United States Office of Environmental Engineering
Environmental Protection and Technology
Agency Washington DC 20460
EPA-600/7-79-215
December 1979
Research and Development
Review of New
Source Performance
Standards for Coal
Fired Utility Boilers
Phase Three Report
Interagency
Energy/Environment
R&D 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 ir.sues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-215
December 1979
REVIEW OF NEW SOURCE PERFORMANCE STANDARDS
FOR COAL-FIRED UTILITY BOILERS
PHASE 3 FINAL REPORT
SENSITIVITY STUDIES FOR THE SELECTION OF A REVISED STANDARD
by
Andrew J. Van Horn
George C. Ferrell
Richard M. Brand!
Richard A. Chapman
Energy and Environmental Systems Division
Teknekron Research, Inc.
Berkeley, California 94704
Project Officer
Lowell F Smith
Office of Environmental Engineering and Technology
Washington, D.C. 20460
OFFICE OF ENVIRONMENTAL ENGINEERING AND TECHNOLOGY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
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DISCLAIMER
This report has been reviewed by the Office of Research and Development, U.S.
Environmental Protection Agency, and approved for publication. Approval does
not signify that the contents necessarily reflect the views and policies of the
U.S. Environmental Protection Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
ii
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FOREWORD
Critical uncertainties surround a number of key factors that will influence the
future impacts of the revised New Source Performance Standards (RNSPS) to be
established for coal-fired electric utility boilers. These factors will affect
utility costs and hence will influence the coal choices and pollution control
measures adopted by utilities in response to alternative standards. For the study
reported herein, city-specific analyses were carried out to examine utility coal
and pollution control choices and their sensitivity to the factors of interest.
Complementing these sensitivity analyses are state, regional, and national
impact projections from the Utility Simulation Model for alternative standards
for the period from 1976 to the year 2000. Together, these analyses and impact
projections constitute Phase 3 of Teknekron's RNSPS review. The results of
I 2 3
Phases I and 2 are presented elsewhere. ' '
The sensitivity studies provide answers to the following generic questions (which
are broken down into highly specific questions in the body of this report):
I. How will utility choices be affected by different stan-
dards and by uncertainties in key factors?
2. How well can the impacts of various full and partial
scrubbing options be distinguished?
3. What are the likely impacts of a revised NSPS?
Key elements that were varied include coal mine prices, coal transportation
rates, coal sulfur and Btu contents, and the costs and performance of FGD
scrubbers. In each case, the selected range of variation reflects the element's
degree of uncertainty and sensitivity to critical issues. For example, physical
parameters such as coal sulfur content and heating values for a specific coal
seam are taken from data on likely reserves with their associated variations;
while the range of uncertainty surrounding f.o.b. mine prices and transportation
costs reflects projected market conditions. For the costs of flue gas desulfuri-
zation (FGD), use was made of engineering estimates developed independently by
PEDCo and by the Tennessee Valley Authority; the TVA capital and operating
Hi
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costs used in this sensitivity study ore significantly lower than PEDCo's. »^»6
(See Appendix A.) The report discusses effects of these variations on the ability
to distinguish analytically between similar standards. Also discussed are the
sensitivities of several cost-effectiveness calculations (for example, cost per ton
of $©2 removed) which have been posited as measures of the worth of various
standards.
The impacts of revised standards will depend not only on utility coal and
pollution control choices but also on such factors as the future growth in
electricity demand, the amount of nuclear capacity, the phasing out of gas steam
plants, and the price of oil. These factors are themselves subject to uncertainty.
The latest assumptions of the joint EPA/DOE working group were used in the
projections for 1976 to 2000 (see Appendix G).
This report focuses on full versus partial scrubbing, considering several forms of
the revised standard; on coal properties and supply characteristics; on FGD
design, costs, and performance; on city-specific sensitivity studies; and on the
Utility Simulation Model's yearly projections of regional and national impacts
from 1976 to the year 2000. Potential RNSPS analyzed here include the EPA's
September 1978 proposed full scrubbing standard and several alternative
standards that would permit partial scrubbing. Appendix I, added in June 1979,
presents a brief comparison of the final promulgated RNSPS announced on
May 25, 1979, and two of the options described in this report.
IV
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ABSTRACT
This report summarizes Teknekron's Phase 3 study of the projected effects of
several different potential revisions to the current New Source Performance
Standard (NSPS) for sulfur dioxide (S02) emissions from coal-fired electric
utility boilers. The revised NSPS (RNSPS) is assumed to apply to all coal-fired
units with a generating capacity of 25 megawatts or more, beginning operation
after 1982. A principal purpose of this phase of the RNSPS analysis is to present
to decision makers the critical uncertainties that will influence utility costs,
coal choices, and pollution control measures adopted by utilities in response to
alternative standards. Answers are presented to the following generic questions
(which are broken down into highly specific questions in the report):
I. How will utility choices be affected by different stan-
dards and uncertainties in key factors?
2. How well can the impacts of various full and partial
scrubbing options be distinguished?
3. What are the likely energy, economic, environmental, and
resource impacts of a revised NSPS?
This report focuses on issues of full versus partial scrubbing, considering several
forms of the revised standard; on coal properties and supply characteristics; on
FGD design, costs, and performance; on city-specific sensitivity studies; and on
the Utility Simulation Model's yearly projections of regional and national impacts
from 1976 to the year 2000. Potential RNSPS analyzed in this report include the
EPA's September 1978 proposed full scrubbing standard and several alternative
standards that would permit partial scrubbing. Appendix I, added in June 1979,
presents a brief comparison of the final promulgated RNSPS announced on
May 25, 1979, and two of the options described in this study.
