin Corporation Arizona; New Mexico-
Houston
Stauffer Chemical American Smelt (Asarco)
U.S. Industrial Chemical Climax Molybdenum
El Paso American Smelt (Asarco)
Company Steam plant
Allied Chemical Paradise
Royster Company Big Bend
Acme (Wright) Fert Belews Creek
Location
Canada
Arizona; New Mexico
Corpus Christi, Tx
Fort Madison, la
El Paso, Tx
Subtotal
Number
6 4770003000
5 4740000300
1 1395000250
Subtotal
Additional
acid
demand
tons/yr
17,574
373,000
37,000
38,000
70,000
535,574
Additional
acid demand
tons/yr
52,163
74,037
44,791
170,991
                                                Acid demand balance    706,565
                                 210

-------
TABLE N-7.  ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH  S




                     IN $0.50/MBTU ACFL  MODEL RUN
. 	 _
Number Acid plant
88 Olin Corporation
138 El Paso Products
Number Company
62 W. R. Grace

83 Occidental Ag. Chem
134 E. I. Dupont DeNemours
Smelter
Arizona; New Mexico-
Houston
Asarco
Steam plant
Crystal River
Wansley
Harrington
Roseton
Additional
acid demand
Location tons/yr
Arizona ;New Mexico 2,000
El Paso 70,000
Subtotal 72,000
Additional
acid demand
Number tons/yr
14 1655000300 313,569
15 1790002550
29 4530000850 4,805
3 7000000550 278,249
Subtotal 596,623
                                                 Acid demand balance  668,623
                                211

-------
TABLE N-8.  ACID PLANTS  BUYING ABATEMENT BYPRODUCT ACID AND FRASCH  S




                    IN $0.70/MBTU ACFL MODEL  RUN

Number
134
138
Number
83
86
Company Buying Smelter
E. I. Dupont DeNemours Canada-Buffalo
El Paso Products Asarco
Company Buying Steam plant
Occidental Ag Chem Harrington
Olin Corporation Homer City
Additional
acid demand
Smelter Location tons/yr
Canada 248,037
El Paso 64,477
Subtotal 312,514
Additional
acid demand
Number tons/yr
41 4530000850 4,805
34 3795000350 314,963
Subtotal 319,768
                                              Acid demand balance   632,282
                                212

-------
TABLE N-9.  FIFTY-EIGHT ACID PLANTS BUYING FRASCH S ONLY




              IN $0,00/MBTU ACFL MODEL RUN
	 	 — 	 	 	
Avoidable
production
#
1
2
7
10
11
13
18
20
21
28
31
33
34
36
37
38
40
43
46
48
49
50
53
54
55
56
57
58
61
62
63
66
67
70
73
74
76
77
83
84
86
96
102
109
110
111
115
116
117
119
120
127
129
131
134
136
142
176



Company
Agrico Chem-Williams
Agrico Chem-Williams
Allied Chemical
Allied Chemical
A3 lied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition Pit
Beker Industries
Borden Chemical
Borden Chemical
CF Industries
CF Industries
CF Industries
Cities Service
Delta Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Essex Chemical
Farmland industries
Freeport Minerals
Gardinier
Gardinier
Gardinier
W. E. Grace
W. R. Grace
W. R. Grace
International Miner
W. R. Grace
LJ & M LaFlace
Miss Chem Corporation
Kcbii Oil
Monsanto
Monsanto
Occidental Ag Chen
Occidental Ag Chem
Olin Corporation
Royster Company
Stauffer Chemicals
Swift Chemicals
Swift Chemicals
Texas gulf Inc.
USS Agri Chem
USS Agri Chem
USS Agri Chem
Weaver Fertilizer
Acme (Wright) Pert Co
ML Industries
Englehardt McConser
US Industrial Chem
E. I. Dupont
USS Agri Chem
American Cyanamid
Texas gulf Inc.
TOTAL


Location
Pierce
Donaldsville
Geismar
Nitro
Hopewell
Front Royal
Savannah
Hamilton
Linden
Radford
Taft
Norfolk
Port Manatee
Plant City
Bonnie
Bonnie
Augusta
Searsport
Richmond
North Bend
Deepwater
Cleveland
Newark
Pierce
Uncle Sam
Tampa
Tampa
Tampa
Charleston
Bar tow
Bar tow
Bonnie
Bartow
Edison
Pascagoula
Dupue
Everett
El Dorado
Plainview
White Springs
Baltimore
Mulberry
LeMoyne
Norfolk
Agricola
Lee Creek
Bartow
Navassa
Ft. Meade
Norfolk
Acme
Sayreville
Nichols
Tuscola
Linden
Wilmington
Fortier
Lee Creek

Average TPY 503
Average TPD 1
Average year

FL
LA
LA
WV
VA
VA
GA
OH
NJ
VA
LA
VA
FL
FL
FL
FL
GA
ME
VA
OH
NJ
OH
NJ
FL
LA
FL
FL
FL
SC
FL
FL
FL
FL
NJ
MS
IL
MA
AR
TX
FL
MD
FL
AL
VA
FL
NC
FL
NC
FL
VA
NC
NJ
FL
IL
NJ
NC
LA
NC

,414
,525
1961
Capacity
1,200,000
1,200,000
500,000
135,000
200,000
160,000
216.000
95,000
245,000
212,000
525,000
80,000
490,000
1,550,000
1,190,000
660,000
125,000
75,000
90,000
175,000
125,000
200,000
180,000
1,226,000
2,160,000
450,000
1,050,000
883,000
42,000
320,000
480,000
1,980,000
1,280,000
75,000
1,220,000
420,000
120,000
100,000
100,000
1,650,000
350,000
325,000
250,000
35,000
220,000
1,357,000
280,000
70,000
540,000
35,000
48,000
560,000
400,000
170,000
325,000
70,000
530,000
449,000
29,198,000