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CONTENTS
Page
FOREWORD iii
ABSTRACT v
FIGURES xi
TABLES xv
ACKNOWLEDGMENTS xix
I. INTRODUCTION I
The Form of the Revised New Source Performance Standard I
Impacts of the Alternative Revised New Source Performance
Standards 5
2. SUMMARY OF PRINCIPAL RESULTS II
Environmental Impacts 11
502 ^missions 11
S02 Emissions from RNSPS-Controlled Plants 14
FGD Capacity 14
FGD Sludge and Coal Ash Production 16
Economic Impacts 16
Cumulative Pollution Control Investment 19
National Average Monthly Residential Electricity Bill 19
Present Value of Total Utility Expenditures to 1995 22
S02 Emission and Percentage Cost Changes 22
Incremental Costs of S02 Reduction: Dollars
per Ton of S©2 Removea 27
Resource Utilization 28
Utility Fossil Fuel Consumption 28
Utility Water Consumption 30
Coal Production for Electric Utilities 32
Western Coal Shipped East 32
vii
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CONTENTS (Continued)
Sensitivity Analyses 33
Ranges of Cost Uncertainties for Key Cities 33
Distinguishing Differences among the Impacts of Various
Partial Scrubbing Options 39
The Implications and Reliability of Cost-Effectiveness
Measures 39
The Implications of the Lower versus Higher Future
FGD Costs 39
The Form of the Revised Standard 40
Comparison of One Full and One Partial Scrubbing Option 42
Emissions 42
Economic Costs 44
Resource Utilization 48
Other Factors 48
3. KEY QUESTIONS AND ANSWERS 51
I. WHAT ARE THE LIKELY IMPACTS OF A REVISED
NSPS? 51
a. How will the national costs and SO, emission reductions
based oh higher (PEDCo) FGD cost* be
distributed regionally in 1995 for the full scrubbing
option (0.2 Ib floor) and the partial scrubbing
options (0.6 Ib floor and 0.6 Ib uniform ceiling)? 51
b. The regional emission projections include emissions
from both old and new generating units. The revised
NSPS will affect only those units in operation after
1 982, and these plants and their successors should be
operating for over 35 years after 1983. What are
the differences in emissions from these RNSPS
plants compared with the older units subject to
more lenient standards? 53
c. What are the emission projections for coal-fired
plants when the Lower (TVA) FGD cost estimates
are used? 55
viii
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CONTENTS (Continued)
d. What are the principal utility capital investments
for various standards using lower as compared with
higher estimates of future scrubber costs? 58
e. How do the alternative RNSPS differ in their
impacts on primary resource consumption and solid
waste generation? 65
f. How are utility coal production and consumption
influenced by the S0? standard and by different
estimates of FGD cons? 67
II. WHAT ARE THE DIFFERENCES BETWEEN THE
PROJECTED IMPACTS OF THE FULL AND
PARTIAL SCRUBBING ALTERNATIVES? 70
a. What are the cost and emission differences
between the various full and partial scrubbing
ptions? 70
b. How does the form of the revised standard influence
the costs of pollution controls? 72
III. HOW WILL UTILITY COAL CHOICES IN KEY STATES BE
AFFECTED BY DIFFERENT SO-> EMISSION STANDARDS
AND UNCERTAINTIES IN KEY FACTORS? 73
a. What estimates can be made-regarding the typical
utility costs of buying, transporting, and burning
different coals, and of required pollution controls,
as a function of the SO2 standard? 73
b. What is the sensitivity of fuel-cycle costs to coal
mine prices? 78
c. What is the sensitivity of fuel-cycle costs to coal
transportation costs? 80
d. What is the sensitivity of fuel-cycle costs to
western coal characteristics? 82
e. What is the sensitivity of coal and pollution control
choices to different engineering estimates of FGD
costs? 84
ix
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CONTENTS (Continued)
Page
IV. HOW ACCURATE AND RELIABLE ARE MEASURES OF
THE COST EFFECTIVENESS OF VARIOUS STANDARDS? 87
REFERENCES 93
APPENDIX A: PEDCO AND TVA FGD COSTS 95
APPENDIX B: LIFE-CYCLE COSTING 105
APPENDIX C: CITY-SPECIFIC SENSITIVITY ANALYSES 117
APPENDIX D: CHARACTERISTICS OF MAJOR POWDER RIVER
BASIN COAL SEAMS 137
APPENDIX E: PROJECTED REGIONAL AND NATIONAL UTILITY
COAL PRODUCTION 141
APPENDIX F: SELECTED RESULTS FOR 1990 AND 1995 153
APPENDIX G: INPUT ASSUMPTIONS FOR THE PHASE 3 ANALYSIS 169
APPENDIX H: PROJECTED NATIONAL ELECTRIC GENERATING
CAPABILITY AND ELECTRICITY GENERATION BY
FUEL, 1976-2000 173
APPENDIX I USM PROJECTIONS FOR 1995 UNDER THE FINAL
PROMULGATED RNSPS 179
GLOSSARY OF SO2 STANDARDS TERMINOLOGY 197
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FIGURES
Comparison of SO, Emissions under Annual Average
Control Alternatives
l-l
4
2-1 National Power-Plant SO2 Emissions 12
2-2 Regional SO2 Emissions, 1995 13
2-3 National SO7 Emissions from Coal-Fired Power
Plants, I99F 15
2-4 Regional FGD Capacity, 1995 17
2-5 National Sludge and Coal Ash Production and FGD
Capacity, 1995 18
2-6 Comparison of Cumulative Pollution Control Investment,
1983-2000, Reflecting Higher and Lower FGD Costs 20
2-7 National Average Residential Monthly Electric
Bill in 1995 and Percentage Increase from Current NSPS 21
2-8 National Percentage Increase in Total Utility Cost and
Percentage Decrease in SO-, Emissions for Revised
NSPS, 1995 23
2-9 Comparison of SO* Emission Reductions and Increases
in Total Utility Cffsts for Revised NSPS Relative to
Current NSPS, 1995 (Northeast and Southeast Regions) 24
2-10 Comparison of SO7 Emission Reductions and Increases in
Total Utility Cost! for Revised NSPS Relative to
Current NSPS, 1995 (North Central and West South
Central Regions) 25
2-11 Comparison of S07 Emission Reductions and Increases in
Total Utility Costs for Revised NSPS Relative to
Current NSPS, 1995 (Mountain and Pacific Regions) 26
2-12 Utility Fossil Fuel Consumption, 1995 29
2-13 Utility Water Consumption, 1995 31
2-14 Utility Coal Production, 1995 (Higher FGD Costs) 34
xi
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FIGURES (Continued)
Poge
2-15 Utility Coal Production, 1 995 (Lower FGD Costs) 35
2- 1 6 Western Coal Shipped East, 1 995 (Higher FGD Costs) 36
2- 1 7 Western Coal Shipped East, 1 995 (Lower FGD Costs) 37
2-18 Comparison of FGD Cost Effectiveness per Ton of ^
Removed under 24-Hour Average S09 Control Alternatives
with a 1.2 Ib/KTBtu Ceiling L 41
2- 1 9 Percentage Change in Power-Plant SO, Emissions in 1 995:
Partial vs. Full Scrubbing (West North Central and Mountain
and Pacific Regions) 45
2-20 Percentage Change in Power-Plant SO, Emissions in 1995:
Partial vs. Full Scrubbing (West South Central Region) 46
2-21 Percentage Change in Power-Plant $©2 Emissions in 1995:
Partial vs. Full Scrubbing (East North central, East, and
East South Central Regions) 47
3- 1 National S0~ Emissions from Coal-Fired Power Plants,
1 995 (LowerTGD Costs) 57
3-2 Regional SO2 Emissions, 1995 (Lower FGD Costs) 60
3-3 National Percentage Increase in Total Utility Cost and
Percentage Decrease in SO9 Emissions for Revised
NSPS, 1 995 (Lower FGD Coits) 6 1
3-4 Comparison of National Pollution Control Investment
and Total Cumulative Investment, 1983-2000 (Lower
FGD Costs) 62
3-5 Comparison of FGD Cost Effectiveness per Btu of
Fuel Input under Annual Average S02 Control
Alternatives 75
3-6 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour
S02 Floor (Columbus, Ohio) 76
3-7 Sensitivity of Levelized Fuel-Cycle Cost to Annual
S02 Ceiling (Columbus, Ohio) 77
3-8 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour
S02 Floor and F.OB. Coal Mine Prices (Columbus, Ohio) 79
XII
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FIGURES (Continued)
3-9 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour
S02 Floor and Transportation Rate (Columbus, Ohio) 81
3-10 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour
SO, Floor and Powder River Coal Characteristics
(Columbus, Ohio) 83
3- 1 1 Sensitivity of Levelized Fuel-Cycle Cost to FGD Cost
(Columbus, Ohio) 85
3-12 Comparison of FGD Cost Effectiveness per Ton of S02
Removed under Annual Average $© Control Alternatives 88
3-13 Levelized Fuel-Cycle Costs per Pound of SO, Emitted
as a Function of Annual S02 Limit (Illinois) 90
C- 1 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and F.O.B. Coal Mine Prices (Indianapolis, Indianaf 120
C-2 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour SO,
Floor and F.O.B. Coal Mine Prices (Orlando, Florida) z 121
C-3 Sensitivity of Levelized Fuel -Cycle Cost to 24-Hour SO,
Floor and F.O.B. Coal Mine Prices (Austin, Texas) 122
C-4 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Transportation Rate (Indianapolis, Indiana) 125
C-5 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Transportation Rate (Orlando, Florida) 126
C-6 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Transportation Rate (Austin, Texas) 127
C-7 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Powder River Coal Characteristics
(Indianapolis, Indiana) 129
C-8 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Powder River Coal Characteristics
(Orlando, Florida) 130
C-9 Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour S02
Floor and Powder River Coal Characteristics (Austin, Texas) 131
XIII
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FIGURES (Continued)
C-10 Sensitivity of Levelized Fuel-Cycle Cost to Annual SO.