Year
1975
1975
1968
1940
1965
1945
1967
1967
1970
1940
1965
1937
1967
1967
1967
1976
1967
1942
1946
1956
1937
1937
1956
1965
1969
1937
1974
1977
1937
1960
1960
1975
1977
1967
1958
1967
1969
1960
1963
1967
1941
1976
1957
1946
1976
1966
1964
1976
1963
1976
1968
1937
1945
1975
1937
1968
1978
1976




cost
25.64
28.45
27.26
38.03
35.50
35.94
29.80
36.76
29.82
35.95
27.53
38.06
27.60
25.85
26.35
26.21
32.51
39.36
37.27
42.41
36.21
43.25
33.20
26,50
25.23
34.17
28.26
31.72
42.41
33.81
32.49
25.19
30.96
34.40
27.27
31.19
32.30
35.03
36.84
26.87
32.48
35.60
35.06
44.28
32.73
30.30
29.12
38.72
27.92
44.55
36.22
31.41
30.88
32.12
32.78
33.94
29.75
31.76




                            213

-------
TABLE  N-10.   FORTY-TWO  ACID PLANTS BUYING FRASCH S ONLY

               IN $0.35/MBTU ACFL MODEL  RUN



ft
I
2
7
11
18
21
31
34
36
37
38
40
43
53
54
55
56
57
58
62
63
66
67
73
74
76
77
83
84
86
110
111
114
115
117
127
129
131
134
136
142
176



Company
Agrico Chem-Williams
Agrico Chem-Williams
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
Beker Industries
Borden Chemical
CF Industries
CF Industries
CF Industries
Cities Service
Delta Chemicals
Essex Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardihier
Gardinier
W. R. Grace
W. R. Grace
International Miner
W. R. Grace
Miss Chen Corporation
Mobil Oil
Monsanto
Monsanto
Occidental Ag Chem
Occidental Ag Chem
01 In Corporation
Swift Chemicals
Texas gulf Inc.
US Industrial Chem
USS Agri Chem
USS Agri Chem
NL Industries
Englehardt McConser
US Industrial Chem
E. I. Dupont
USS Agri Chem
American Cynamid
Texas gulf Inc.
TOTAL


Locat ion
Pierce
Donaldsville
Geismar
Hopewell
Savannah
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Augusta
Searsport
Newark
Pierce
Uncle Sam
Tampa
Tampa
Tampa
Bartow
Bartow
Bonnie
Bartow
Pascagoula
Dupue
Everett
£1 Dorado
Plainview
White Springs
Baltimore
Agricola
Lee Creek
Desoto
Bartow
Ft. Meade
Sayreville
Nichols
Tuscola
Linden
Wilmington
Fortier
Lee Creek




FL
LA
LA
VA
GA
NJ
LA
FL
FL
FL
FL
GA
ME
NJ
FL
LA
FL
FL
FL
FL
FL
FL
FL
MS
IL
MA
AR
TX
FL
MD
FL
NC
KS
FL
FL
NJ
FL
IL
NJ
NC
LA
NC



Capacity
1,200,000
1,200,000
500,000
200,000
216,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
125,000
75,000
180,000
1,226,000
2,160,000
450,000
1,050,000
883,000
320,000
480,000
1,980,000
1,280,000
1,220,000
420,000
120,000
100,000
100,000
1,650,000
350,000
220,000
1,357,000
105,000
280,000
540,000
560,000
400,000
170,000
325,000
70,000
530,000
449.000
27,151,000


Year
1975
1975
1968
1965
1967
1970
1965
1967
1967
1967
1976
1967
1942
1956
1965
1969
1937
1974
1977
1960
1960
1975
1977
1958
1967
1969
1960
1963
1967
1941
1976
1966
1940
1964
1963
1937
1945
1975
1937
1968
1978
1976

Avoidable
production
cost
25.64
28.45
27.26
35.30
29.80
29.82
27.53
27.60
25.85
26.35
26.21
32.51
39.36
33.20
26.50
25.23
34.17
28.26
31.72
33.81
32.49
25.19
30.96
27.27
31.19
32.30
35.03
36.84
26.87
32.48
32.73
30.30

29.12
27.92
31.41
30.88
32.12
32.78
33.94
29.75
31.76

                    Average TPY 646,452
                    Average TPD   1,958
                   Average year
                                1964
                               214

-------
TABLE N-ll.   THIRTY  ACID PLANTS  BUYING FRASCH  S  ONLY

              IN $0.50/MBTU ACPL  MODEL RUN
-- • - — 	 	 --- - - - — 	 — 	 	 	


J_
I
2
7
18
21
31
34
36
37
38
43
54
55
57
58
63
66
67
73
76
84
86
110
111
115
117
127
129
142
176



Company
Agrico Chem Williams
Agrico Chem Williams
Allied Chemical
American Cyanamid
American Cyanamid
Beker Industries
Borden Chemicals
CF Industries
CF Industries
CF Industries
Delta Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardinier
W. R. Grace
International Miner
W. R. Grace
Miss Chem Corporation
Monsanto
Occidental Ag Chem
Olin Corporation
Swift Chemicals
Texasgulf Inc.
USS Agri Chem
USS Agri Chem
NL Industries
Englehardt McConser
American Cyanamid
Texasgulf Inc.
TOTAL


Location
Pierce
Donaldsville
Geismar
Savannah
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Searsport
Pierce
Uncle Sam
Tampa
Tampa
Bar tow
Bonnie
Bartow
Pascagoula
Everett
White Springs
Baltimore
Agricola
Lee Creek
Bartow
Ft . Meade
Sayreville
Nichols
Fortier
Lee Creek




FL
LA
LA
GA
NJ
LA
FL
FL
FL
FL
ME
FL
LA
FL
FL
FL
FL
FL
MS
MA
FL
MD
FL
NC
FL
FL
NJ
FL
LA
NC



Capacity
1,200,000
1,200,000
500,000
216,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
75,000
1,226,000
2,160,000
1,050,000
883,000
480,000
1,980,000
1,280,000
1,220,000
120,000
1,650,000
350,000
220,000
1,357,000
280,000
540,000
560,000
400,000
530,000
449,000
24,586,000


Year
1975
1975
1968
1967
1970
1965
1967
1967
1967
1976
1942
1965
1969
1974
1977
1960
1975
1977
1958
1969
1967
1941
1976
1966
1964
1963
1937
1945
1978
1976

Avoidable
production
cost
25.64
28.45
27.26
29.80
29.82
27.53
27.60
25.85
26,35
26.21
39.36
26.50
25.23
34.17
31.72
32.49
25.19
30.96
27.27
32.30
26.87
32.48
32.73
30.30
29.12
27.92
31.41
30.88
29.75
31.76

                  Average TPY  819,533
                  Average TPD    2,483
                 Average year     1966
                            215

-------
TABLE N-12.   TWENTY-EIGHT ACID  PLANTS BUYING  FRASCH S ONLY

                IN $0.70/MBTU ACFL MODEL RUN



//
1
2
7
21
31
34
36
37
38
43
54
55
57
58
63
66
67
73
76
84
110
111
115
117
127
129
142
176



Company
Agri Chem Williams
Agri Chem Williams
Allied Chemical
American Cyanamid
Beker Industries
Borden Chemicals
CF Industries
CF Industries
CF Industries
Delta Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardinier
W. R. Grace
International Miner
W. R. Grace
Miss. Chem Corporation
Monsanto
Occidental Ag Chem
Swift Chemicals
Texasgulf Inc.
USS Agri Chem
USS Agri Chem
ML Industries
Englehardt McConser
American Cyanamid
Texasgulf Inc
TOTAL


Location
Pierce
Donaldsville
Geismar
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Searsport
Pierce
Uncle Sam
Tampa
Tampa
Bartow
Bonnie
Bartow
Pascagoula
Everett
White Springs
Agricola
Lee Creek
Bartow
Ft. Meade
Sayreville
Nichols
Fortier
Lee Creek




FL
LA
LA
NJ
LA
FL
FL
FL
FL
ME
FL
LA
FL
FL
FL
FL
FL
MS
MA
FL
FL
NC
FL
FL
NJ
FL
LA
NC



Capacity
1,200,000
1,200,000
500,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
75,000
1,226,000
2,160,000
1,050,000
883,000
480,000
1,980,000
1,280,000
1,220,000
120,000
1,650,000
220,000
1,357,000
280,000
540,000
560,000
400,000
530,000
449,000
24,020,000


Year
1975
1975
1968
1970
1965
1967
1967
1967
1976
1942
1965
1969
1974
1977
1960
1975
1977
1958
1969
1967
1976
1966
1964
1963
1937
1945
1978
1976

Avoidable
production
cost
25.64
28.45
27.26
29.82
27.53
27.60
25.85
26.35
26.21
39.36
26.50
25.23
28.26
31.72
32.49
25.19
30.96
27.27
35.03
26.87
32.73
30.30
29.12
27-92
31.41
30.88
29.75
31.76

                 Average TPY  857,857
                 Average TPD    2,599
                Average year
1967
                              216

-------
             TABLE  N-13.   SET  1  - $0.00/MBTU ACFL  MODEL  RUN
   ff	Name	


   51   E.  I.  Dupont
   60   W.  R.  Grace
   79   NL Industries
   88   Olin Corporation
   91   Pennsalt  Chem
  104   Stauffer  Chem
  113   US Industrial  Chem
  114   US Industrial  Chem
  133   E.  I.  Dupont
  137   Allied Chem Corp
  138   El Paso Products

       TOTALS
"
lependent on abatement byproduct acid supplies

Location
Cornwell Hts.
Joplin
St. Louis
Pasadena
Tulsa
Ft. Worth
Dubuque
Desoto
Gibbstown
Cleveland
El Paso



PA
MO
MO
TX
OK
TX
IA
KS
NJ
OH
TX


Demand
75
98
455
500
110
120
98
105
110
130
86
1,887
Port
Sulphur
10
91
360
382
101
37
5
45
90
92
70
1,283

Abatement
65
7
95
118
9
83
93
60
20
38
16
604
 IB - Supply points not  satisfying total demand requirements


Area
Canada
Eastern
Eastern
Eastern
Eastern
West
West
Eastern
Eastern
Eastern
West
Eastern
Eastern
Eastern
Eastern
Eastern
ui J. J_il
-------
                 TABLE  N-14.   SET  TI  - $0.35/MBTU ACFL MODEL RUN
                                                            Port
     //           Name             Location        Demand   Sulphur   Abatement
     13   Allied Chem Corp
     70   LJ & M LaPlace Cde
     88   Olin Corporation
     96   Royster Co.
    104   Stauffer Chem Co.
    113   US Industrial Chem
    120   Acme (Wright) Pert
    138   El Paso Products