Ceiling (Indianapolis, Indiana) 133
C-11 Sensitivity of Levelized Fuel-Cycle Cost to Annual SO,
Ceiling (Orlando, Florida) L 134
C-12 Sensitivity of Levelized Fuel-Cycle Cost to Annual S0?
Ceiling (Austin, Texas) * 135
H-l Utility Simulation Model: Projected National Electric
Generating Capability ' 176
H-2 Utility Simulation Model: Projected National Electricity
Generation 177
xlv
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TABLES
I-1 Averaging Time and SO2 Standards with Equivalent Annual
Emissions 6
2-1 Percentage SC^ Emission Reduction in 1995 under Full
Scrubbing Compared with Partial Scrubbing 43
3-1 Full and Partial Scrubbing vs. Current NSPS: Percentage
Changes in Regional S09 Emissions and Total Utility
Costs in 1995 {Higher FGD Costs) 52
3-2 National Coal-Fired, Power-Plant SO^Emissions
by Regulatory Category (Higher FGDlTosts) 54
3-3 National Coal-Fired, Power-Plant SO, Emissions
by Regulatory Category (Lower FGD Costs) 56
3-4 Full and Partial Scrubbing vs. Current NSPS: Percentage
Changes in Regional SCuEmissions and Total Utility
Costs in 1995 (Lower FGD Costs) 59
3-5 Comparison of Cumulative Pollution Control Investment,
FGD Capacity, and Total Coal Capacity
(Higher FGD Costs) 63
3-6 Comparison of Cumulative Pollution Control Investment,
FGD Capacity, and Total Coal Capacity
(Lower FGD Costs) 64
A-1 Comparison of TVA and PEDCo Limestone
FGD Capital Costs 100
A-2 Comparison of TVA and PEDCo Limestone
FGD Operating Costs 101
A-3 Comparison of Modeled TVA and PEDCo Limestone FGD
Capital Costs 103
A-4 Comparison of Modeled TVA and PEDCo Limestone FGD
Operating Costs 104
B-l Calculation of Present Value 109
B-2 Calculation of Present Value by Discounting Levelized Costs 110
xv
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TABLES (Continued)
B-3 Fixed Charge Rates and Levelization Factors
Used to Evaluate Investments in Publicly
and Privately Owned Electric Utilities 112
B-4 Costs Levelized in the Coal Fuel Cycle 113
B-5 Sensitivity of Levelization Factors IIS
C-1 24-Hour S02 Floors above Which Western Coal
Is Economically Preferred for Various Coal Mine Prices 123
C-2 24-Hour SO, Floors above Which Western Coal
Is Economically Preferred for Various Transportation Rates 124
D-1 Characteristics of Major Powder River Basin Coal Seams 140
E-l Regional Utility Coal Production: 1985 (PEDCo Scrubber
Cost Estimates) 144
E-2 Regional Utility Coal Production: 1990 (PEDCo Scrubber
Cost Estimates) 145
E-3 Regional Utility Coal Production: 1995 (PEDCo Scrubber
Cost Estimates) 146
E-4 Summary of Regional Growth Rates in Utility Coal
Production, 1985-1995 (PEDCo Scrubber Cost Estimates) 147
E-5 Regional Utility Coal Production: 1985 (TVA Scrubber
Cost Estimates) 148
E-6 Regional Utility Coal Production: 1990 (TVA Scrubber
Cost Estimates) 149
E-7 Regional Utility Coal Production: 1995 (TVA Scrubber
Cost Estimates) 150
E-8 Summary of Regional Growth Rates in Utility
Coal Production, 1985-1995 (TVA Scrubber Cost Estimates) 151
F-1 USM Emission Projections, 1990 (PEDCo FGD Costs) 157
F-2 USM Emission Projections, 1990 (TVA FGD Costs) 158
F-3 USM Emission Projections, 1995 (PEDCo FGD Costs) 159
xvi
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TABLES (Continued)
F-4 USM Emission Projections, 1995 (TVA FGD Costs) 160
F-5 USM Cost Projections, 1990 (PEDCo FGD Costs) 161
F-6 USM Cost Projections, 1990 (TVA FGD Costs) 162
F-7 USM Cost Projections, 1995 (PEDCo FGD Costs) 163
F-8 USM Cost Projections, 1995 (TVA FGD Costs) 164
F-9 USM Fuel Impact Projections, 1990 (PEDCo FGD Costs) 165
F-IO USM Fuel Impact Projections, 1990 (TVA FGD Costs) 166
F-11 USM Fuel Impact Projections, 1995 (PEDCo FGD Costs) 167
F-12 USM Fuel Impact Projections, 1995 (TVA FGD Costs) 168
H-l Projected National Generating Capacity 178
I-1 USM Projections for 1995 under the Final
Promulgated RNSPS 184
1-2 Utility Simulation Model Emission Impact
Projections, 1995 187
1-3 Utility Simulation Model Cost Projections, 1995 188
xvii
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ACKNOWLEDGMENTS
Many people contributed to this analysis. We acknowledge first Dr. Lowell Smith
of EPA's Office of Energy, Minerals, and Industry for his effective direction in
guiding the study in its multiple stages. Teknekron's Software Group under the
direction of Marcel la Wells provided the capability to program and operate the
extensive computer models and data bases required. Dr. Donald Clements
significantly added to the development of the pollution control cost and
performance models; Virginia Matucha, Harry Nelson, and Rosemary Dunn
compiled many of the data bases; and all participated in the model runs. Douglas
Pierce carried out many of the sensitivity studies and competitive coal analyses.