         TOTALS

>endent on abatement byprod
Location
Front Royal
Edison
Pasadena
Mulberry
Ft. Worth
Dubuque
Acme
El Paso

VA
NJ
TX
FL
TX
IA
NC
TX
Demand
160
75
500
325
120
98
48
86
                                       1,412
                            52.163
                            17.574
                           373.000
                            74.037
                            37.000
                            38.000
                            44.791
                            70.000

                           706.565
        107.837
         57.426
        127.000
        250.963
         83.000
         60.000
          3.209
         16.000

        705.435
   IIB - Supply points not satisfying total demand requirements

   SMELTERS
 Area

Canada
Western
Western
Eastern
Eastern
Eastern
Eastern
    Smelter
Amer Smelt (Asarco)
Amer Smelt (Asarco)
Climax Molybdenum
Amer Smelt (Asarco)
Location
 Canada
 Arizona
 New Mexico
 Corpus Christi TX
 Corpus Christi TX
 Ft Madison     IA
 El Paso        TX

Potential
demand
75
500
500
120
120
98
86

Amount
selling
57.426
118.000
9.000
7.000
76.000
60.000
16.000

Demand
balance
17.574
373.000
0.000
37.000
0.000
38.000
70.000
Acid
plant
No
70
88
88
104
104
113
138
     TOTALS
                                                      879
                                                     343.426    535.574
POWER PLANTS
  Number	

6 4770003000
5 4740000300
1 1395000250

     TOTALS
                      Location

                      Kentucky
                      Florida
                      North Carolina
                   Potential   Amount
                     demand   selling
                      160
                      325
                       48

                      533
107.837
250.963
  3.209
                    Acid
           Demand   plant
           balance   No
52.163
74.037
44.791
 13
 96
120
                                                               362.009    170.991
                                         218

-------
                 TABLE N-15.   SET 111  - $0.50/MBTU  ACFL  MODEL  RUN
IIIA - Acid plants partly dependent on abatement byproduct acid supplies
  if

  62
  83
  88
 134
 138
       Name
                        Location
 W.  R.  Grace & Co.
 Occidental Ag Chem
 Olin Corporation
 E.  I.  Dupont
 El Paso Products

TOTALS
Bartow
Plainview
Pasadena
Linden
El Paso
FL
TX
TX
NJ
TX
Capacity

  320
  100
  500
  325
   86
                                              1,331
 Port
Sulphur

313.569
  4.805
  2.000
278.249
 70.000
Abatement

   6.431
  95.195
 498.000
  46.751
  16.000
                                                  668.623   662.377
 IIIB - Supply points not satisfying total demand requirements
 SMELTERS
  Area
         Smelter
 Western
 Western
 Eastern   Amer Smelt (Asarco)

      TOTALS
      Location	

      Arizona
      New Mexico
      El Paso    TX
         Potential
           demand

             500
             500
              86

             586
                Amount
                selling

                  118
                  380
                   16

                  514
                         Acid
                Demand   plant
                balance    No.
                                                                   2.
                                                                   0.
                                                                   70.

                                                                   72
                          88
                          88
                         138
 POWER PLANTS

     Number

 14 1655000300
 15 1790002550
 29 4530000850
  3 0700000550

      TOTALS
                Location
             Florida
             Georgia
             Texas
             New York
           Potential
             demand

              320
              320
              100
              325

              745
          Amount
          selling

           2.101
           4.330
          95.195
          46.751

         148.377
                                                                Acid
                                                        Demand   plant
                                                       balance    No.
                 0.
               313.569
                 4.805
               278.249

               596.623
               62
               62
               83
               134
                                        219

-------
                TABLE N-16.   SET  LV - $0.70/MBTU ACFL MODEL  RUN
IVA - Acid plants partly  dependent on abatement byproduct acid supplies
             Name
                              Location
                                             Port
                                   Capacity Sulphur
                                                               Abatement
83
86
134
138
Occidental Ag Chem
Olin Corporation
E. I. Dupont
El Paso Products
Plainview
Baltimore
Linden
El Paso
TX
MD
NJ
TX
100
350
325
86
4.805
314.963
248.037
64.477
95.195
35.037
76.963
21.523
     TOTALS
                                     861   632.282
                                                                228.718
IVB - Supply points not satisfying total  demand  requirements
SMELTERS

 Area
               Smelter
                                Location
 Canada
Eastern
Amer Smelt (Asarco)
Canada
El Paso  TX
                                                                     Acid
                                       Potential   Amount   Demand   plant
                                         demand   selling  balance    No.
325
86
411
76.963
16 . 000
92.963
248.037
64.477
312.514
134
138
POWER PLANTS
    Number

41 4530000850
34 3795000350
 7 1000000050

     TOTALS
         Location

        Texas
        Pennsylvania
        Texas

Potential
demand
100
350
(86)

Amount
selling
95.195
35.037
5.523

Demand
balance
4.805
314.963
0.000
Acid
plant
No.
83
86
138
                          450
             135.755  319.768
                                         220

-------
                                APPENDIX 0




                SIZE AND OWNERSHIP OF S-BURNING ACID PLANTS







                                 CONTENTS




Tables                                                                 Page




 0-1    S-Burning Acid Plants Ordered by Size of Plant (1978) .....  222




 0-2    S-Burning Acid Plant Capacity by Firm (1978)	224
                                    221