Dr. Stanley Greenfield offered constructive comments on the numerous issues
addressed in this report. The Graphics Group under Charles Chickadel enhanced
the presentation of results; particularly helpful in this regard was Carol Johnson,
who designed and executed the graphics. Barbara Phillips edited the text, tables,
and figures to ensure the production of a clear, cogent, and straightforward
document. Finally, word processors Evelyn Kawahara, Sheryl Klemm, Maureen
Ash, and Carol See produced the draft report under severe time constraints. The
authors gratefully acknowledge these and other members of Teknekron's Energy
and Environmental Systems Division for their exemplary efforts. This work was
performed under EPA Contract 68-02-3092.
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I. INTRODUCTION
Numerous potential revised New Source Performance Standards (RNSPS) have
I -3 8
been analyzed. " ' Because of the many uncertainties surrounding future costs
and the responses of individual utilities, the impacts of each standard cannot be
predicted with certainty. Hence, emphasis should not be placed on the small
marginal differences between similar standards. Accordingly, the Phase 3
projections presented in this report focus on five standards, different in form,
that exemplify the differences in likely impacts among feasible full and partial
scrubbing options. These standards include the full scrubbing option proposed by
EPA as the preliminary revised standard in September 1978 and several partial
scrubbing options. City-specific sensitivity analyses for key states were
performed for this Phase 3 study to determine the ranges of uncertainty
surrounding coal and pollution control choices. Many of the sensitivity studies
were carried out with the Coal Assignment Model. The yearly impact projec-
tions from 1976 to 2000 were calculated by the Utility Simulation Model. In this
Phase 3 analysis the costs and performance of flue gas desulfurization (FGD)
technologies were based on wet scrubbing processes, while our analysis of the
final promulgated RNSPS given in Appendix I includes both wet and dry FGD
technologies.
The Form of the Revised New Source Performance Standard
RNSPS standards are characterized by an emission ceiling, percentages of
required SOj removal, an emission averaging time (24-hour, 30-day, or annual
average), and an emission floor. These terms are explained in the Glossary. As
the Phase 3 sensitivity studies and state and regional projections demonstrate,
the specific form of the standard will significantly affect the use of low-sulfur
and intermediate-sulfur coals and the resulting level of SC emissions.
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The sensitivity analyses conducted for this report covered the complete range of
S02 emission floors and ceilings between 1.2 Ib S02 per million Btu (10* Btu) and
0.2 Ib S02/I0 Btu, in intervals of O.I. However, for the national projections,
only five distinct standards are presented. These are:
Current NSPS. This is the current standard of 1.2 Ib
SCWIO Btu with no mandatory percentage S02 removal.
Coal sulfur RSD (relative standard deviation) is assumed
to be zero for any averaging time. This assumption means
that the emission averaging time does not affect compli-
ance with this standard. For purposes of comparison with
the alternative RNSPS, this is considered to be an annual
average form of the standard. The current NSPS is used
as a baseline from which to compare the impacts of
alternative RNSPS.
0.2 Ib floor. This standard requires 85 percent removal of
S(>2 over a 24-hour averaging time but permits a drop to
75 percent removal for three days/per month. Also, it
includes a ceiling of 1.2 Ib SOJIO Btu and a floor of
0.2 Ib S07/I0 Btu. This, stdhdard is the preliminary
RNSPS promulgated by EPA in September f^7o\ Trie
ceiling may be exceeded three days per month, while the
floor, if controlling, may not be exceeded. Thus, the
mean coal sulfur content must be low enough so that the
mean plus 2 RSD (24-hour RSD is 0.08 for cleaned coal
and 0.15 for uncleaned coal) is less than the 1.2 Ib ceiling.
Similarly, only those coals for which the mean plus 3 RSD
(24-hour) is less than 0.2 Ib SO,/10° Btu may be scrubbed
at less than 85 percent removal efficiency. The only fuels
affected by the 0.2 Ib floor are those with a sulfur
content of less than about 0.5 Ib 5/10 Btu. It is assumed
that, when the floor controls, partial scrubbing with a
fixed bypass will be used. In cases where the ceiling
controls, it is assumed that the FGD system will operate
at a constant efficiency and that annual average emis-
sions therefore will be less than the ceiling. FGD capital
costs are based on a maximum expected coal sulfur
content [mean x (I + 2 or 3 RSD)], while operating costs
are based on the mean sulfur content. This standard
requires full scrubbing (90 percent or greater annual SO,
removal)"7oF all coals except those affected by the floor!
Greater than 90 percent annual removal would be required
only,for high-sulfur coals containing more than 3.1 Ib
S/l06Btu.
0.6 Ib floor. This standard is identical to the preceding
standard except that the floor is raised. It permits partial
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scrubbing (less than 85 percent daily SO? removal or,
equivalently, less than 90 percent annual SO\ removal) of
intermediate-sulfur coals (coals with less than about
1.5 Ib S/IO Btu). It would require 90 percent annual SCU
removal for all coals.with more than 1.5 Ib S/IO Btu ana
greater than 90 percent removal for coals with more than
3.1 Ib S/IO6 Btu.
0.6 Ib uniform ceiling with 33 percent minimum removal.
This is an annual average standard that requires alLcoals
to meet a uniform emission ceiling of 0.6 Ib SOJIO Btu.
Since the coal sulfur RSD = 0 for annual standards, annual
emissions will be at the limit of 0.6 Ib SO2/IO Btu. The
dashed line in Figure I-1 shows the percentage removal
that would be required for each coal to meet a uniform
0.6 Ib ceiling. It can be seen that, if the minimum
percentage SO2 removal is specified as 33 percent, the
specified 0.6 ceiling rather than the percentage removal
requirement will be controlling for all coals. Compared
with the 24-hour standard stipulating a 0.6 Ib floor, this
standard will allow much more partial scrubbing of inter-
mediate-sulfur coals. Whereas the 0.6 Ib floor standard
requires 90 percent annual removal for all coals with
more than about 1.5 Ib S/10° Btu, the 0.6 Ib uniform
ceiling standard, requiring only 33 percent removal, per-
mits less than 90 percent annual removal (i.e., partial
scrubbing) for all coals containing less than 3.0 Ib S/IO
Btu.
Therefore, under this standard, compared with the 0.2 and
0.6 Ib floor 24-hour standards, intermediate-sulfur coals
will cost less to bum. As a result, these coals will replace
lower-sulfur coals in a number of states. (See the
sensitivity analyses.) Emissions will increase over the
0.2 Ib floor and 0.6 Ib floor cases.
0.5 Ib uniforrn ceiling with 90 percent removal. This form
of an annual RNSPS requires high-sulfur coals containing
more than about 2.5 Ib S/10 Btu to be scrubbed at 90 to a
maximum 94 percent 562 removal. All other coajs are
required to be scrubbed at 90 percent removal. This is a
"low emissions" full scrubbing standard based on current
FGD technology. For most regions, it can be expected
that emissions under this standard will be lower than
those under the full scrubbing option (0.2 Ib floor) previ-
ously described, due to lower emissions from the highest-
sulfur coals.
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Figure 1-1
Comparison of SO2 Emissions under Annual Avaraga Control Altarnativas
0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0
0.0
ANNUAL AVERAGE COAL SULFUR CONTENT (LB S/10* BTU)
-------
The five standards discussed above prescribe either 24-hour or annual periods
within which the SOj emissions are averaged. A shorter averaging time for a
given ceiling implies lower average emissions in order that emission ceilings not
be exceeded more than the allowed number of times (i.e., sulfur variability as
measured by the RSD becomes greater for shorter averaging periods). The
minimum specified percentage SO* removal also depends on averaging time.
Ninety percent annual SOj removal is assumed to be achieved if a minimum
85 percent daily 502 removal is maintained.
Table I-1 illustrates the effects of averaging time for a number of potential
RNSPS. For comparative purposes, each of the RNSPS presented in the table are
compared at the same annual emission level.
Impacts of the Alternative Revised New Source Performance Standards
In Section 2, Summary of Principal Results, the projected impacts of alternative
RNSPS are grouped into three categories: environmental impacts; economic
impacts; and resource utilization. The absolute impact levels, the comparative
levels relative to the baseline, and the results of the sensitivity analyses are
presented for each category. In addition, Section 2 contains a subsection
devoted specifically to general conclusions from the sensitivity analyses, as well
as a subsection comparing the full and partial scrubbing options. The impact and
sensitivity discussions in Section 2 proceed as follows:
Environmental Impacts
Regional SO^ emissions*
emissions from RNSPS-controlled plants
Emissions of numerous other pollutants NO , particulates, trace metals,
and so forth were also calculated but are not discussed in this report.
-------
I-1
Averaging iimeanu 3*j<+ oiuiwuiui wim n|ui»ui«i§ mm\n I_HM .v~-
Revised NSPS SO2 Standard0
Ceiling
(Ib/IO6 Btu)
1.2
0.6
0.5
1.2
1.2
0.8
l.2k
0.6"
Floor
(Ib/I0bntu)
0
0
0
0.2
0.6
0
0.6
0
Minimum
Removal
(%)
0
33
90
85
85
55
90
70
Averaging
Time
(Days)
365
365
365
1
1
30
30
30
Equivalent Standard (Some Annual Emissions)
l-Ony Average1*
Effective
Ceiling
1.56 - 2.34e
0.79- I.I79
0.98
1.2
1.2
0.9- i.oe'
2.1
1.2
Floor
0
0
0
0.2
0.6
0
1.2
0
Minimum
Removal
0
31
85
85
85
S3
87
68
30-Day Average
Effective
Oiling
1.45- l.74f
0.72-0.871'
0.72
0.89
0.89
0.8
1.2
0.6
Floor
0
0
0
0.13
O.'iO
0
0.6
0
Minimum
Removal
0
32
88
88
88
55
90
70
365-Day Average"1
Effective
Ceiling
1.2
0.6
0.5
0.615
0.615
0.55 - 0.64'
1.0
0.5
Floor
0
0
0
0.092
0.276
0
0.5
0
Minimum
Removal
0
33
90
90
90
56
92
72
A key element of this table is the variability of cool sulfur content. For uncleaned cools, the assumed coal sulfur RSD (relative standard deviation) - 0.15 for a
24-hour averaging time, 0.069 for a 30-day averaging time, ami 0.0 for an annual averaging period. For cleaned coals, the RSD = 0.075 for a 24-hour averaging
time, 0.03 for a 30-day averaging time, arid 0.0 for an annual averaging period. In practice, lot size as well os averaging time end coal properties can change the
RSD.
Ceiling exemption allowed three days per month; no floor exemptions allowed.
No exemptions. Thirty-day average may not exceed ceiling or floor.
No exemptions. Annual average may not exceed limit.
> ceiling is a function of coal sulfur content (Coal S) in pounds per million Btu. One-day ceiling - 1.47 » 0.144 Coal S when Coal S is less than 6, and
2.34 when Coal S is equal to or greater than 6. The effective ceiling yields the same annual emissions for coals with different sulfur contents.
The effective ceiling is o function of cool sulfur content (Coal S) in pounds per million Btu. Thirty-day ceiling = 1.42 » 0.054 Coal S when Cool S is less than 6, and
1.74 when Coal S Is equal to or greater than 6.
' The effective ceiling is o function of coal sulfur content (Coal S) in pounds per million Btu. One-day ceiling = 0.737 » 0.144 Coal S when Cool S is less than 3, and
1.17 when Coal S is equal to or greater than 3. For Coal S less than 0.36, minimum removal controls.
The effective ceiling is o function of coal sulfur content (Coal S) in pounds per million Btu. Thirty-day ceiling - 0.708 * 0.054 Coal S when Coal S is less than 3,
and 0.87 when Coal S is equal to or greater than 3. For Coal S less than 0.45, minimum removal controls.
The effective ceiling is o function of cool sulfur content (Coal S) in pounds per million fltu. The effective ceiling = 0.832 < 0.089 Coal S when Coal S is equal to or
less than 2.76, and 1.08 when Coal S is greater than 2.76. For Cool S less than 0.74 and ceiling less than 0.9, minimum removal controls.
' The effective ceiling is o function of cool sulfur content (Cool S) in pounds per million Rtu. The effective ceiling = 0.678 - 0.045 Cool S when Cool S is equal to or
less than 2.76 and 0.55 wlien Tool S is greater than 2.76. For Coal S less than 0.74 and ceiling greater titan 0.64, minimum removal controls.
Th» last two RN5PS shown represent the final protnulqntr-il Hf-ISPS. ( nol* with sulfur rmtlonf Iv-low nlwuit O.' Ib S fwr million fllu ran be scrubbed at o minimum of
70 percent SO- removal of fir i^nry, as iixfirntrd liv tlio lost line. Otlior cools w"' IK" cootrollril l)v hiqlwt pprrrntocio removals n< indicated by the previous line.
-------
FGD capacity
FGD sludge and coal ash production
Economic Impacts
Cumulative pollution control investment
- National average monthly residential electricity bill
Present value of total utility expenditures
SC>2 emission and percentage cost changes
Incremental costs of SOo reduction
Resource Utilization
Utility fossil fuel consumption
Utility water consumption
Coal production for electric utilities
Western coal shipped east of the Mississippi River
Sensitivity Analyses
Ranges of cost uncertainties
Distinguishing differences among the impacts of
various partial scrubbing options
- Implications and reliability of cost-effectiveness
measures
Implications of lower versus higher future FGD
costs
The form of the revised standard
Comparison of one full and one partial scrubbing option
SO2 emissions
Economic costs
Resource utilization
Other factors
-------
Many measures of impacts can be used, and these impacts can be aggregated
from the county level to the national level with the Utility Simulation Model. In
Section 3, Key Questions and Answers, impact measures and aggregations are
more extensively treated through a question and answer format. The questions
answered in Section 3 are as follows:
WHAT ARE THE LIKELY IMPACTS OF A REVISED NSPS?
a. How will the national costs and SO? emission reductions based on
higher (PEDCo) FGD costs be distributed regionally in 1995 for the
full scrubbing option (0.2 Ib floor) and the partial scrubbing options
(0.6 Ib floor and 0.6 Ib uniform ceiling)?
b. The regional emission projections include emissions from both old and
new generating units. The revised NSPS will affect only those units
in operation after 1982, and these plants and their successors should
be operating for over 35 years after 1983. What are the differences
in emissions from these RNSPS plants compared with the older units
subject to more lenient standards?
c. What are the emission projections for coal-fired plants when TVA's
lower FGD cost estimates are used?
d. What are the principal utility capital investments for various stan-
dards using lower as compared with higher estimates of future
scrubber costs?
e. How do the alternative RNSPS differ in their impacts on primary
resource consumption and solid waste generation?
f. How are utility coal production and consumption influenced by the
S02 standard and by different estimates of FGD costs?