-------
TABLE 0-1.   S-BURNING ACID PLANTS ORDERED BY SIZE OF PLANT (1978)
— 	 	 -..-... . . . _ . — . 	 . 	 . 	 _ 	

No.
55
66
84
36
111
67
54
73
1
2
37
57
58
38
127
117
142
31
7
88
34
63
79
56
176
74
129
86
96
134
62
115
75
102
21
110
18
28
11
50
53
48
131
13
10
27
137
40
49
76
104
91
133
85
114
77
83
60
113
20
46
138
33
43
51
70
136

Company
Freeport Minerals
International Miner
Occidental Ag Chem
C. F. Industries
Texasgulf Inc.
W. R. Grace
Farmland Industries
Miss. Chem Corp
Agri Chem Williams
Agri Chem Williams
C. F. Industries
Gardinier
Gardinier
C. F. Industries
N. L. Industries
USS Agri Chem
American Cyanamid
Beker Industries
Allied Chemical
Olin Corp
Borden Chemicals
W. R. Grace
N. L. Industries
Gardinier
Texasgulf Inc.
Mobil Oil
Englehardt McConserv
Olin Corporation
Royster Company
E. I. Dupont
W. R. Grace
USS Agri Chem
Monsanto
Stauffer Chemical
American Cyanamid
Swift Chemicals
American Cyanamid
Army Ammunitions
Allied Chemical
E. I. Dupont
Essex Chem Co
E. I. Dupont
U.S. Industrial
Allied Chemical
Allied Chemical
Army Ammunitions
Allied Chemical
Cities Service
E. I. Dupont
Monsanto
Stauffer Chemical
Pennsalt Chemical
E. I. Dupont
Olin Corporation
U. S. Industrial
Monsanto
Occidental Ag Chem
W. R. Grace
U. S. Industrial
American Cyanamid
E. I. Dupont
El Paso Products
Borden Chemical
Delta Chemicals
E. I. Dupont
LJ (. M LaPlace
USS Agri Chera

Location
Uncle Sam
Bonnie
White Springs
Bonnie
Lee Creek
Bartou
Pierce
Pascagoula
Pierce
Donaldsville
Bonnie
Tampa
Tampa
Bonnie
Sayrevllle
Ft. Meade
Fortier
Taft
Geismar
Pasadena
Port Manatee
Bartow
St. Louis
Tampa
Lee Creek
Depue
Nichols
Baltimore
Mulberry
Linden
Bartow
Bartow
E. St. Louis
LeMoyne
Linden
Agricola
Savannah
Radford
Hopewell
Cleveland
Newark
North Bend
Tuscola
Front Royal
Nitro
Tyner
Cleveland
Augusta
Deepwater
Everett
Fort Worth
Tulsa
Gibbstown
N. Little Rock
Desoto
El Dorado
Plainview
Joplin
Dubuque
Hamilton
Richmond
El Paso
Norfolk
Searsport
Cornwell Hgts.
Edison
Wilmington

Yr
con-
struc ted
LA
FL
FL
FL
NC
FL
FL
MS
FL
LA
FL
FL
FL
FL
NJ
FL
LA
LA
LA
TX
FL
FL
MO
FL
NC
IL
FL
MD
FL
NJ
FL
FL
IL
AL
NJ
FL
GA
VA
VA
OH
NJ
OH
IL
VA
WV
TN
OH
GA
NJ
MA
TX
OK
NJ
AR
KS
AR
TX
MO
IA
OH
VA
TX
VA
ME
PA
NJ
1969
1975
1967
1967
1966
1977
1965
1958
1975
1975
1967
1974
1977
1976
1937
1963
1978
1965
1968
1946
1967
1960
1958
1937
1976
1967
1945
1941
1967
1937
1960
1964
1937
1957
1970
1976
1967
1940
1965
1937
1956
1956
1975
1945
1940
1941
1909
1967
1937
1969
1925
1937
1957
1947
1940
1960
1963
1954
1940
1967
1947
1967
1937
1942
1941
1967
NC 1968
Capac ity ,
annual
tons
2,160,000
1,980,000
1,650,000
1,550,000
1,357,000
1,280,000
1,226,000
1,220,000
1,200,000
1,200,000
1,190,000
1,050,000
883,000
660,000
560,000
540,000
530,000
525,000
500,000
500,000
490,000
480,000
455,000
450,000
449,000
420,000
400,000
350,000
325,000
325,000
320,000
280,000
265,000
250,000
245,000
220,000
216,000
212,000
200,000
200,000
180,000
175,000
170,000
160,000
135,000
132,000
130,000
125,000
125,000
120,000
120,000
110,000
110,000
105,000
105,000
100,000
100,000
98,000
98,000
95,000
90,000
86,000
80,000
75,000
75,000
75,000
70,000
Capacity
replaced by
abatement acid
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
500,000
0
0
455,000
450,000
0
420,000
0
35,037
325,000
76,963
320,000
0
265,000
250,000
0
0
216,000
212,000
200,000
200,000
180,000
175,000
170,000
160,000
135,000
132,000
130,000
125,000
125,000
0
120,000
110,000
110,000
105,000
105,000
100,000
95,195
98,000
98,000
95,000
90,000
21,523
80,000
0
75,000
75,000
70,000
	 	
(continued)


222





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                         TABLE  0-1   (continued)

No.
116
15
72
132
95
17
126
120
61
32
107
44
109
119
135
108
16
19
130
98
68
128
52

Company
USS Agrl Chem
American Cyanamid
Minn. Mine & Smelt
Marion Manufacturing
Reichold Chemical
American Cyanamid
American Cyanamid
Acme (Wright) Fert Co
W. R. Grace
Borden Chemical
Swift Chem Company
Detroit Chemical
Swift Chem Company
Weaver Fertilizer
Cities Service
Swift Chem Company
American Cyanamid
American Cyanamid
Columbia Nitrogen
Royster Company
Kerr-McGee
Home Guano Company
Eastman Kodak