WHAT ARE THE DIFFERENCES BETWEEN THE PROJECTED IMPACTS
OF THE FULL AND PARTIAL SCRUBBING ALTERNATIVES?
a. What are the cost and emission differences between the various full
and partial scrubbing options?
b. How does the form of the revised standard influence the costs of
pollution controls?
8
-------
III. HOW WILL UTILITY COAL CHOICES IN KEY STATES BE AFFECTED BY
DIFFERENT SO, EMISSION STANDARDS AND UNCERTAINTIES IN KEY
FACTORS? L
a. What estimates can be made regarding the typical utility costs of
buying, transporting, and burning different coals, and of required
pollution controls, as a function of the $©2 standard?
b. What is the sensitivity of fuel-cycle costs to coal mine prices?
c. What is the sensitivity of fuel-cycle costs to coal transportation
costs?
d. What is the sensitivity of fuel-cycle costs to western coal character-
istics?
e. What is the sensitivity of coal and pollution control choices to
different engineering estimates of FGD costs?
IV. HOW ACCURATE AND RELIABLE ARE MEASURES OF THE COST
EFFECTIVENESS OF VARIOUS STANDARDS?
-------
2. SUMMARY OF PRINCIPAL RESULTS
This section presents some of the major conclusions of the Phase 3 sensitivity
studies and impact projections for alternative revised New Source Performance
Standards (RNSPS).
Environmental Impacts
Included below are the key results on regional SO2 emissions and percentage cost
changes, RNSPS-plant SCU emissions, FGD capacity, and FGD sludge and coal
ash production.
Emissions
National power-plant 502 emiss'ons from '^85 to 2000
are shown in Figure 2-1. S©2 emissions increase under
the current NSPS because of The rapid increase in coal-
fired power generation after 1985. SO2 emissions begin
to decrease under the revised NSPS after 1995, both
because of the tighter standards and because of retire-
ments of older plants (plants regulated by more lenient
State Implementation Plan standards). However, under
the current NSPS, SO, emissions increase through the
year 2000 even though old plants are being retired.
National SO2 emissions in 1995 decrease by 19.7 percent
under the fun scrubbing option (0.2 Ib floor), by 17.5 per-
cent under the 0.6 Ib floor, and by 12.7 percent under the
0.6 Ib uniform ceiling.
Regional S02 emissions in 1995 change under alternative
RNSPS as shown in Figure 2-2. Compared with projec-
tions for the baseline case (the current NSPS), the great-
est emission reductions occur in the West South Central
region. There emissions decrease by 44 percent under the
full scrubbing option (0.2 Ib floor) and by 28 percent under
the 0.6 Ib uniform ceiling. In the Pacific region, SO2
emissions decrease by 57 percent under the full scrubbing
option and by 29 percent under the 0.6 Ib uniform ceiling
II
-------
Figure 2-1
National Power-Plant SO, Emission*
Higher FGO Costs
25-
24-
23-
22-
21-
20-
N>
"
"
14
13
12
11
Currant NSPS
0.6 Uniform Ceding.
33% Removal
0.« Floor, 1.2 Ceding
0.2 Floor, 1.2 Ceiling
19T«
1965
1990
1995
2000
YEAR
-------
Figure 2-2
Regional SO2 Emissions (10* Tons), 1995
Higher FGD Costs
Current NSPS
0.6 Uniform Celling,
33% Removal
0.6 Floor, 1.2 Celling
0.2 Floor, 1.2 Celling
-------
(a partial scrubbing option). It is in the Pacific and West
South Central regions that the impacts of full and partial
scrubbing differ most substantially. Percentage emission
differentials in the East and Midwest are smaller, but
nevertheless important.
SO2 Emissions from RNSPS-Controlled Plants
The results given above are for total emissions that is,
emissions from existing pre-1977 plants (regulated by
SIPs), existing post-1977 plants (regulated by the current
NSPS), and post-1982 plants (assumed to be regulated by
the RNSPS or by SIPs more stringent than the RNSPS).
Figure 2-3 illustrates how SO, emissions are distributed
in 1995 among these three regulatory categories of plants.
Under a full scrubbing option, the RNSPS plants' emit half
the SOj they would emit under the 0.6 Ib uniform ceiling
and 28 percent of what they would emit under the current
NSPS.
In 1995 in the East, average RNSPS plant SCK emissions
drop from 0.6 Ib SO,/10 Btu under the 0.61b uniform
ceiling to 0.36 Ib S02/I0 Btu under a full scrubbing
option.
In 1995 in the West South Central region,,average RNSPS
plant emissions drop from 0.6 Ib SO2/ID Btu under the
0.6 Ib uniform ceiling to 0.29 Ib SO-HO Btu under a full
scrubbing option.
In 1995 in the Mountain and Pacific regions, average
RNSPS plant emissions drop from 0.6 Ib S02/IOGBtu
under the 0.6 Ib uniform ceiling to about O.I6 Ib SO2/
10 Btu under a full scrubbing option.
Since RNSPS plants will have expected operating life-
times of 35 to 40 years, their emissions will account for
an increasing percentage of total emissions over time.
FGD Capacity
When projections are based on higher FGD costs, FGD
capacity reaches I94GW by the year 2000 under the
-------
Figura 2-3
National SO2 Emissions from Coal-Firad Powar Plants, 1995
Highar F6D Coats
20-
Current NSPS
|::i::| 0.6 Uniform Calling,
33% Rtmoval
0.6 Floor, 1.2 Ctlling
0.2 Floor, 1.2 Celling
CO
M
o
to
to
IU
O
(0
SIP-Regulatad
Plants
Current-NSPS-
Regulatsd Plants
Ragulatad Plants
IS
-------
current NSPS, 423 GW under the 0.6 Ib uniform ceiling,
and 5IOGW under a full scrubbing option. The net coal
capability in 2000 is projected to be about 630 GW.
When projections are based on lower FGD costs, FGD
capacity reaches 295 GW by 2000 under the current NSPS
(a substantial increase over the higher FGD cost projec-
tion), 452 GW under the 0.6 Ib uniform ceiling, and
505 GW under the 0.2 Ib floor, full scrubbing option. The
net coal capability is the same as that projected using
higher FGD costs.
Projected regional FGD capacity is shown in Figure 2-4.
The regions with the largest relative increases are the
Pacific, West South Central, and North Central.
FGD Sludge and Coal Ash Production
In I99i production of scrubber sludge increases from
15 x 10, tons (dry basis) under the current NSPS to
51 x 10 tons under full scrubbing. In the same year,
production of coal ash for disposal increases /.from
88 x 10 tons under the current NSPS to lOOx IO5 tons
under full scrubbing. Figure 2-5 illustrates national
sludge and coal ash production and FGD capacity in 1995
for the various RNSPS. The impacts of sludge disposal
will depend significantly on the individual power-plant
location. The volumes of FGD sludge produced are
smaller but of the same order of magnitude as the
volumes of coal ash. It should be noted that these
projections assume the use of wet scrubbing technologies:
lime, limestone, and magnesium oxide. Dry scrubbing
technologies will be included in later studies.
Economic Impacts
This section presents key national results for cumulative pollution control invest-
ment, the average monthly residential electricity bill in 1995, the present value
of total utility expenditures to 1995, national and regional increases in utility
costs and the corresponding decreases in SC>2 emissions, and the incremental
costs of SC>2 reduction as determined by a widely used but questionable measure
of cost effectiveness, expressed as dollars per ton of SC^ removed.
16
-------
Figure 2-4
Regional FGO Capacity (GW), 1995
Higher FGD Costa
Current NSPS
!i:::| °-8 Uniform Ceiling,
33% Removal
0.6 Hoor, 1.2 Ceiling
0.2 Floor, 1.2 Ceiling
-------
Figure 2-5
National Sludge and Coal Aeh Production and FGD Capacity, 1995
Higher FGD Coeta
W!
Current NSPS
0.6 Uniform Celling,
33% Removal
0.6 Floor, 1.2 Celling
0.2 Floor, 1.2 Ceiling
100-,
O
&
1-350
-300
-250
200
150
fe
O
!
O
O
100
-50
Sludge
Coal Ash
FGO Scrubber
Capacity
18
-------
Cumulative Pollution Control Investment
Between 1983 and 2000, under the current NSPS, cumula-
tive investment for pollution controls (including water and
air pollution controls for electric utilities) is projected to
be $40 billion (1975 $). Under the 0.6 Ib uniform ceiling,
pollution control investment increases by $28 billion
(70 percent); and under the full scrubbing option it in-
creases by $42 billion (105 percent). These results are
based on the higher (PEDCo) FGD cost estimates, which
reflect conservatism regarding FGD design.
As indicated earlier, under the lower (TVA) FGD cost
estimates (which are about 40 percent lower than
PEDCo's and reflect a less conservative approach), FGD
capacity under the current NSPS significantly increases.
This is because lower FGD costs would make scrubbing
more economically attractive. Pollution control invest-
ments from 1983 to 2000 under the current NSPS are $34
billion (1975$). Under the 0.6 Ib uniform ceiling they
increase by $14 bill ion (41 percent); and under the full
scrubbing option they increase by $18 billion (53 percent).
The higher and lower FGD cost projections are compared
in Figure 2-6.
National Average Monthly Residential Electricity Bill
The national average monthly residential electricity bill
in 1995 increases from $54.68 under the current NSPS to
$56.21 under the 0.6 Ib uniform ceiling (a 2.8 percent
increase). Under the full scrubbing option it rises to
$57.37 (a 4.9 percent increase). These projections assume
the higher FGD cost estimates. Using the lower esti-
mates reduces the expected monthly cost of electricity in
1995: the cost is $52.67 under the current NSPS, $53.75
(a 2.1 percent increase) under the 0.6 Ib uniform ceiling,
and $53.99 (a 2.5 percent increase) under the 0.2 \b floor,
full scrubbing option. A more stringent full scrubbing
option, the 0.5 Ib ceiling with 90 percent removal, would
lead to slightly greater cost increase (to $54.61 a month,
or a 3.6 percent increase). Using the lower instead of the
higher FGD cost estimates reduces the projected average
residential electricity bill under the 0.2 Ib floor, full
scrubbing option by over $3 per month in 1995.
Figure 2-7 compares the 1995 monthly residential bills.
19
-------
Figure 2-6
Comparison of Cumulative Pollution Control Investment, 1983-2000,
Reflecting Higher and Lower FOD Costs
(Billions 197BS)
Currant NSPS
0.8 Uniform Calling,
33% Removal
0.6 Floor. 1.2 Ceiling
0.5 Uniform Ceiling,
90% Removal
0.2 Floor, 1.2 Ceiling
Higher FGD Costs
Lower FQD Costs
20
-------
Figure 2-7
National Avaraga Rasidantial Monthly Elaetric Bill in 1996
and Parcantaga Ineraaaa from Currant N8PS
(1975$)
Currant NSPS
I 0.6 Uniform Getting.
' 33% Removal
0.6 Floor. 1.2 Citing
0.6 Uniform Ceiling,
90% Removal
0.2 Floor. 1.2 Ceiling
57.02 57.37
(4.3%) (4.9%)
a a
* a a
e a a a a
e a a a a
e a a a
e a a a
ea a* a
e a a a a a
a a a a a
e a a a aa
a a a a a
e a a a a a
a a a a a
a a a a a
a a a*a
a a a a a
a a a a a
a a a a a
a a a a f
a a a at
a a a a
a a a a 4
a a a a <
e a a a a <
a a a a
a a a a
a a a a
54.61
53.75 (3.6%) 53.99
52.67
Higher FQD Coat*
Lower FQD Coets
21
-------
Present Value of Total Utility Expenditures to 1995
Under higher FGD costs, the present value of total utility
expenditures to 1995 in 1975 dollars is as follows:
Current NSPS - $819 billion (0 percent in-
crease)
0.6 Ib uniform ceiling - $826 billion (0.8 percent in-
crease)
Full scrubbing
(0.2 Ib floor) - $832 billion (1.6 percent in-
crease)
Under lower FGD costs, the present value of total utility
expenditures to 1995 in 1975 dollars is as follows:
Current NSPS - $805 billion (0 percent in-
crease)
0.6 Ib uniform ceiling - $809 billion (0.6 percent in-
crease)
Full scrubbing
(0.2 Ib floor) - $811 billion (0.7 percent in-
crease)
Emission and Percentage Cost Changes
The increases in national total utility costs and percent-
age S02 reductions for alternative RNSPS are shown in
Figure 2-8. Note that the cost increases range only from
3 to 5 percent, while the corresponding 562 emission
reductions range from 13 to 20 percent.
The regional projections generally reflect the projected
national impacts, with the eastern regions showing rela-
tively less change in magnitude than the western regions,
as shown in Figures 2-9 through 2-11.