Location
Navassa
Bound Brook
Copley
Indianapolis
Tuscaloosa
Joliet
Fortier
Acme
Charleston
Streator
Calumet City
Detroit
Norfolk
Norfolk
Momnouth Jet
Wilmington
Mobile
Kalamazoo
Moultrie
Norfolk
Cottondale
Do than
Rochester

Year
con-
Capacity,
annual
strutted tons
NC
NJ
OH
IN
AL
IL
LA
NC
SC
IL
IL
MI
VA
VA
NJ
NC
AL
MI
GA
VA
FL
AL
NY
1967
1945
1942
1947
1957
1937
1967
1968
1937
1951
1942
1937
1946
1967
1971
1944
1967
1967
1947
1937
1950
1937
1930
70,000
65,000
65,000
56,000
55,000
50,000
50,000
48,000
42,000
40,000
40,000
35,000
35,000
35,000
35,000
32,000
26,000
25,000
24,000
20,000
15,000
11,000
6,000
Capacity
replaced by
abatement
acid
70,000
65,000
65,000
56,000
55,000
50,000
50,000
48,000
42,000
40,000
40,000
35,000
35,000
35,000
35,000
32,000
26,000
25,000
24,000
20,000
15,000
11,000
6,000
Total
32,237,000   7,584,716
                                223

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TABLE 0-2.  S-BURNING ACID PLANT CAPACITY BY FIRM  (1978)

Name
C. F. Industries Inc.
Agrico Chem
Gardinier
W. R. Grace
Freeport Mineral
International Miner
Texas gulf Inc.
Occidental Ag
American Cyanamid
Farmland Industries
Miss. Chem Corp
Allied Chem Corp
E. I. Dupont DeNemours
N. L. Industries
USS Agri-Chem
Olin Corp
Borden Chemical
Beker Industries
Monsanto Company
Mobil Oil
Englehardt McConser
U.S. Industrial Chem
Stauffer Chem
Royster Company
Army Ammunition Plant
Swift Chem Co.
Essex Chemical Co.
Cities Service Oil
Pennsalt Chemicals
El Paso Chem
Delta Chemical
LJ & M LaPlace Cde
Minn. Mining & Smelting
Marion Manufacturing
Reichold Chemicals
Acme Fertilizer Company
Detroit Chemical
Weaver Fertilizer
Columbia Nitrogen
Kerr-McGee
Home Guano Co .
Eastman Kodak
Total capacity
[ tons ]
Capacity [ yr ]
3,400,000
2,400,000
2,383,000
2,220,000
2,160,000
1,980,000
1,806,000
1,750,000
1,302,000
1,226,000
1,220,000
1,125,000
1,100,000
1,015,000
960,000
955,000
610,000
525,000
485,000
420,000
Dr 400, 000
373,000
370,000
345,000
344,000
327,000
180,000
160,000
110,000
86,000
75,000
75,000
65,000
56,000
55,000
48,000
35,000
35,000
24,000
15,000
11,000
6,000
32,237,000
Number
of
plants
3
2
3
5
1
1
2
2
9
1
1
5
7
2
4
3
3
1
3
1
1
3
2
2
2
4
1
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Buying abate-
ment acid at
$0.70/MBtu ACFL
0
0
1
3
0
0
0
1
7
0
0
4
7
1
2
3
2
0
2
1
0
3
2
2
2
3
1
2
1
1
0
1
1
1
1
1
1
1
1
1
1
1



Top 5 companies
14 of 90 plants
12,563,000 tons
38.97%

Top 10 companies
29 of 90 plants
20,627,000 tons
63.99%

Top 15 companies
48 of 90 plants
26,047,000 tons
80.79%

Top 20 companies
59 of 90 plants
29,042,000 tons
90.09%























                           224

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                                APPENDIX P

             ACID PLANTS OUT OF COMPLIANCE, RETROFIT COST, AND

                  CANDIDATES FOR PURCHASE OF BYPRODUCT ACID


                                 CONTENTS

Table                                                                  Page

 P-l    Acid Plants Out of Compliance, Retrofit Cost, and
        Candidates for Purchase of Byproduct Acid	226
                                     225

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                       TABLE P-l.  ACID  PLANTS OUT OF  COMPLIANCE, RETROFIT COST, AND




                                  CANDIDATES FOR PURCHASE OF BYPRODUCT  ACID
No.
2
11
15
44
48
50
56
57
58
62
63
67
72
85
96
102
111
133
137
176
Company
Agrico Chem-Williams
Allied Chemical
American Cyanamid
Detroit Chemicals
E. I. Dupont
E. I. Dupont
Gardinier
Gardinier
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Minn Mine & Smelting
Olin Corporation
Royster Company
Stauffer Chemicals
Texasgulf Inc.
E. I. Dupont
Allied Chemicals
Texasgulf Inc.
Location
Donaldsville
Hopewell
Bound Brook
Detroit
North Bend
Cleveland
Tampa
Tampa
Tampa
Bartow
Bartow
Bartow
Copley
N. Little Rock
Mulberry
LeMoyne
Lee Creek
Glbbstown
Cleveland
Lee Creek

LA
VA
NJ
MI
OH
OH
FL
FL
FL
FL
FL
FL
OH
AR
FL
AL
NC
NJ
OH
NC
Avoidable
production
cost, $/ton
28.45
35.50
46.19
57.91
42.41
43.25
34.17
28.56
31.72
33.81
32.49
30.96
50.35
44.27
35.60
35.06
30.30
40.50
45.58
31.76
Purchase from
Retrofit smelters
cost, $/ton only
2.80
4.69
6.49 X
7.76 X
4.88
4.69
3.71
2.91
3.06
4.10
3.65
2.75
6.49 X
5.65 X
4.08
4.40
2.70
5.58 Xa
5.32 X*
3.72
Purchase from power plants when ACFL is
50.35/MBtu


X
X
X
X






X
X
Xa
X

X
X

$0.50/MBtu

X
X
X
X
X
X


xa


X
X
X
X

X
X

$0.70/MBtu

X
X
X
X
X
X


X


X
X
X
X

X
X

a.  Buying from Port Sulphur in addition to byproduct acid.

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                                APPENDIX Q


           POWER PLANTS AND ACID PLANTS AFFECTED BY A REDUCTION

                           OF $20/TON IN S PRICE


                                 CONTENTS

Tables                                                                 Page

 M-l     Effect of S Price Change at $0.35/MBtu ACFL for Power
         Plants, Smelters, and Acid Plants	228

 M-2     Effect of S Price Change at $0.5Q/MBtu ACFL for Power
         Plants, Smelters, and Acid Plants	229

 M-3     Effect of S Price Change at $0.70/MBtu ACFL for Power
         Plants, Smelters, and Acid Plants
                                                                       230
                                     227

-------
            TABLE Q-1-   EFFECT OF S PRICE CHANGE AT $0.35/MBTU ACFL

                  FOR POWER PLANTS, SMELTERS. AND ACID PLANTS	

       Two power  plants  affected by  S price change at  $t).35/MBtu ACFL

                                                                   57,79^
                                                                  188,517
                                                                  2^6,311
1400000600  Pennsylvania  Total tons   80,^09
4770003000  .Kentucky      Total tons  628,358
                         tons  affected
                         tons  affected
          Four smelters  affected by  S price change at  $0.35/MBtu ACFL
New Mexico
New Mexico
Arizona
Montana
            Houston
            St.  Louis
            Houston
            St.  Louis
Total tons
Total tons
Total tons
Total tons
  9,000
166,000
118,000
144,000
tons affected
tons affected
tons affected
tons affected
  9,000
166,000
118,000
144,000
437,000
246.311
683,311
         Six acid  plants affected by S price change at $0.35/MBtu ACFL
13          Allied Chemical Corp
4770003000  Kentucky

33          Borden Chemical
4770003000  Kentucky

48          E. I. Dupont

1^00000600  Pennsylvania
                                       Front Royal, Virginia        29.83

                                       107,837    tons       @      31.73

                                       Norfolk, Virginia            31.95
                                        80,000    tons       @      32.37

                                       North Bend, Ohio             36.30

                                        57,794    tons       @      36.33
60          W. R. Grace
4770003000  Kentucky
                                       Joplin, Missouri
                                           680    tons
                                           33.57
                                           34.13
79
            N L Industries  inc.
            New Mexico - St. Louis

            Montana    - St. Louis
              St. Louis, Missouri          25.01

              166,000    tons       @      28.16

              144,000    tons       @      28.79
88
            Olin Corporation

            Arizona     -  Houston

            New Mexico  -  Houston
                                       Pasadena, Texas

                                       118,000    tons

                                         9,000    tons
                                           24.19
                                           27.56
                                           27.56
                                       683,311
                                    228

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TABU;  Q-2-   EFFECT  OF  s TRICK  CHANGE  AT  $O.SO/MBTU
ACFL FOR  POWER PLANTS,  SMELTERS,  AND  ACID PLANTS
   Six  power  plants  affected by S  price change
                  at  $0.50/MBtu  ACFL

1115001100  Illinois,     Total tons    126,788   tons affected     12,054
1655000300  Florida     Total tons    192,742   tons affected     2,101

3455000400  Indiana     Total tons    132,291   tons affected     42,291

4770003000  Kentucky     Total tons    628,358   tons affected    528,297
4770003200  Kentucky     Total tons    288,947   tons affected     44,830
5540000250  Missouri     Total tons    108,149   tons affected     10,149
                                                             639,722
      Two  smelters affected by  S price  change
                  at  $0.50/HBtu  ACFL
Arizona     Houston      Total tons    118,000   tons affected    118,000
Mew Mexico  Houston      Total tons    380,000   tons affected    380,000
                                                             498,000
                                                             639,722
                                                           1,137,722
  Ten  acid  plants affected by  S price  change
                  at  $0.50/MBtu  ACFL

11         Allied  Chemical Corp,     HopcwelJ., Virginia          29.39
4770003000  Kentucky                  156,544   tons      @      31.73

33         Borden  Chemical Corp      Norfolk, Virginia           31.95
4770003000  Kentucky                  80,000   tons      I?      32.37

46         E.  I. Dupont              Richmond, Virginia          31.16
4770003000  Kentucky                  90,000   tons      @      31.73

60         W.  R. Grace              Joplin, Missouri           33.57
4770003000  Kentucky                  22,394   tons      @      34.13

62         W.  R. Grace              Bartow, Florida            27.70
1655000300  Florida                    2,101   tons      <«      28.55

74         Mobile Oil               Depue,  Illinois            25.08
1115001100  Illinois                  12,054   tons      13      27.59
3455000400   Indiana                  42,291   tons      @      25.36
5540000250  Missouri                  10,149   tons      @      27.56

88         Olin Corporation           Pasadena, Texas            24.19
Arizona     Houston                   118,000   tons      S      27.56
New Mexico  Houston                  380,000   tons      @       27.56

96         Royster Company            Mulberry, Florida           29.49
4770003000   Kentucky                  134,359   tons      @       32.96

102        Stauffer Chemical Co       LeMoyne, Alabama            28.95
4770003200   Kentucky                 44,830   tons      @      30.95

114        U.S. Industrial Chemicals  Desota, Kansas              34.18
4770003000  Kentucky                  45,000   tons      @      37.83

                                  1,137,722
                              229

-------
 TABLE Q-3.   EFFECT OF  S PRICE  CHANGE  AT  $0.70/MBTU
 ACFL FOR POWER  PLANTS,  SMELTERS,  AND  ACID PLANTS
   Eight  power plants affected  by  S price  change
                    at  $0.70/MBtu ACFL
0785000500  Illinois
1000000050  Texas
1655000300  Florida
Total tons
Total tons
Total tons
3795000350  Pennsylvania Total tons
4520000500  Indiana     Total tons
4770001900  Tennessee    Total tons
4770003000  Kentucky    Total tons
5540000250  Missouri    Total t.'.w
 77,549
125,523
192,742

 72,342
216,721
301,246
628,358
108,149
tons affected     31,951
tons affected      5,523
tons affected    192,742
                     tons affected
                     tons affected
                     tons affected
                     tons affected
                     tons affected
                35,037
                45,000
                80,403
               538,358
                10,149
       Two smelters  affected by  S price change
                    at  $0.70/MBtu ACFL
Arizona    Houston
New Mexico  Houston
Total tons    118,000
Total tons    299,000
            417,000
            939,163
          1,356,163
         tons affected
         tons affected
               118,000
               299,000
     Ten  acid plants  affected by S price change
                    at $0.70/MBtu ACFL
11
4770003000
33
4770003000
56
1655000300
62
4770001900
4770003000
74
0785000500
5540000250
86
3795000350
88
Arizona
New Mexico
96
4770003000
114
4520000500
138
1000000050

Allied Chemical
Kentucky
Borden Chemical
Kentucky
Gardinier Inc.
Florida
W. R. Grace & Co.
Tennessee
Kentucky
Mobil Oil
Illinois
Missouri
Olin Corporation
Pennsylvania
Olin Corporation
Houston
Houston
Royster Company
Kentucky
U.S. Industrial Chemicals
Indiana
El Paso Products
Texas
1
Hopewell, Virginia
77,508 tons @
Norfolk, Virginia
80,000 tons 13
Tampa, Florida
192,742 tons @
Bartow, Florida
80,403 tons @
239,597 tons @
Depue, Illinois
31,951 tons @
10,149 tons @
Baltimore, Maryland
35,037 tons g
Pasadena, Texas
118,000 tons @
299,000 tons 
-------
                                TECHNICAL REPORT DATA
                         {Please read Instructions on the reverse be/ore completing)
. REPORT NO.

EPA-600/7-78-07Q
     AND SUBTITLE  Potential Abatement Production and
Marketing of Byproduct Sulfuric Acid in the U.S.
                               3. RECIPIENT'S ACCESSION NO.
                               5. REPORT DATE
                                April 1978
                                                      6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
J.I. Bucy, R.L.Torstrick, W.L.Anders, J.L. Kevins,
and P.A.Corrigan
                               8. PERFORMING ORGANIZATION REPORT NO.

                                TVA Bulletin Y-122
 PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
Office of Agricultural and Chemical Development
National Fertilizer Development Center
Muscle Shoals. Alabama  35660
                                10. PROGRAM ELEMENT NO.
                                EHE624A
                                11. CONTRACT/GRANT NO.
                                E PA Interagency Agreement
                                D8-E721-BJ (TV-41967A)
12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC  27711
                                13. TYPE OF REPORT AND PERIOD COVERED
                                Final; 7/74 - 6/77
                               14. SPONSORING AGENCY CODE
                                 EPA/600/13
-,5. SUPPLEMENTARY NOTES JERL-RTP project officer is Charles J. Chatlynne, Mail Drop 61,
 919/541-2915.
is. ABSTRACT The report gives resiilts of an evaluation of the market potential for sulfur
 and sulfuric acid byproducts of combustion in power plant boilers.(Air quality regu-
 lations require control of SOx emissions from power plant boilers. Recovery of
 sulfur in useful form would avoid waste disposal and conserve natural sulfur and
 natural gas used to mine sulfur,) A cost model was  developed to estimate the least-
 cost compliance method from three alternatives: selecting a clean fuel strategy,
 selecting a limestone-throwaway scrubbing technology, or selecting a sulfuric acid
 or sulfur-producing scrubbing technology. For plants where production of byproducts
 was the economic choice, a market simulation model was used to evaluate distribu-
 tion of byproducts  in competition with existing markets. Significant amounts of
 sulfuric acid could be produced from SOx in power plant flue  gas and sold in com-
 petitive markets.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                                                    COSATl Field/Group
 Pollution
 Sulfuric Acid
 Sulfur
 Byproducts
 Marketing
 Sulfur Oxides
Electric Power
  Plants
Boilers
Flue Gases
Limestone
Gas Scrubbing
Pollution Control
Stationary Sources
Clean Fuel
13B
07B

14B
05C
   10B
   13A
   2 IB
   08G
07A,13H
13. DISTRIBUTION STATEMENT
                    19. SECURITY CLASS (This Report)
                    Unclassified     	
                                                                       265
 Unlimited
                    20. SECURITY CLASS (This page}
                    Unclassified
                                                                  22. PRICE
EPA Form 2220-1 (9-73)
                                          231

-------