22
-------
Figure 2-8
National Percentage Increaee in Total Utility Cost and Percentage Decrease
in SO, Emissions for Revised NSPS. 1995
Higher FGD Costs
* *| SO, Reduction
Increwe in Totsl Utility Costs
20-1
19.7
-------
Figure 2-9
Comparison of SO2 Emission Reductions and Increases in Total Utility Costs
for Revised NSPS Relative to Current IMS PS, 1995
Higher FGD Costs
0
BO
CO
2
Ul
c
c
o
2
o
E
ID
o
i
o
Ul
s
Ul
O
c
40<
30<
20-
10-
802 Reduction
Increase in Total Utility Costs
0.6 Uniform 0.6 Floor 0.2 Floor.
Coiling 1.2 Ceiling 1.2 Calling
0.6 Uniform 0.6 Floor 0.2 Floor.
Coiling 1.2 Coiling 1.2 Colling
Northeast
Southeast
-------
Figure 2-10
Comparison of SO2 Emission Reductions and Increases in Total Utility Costs
for Revised NSPS Relative to Current NSPS, 1995
Higher FGD Costs
60-
SOj Reduction
Increase In Total Utility Costs
0.6 Uniform 0.6 Floor, 0.2 Floor,
Calling 1.2 Celling 1.2 Collins
North Central
0.6 Uniform 0.6 Floor, 0.2 Floor,
Celling 1.2 Celling 1.2 Celling
West South Central
25
-------
Figure 2-11
Comparison of SO2 Emission Reductions and Incraasas in Total Utility Costs
for Ravisad NSPS Rslativa to Currant NSP8, 1995
Highar FGD Costs
SO] Reduction
Increase in Total Utility Costs
0.6 Uniform 0.0 Floor, 0.2 Floor,
Coiling 1.2 Ceiling 1.2 Celling
0.6 Uniform 0.6 Floor, 0.2 Floor,
Ceiling 1.2 Celling 1.2 Celling
Mountain
Pacific
26
-------
Total utility costs under the higher FGD cost assumptions
are slightly greater for the 0.6 Ib floor than for the 0.2 Ib
floor in the Southeast, yet the same is not true for the
other regions. This phenomenon is caused by two factors
the delivered price of coal and the scrubbing require-
ment. Under the 0.6 Ib floor, southeastern utilities con-
sume more low-sulfur coal and scrub less than under the
0.2 Ib floor. Under the 0.2 Ib floor, utilities will use
locally available higher-sulfur coals with a lower de-
livered price, which offsets the slightly increased cost of
scrubbers. The close similarity between these two RNSPS
options (0.2 Ib and 0.6 Ib floor) is discussed in Section 3.
Incremental Costs of SCU Reduction: Dollars per Ton of SOj Removed
Dollars per ton of SO 2 removed has been used in other studies as a measure of
the cost effectiveness of alternative RNSPS. Section 3 discusses the short-
comings of this measure due to the uncertainties which affect its calculation.
As shown in Section 3, great care must be exercised when considering this
measure. The absolute uncertainty and the relative uncertainties of this
measure when compared for alternative RNSPS make comparisons with other
model results difficult. This measure also varies significantly by region.
Remembering the above caveats and using higher FGD
costs, the 1995 incremental costs per ton of SC^ "removed
in 1975 dollars are as follows:
0.6 Ib uniform ceiling $1,375
0.6 Ib floor $1,531
0.2 Ib floor $1,591
Remembering the above caveats and using lower FGD
costs, the 1995 incremental costs per ton of SC^ removed
in 1975 dollars are as follows:
0.6 Ib uniform ceiling $900
0.2 Ib floor $900
0.5 Ib ceiling, 90 percent removal $831
27
-------
Resource Utilization
This section compares the impacts of alternative RNSPS on utility fossil fuel
consumption, on water consumption for cooling and FGD, on regional utility coal
production, and on movements of western coal to the East.
Utility Fossil Fuel Consumption
Figure 2-12 shows projected utility consumption of fossil fuels in 1995.
Total coal consumption rises slightly as the SC^ emission
standard becomes more stringent. This is due primarily to
FGD energy requirements.
Projected oil consumption is largely independent of the
revised NSPS but does depend significantly on oil plant
retirement schedules. Considerable oil plant retirements
are projected to occur in the decade between 1985 and
1995, and these will reduce utility oil consumption over
rime. (See Appendixes F and H.) In the USM, oil plants
are retired on the basis of age, announced utility plans,
and government coal conversion programs, and not
strictly on the basis of oil price. This is appropriate for a
number of reasons:
High fuel oil costs are usually passed through to the
customer
Oil plants are often located in urban areas where
coal storage space is not available
It is much easier for a utility to operate an existing
oil plant than to site, build, and operate a new coal
plant
Oil plants are often located in strategic locations in
the distribution grid and in 1995 will be used in a
cycling mode
Residual oil for electric utilities should be available
as long as petroleum is refined for gasoline for use
in motor vehicles, etc. The availability of oil will
depend more on future government oil policy than
on oil prices, which are already high compared to
coal.
28
-------
30-
Flgurs 2-12
Utility Fossil Fusl Consumption, 1995
Hiflhsr FGD Costs
25-
20-
N>
VO
o>
Current NSPS
TIT] 0.6 Uniform Celling,
33% Removal
0.6 Floor, 1.2 Celling
0.2 Floor, 1.2 Ceiling
15-
10-
Totnl Fossil
Fuel Consumption
Coal Consumption
Oil Consumption
1-1
-.75
-.SO
-.25
Fuel Used in
Transporting Coal
-------
Lower utility reserve margins in 1995, about 20 per-
cent, will discourage differential retirements of the
remaining oil capacity simply in response to more
stringent RNSPS
Oil plants in the 1990s will be dispatched after coal plants
because of their high fuel cost. Since the load curves are
assumed constant for each alternative NSPS, their use,
and hence oil consumption, does not change with the
alternative New Source Performance Standards. If, how-
ever, scrubber reliability is lower than assumed, the
remaining oil plants could be utilized more although it
is also possible that utilities might build more nuclear
plants if coal plants proved to be less reliable.
The amount of diesel fuel used in transporting coal
depends on the amounts of western coal shipped east and
varies by about a factor of 1.5 with changes in RNSPS.
The magnitude of this oil consumption in Btu^ is about
one-tenth of that for residual oil to be burned for
electricity generation in 1995.
Utility Water Consumption
Total utility water consumption in 1995 for a full scrub-
bing option increases by about 5 percent over the current
NSPS baseline under the higher FGD cost estimates, and
by about 3 percent under the lower FGD cost estimates.
Under a full scrubbing option, total water consumption by
FGD equipment is about 9 percent of the water consump-
tion for generation cooling purposes. (See Figure 2-13.)
These calculations assume only wet scrubbing technol-
ogies. Dry scrubbing technologies should lead to lower
levels of consumptive water use than those given here.
An increase of less than I percent per year in the rate of
growth of electricity demand leads to a greater increase
in total water consumption in 1995 than does the in-
creased use of scrubbing under alternative RNSPS.
As with SO? emissions and scrubber sludge disposal, the
impacts of increased water consumption will depend on
the location of individual power plants.
30
-------
Figure 2-13
Utility Water Consumption. 1995
Higher F6D Co»t«
6-1
M
111
u.
ULI
3H
.1
Cooling
FGD
6.4* pw YMr
Growth Rat*
(1976-1996)
(5431 TWh)
Current
NSPS
0.6 Uniform
Criltng
0.6 Floor,
1.2 Celling
0.2 Floor,
1.2 Celling
4.3% per Year Growth Ret* (1976-1996)
(4470 TWh)
31
-------
Coal Production for Electric Utilities
The electric utility sector consumes approximately two-thirds of the coal mined
in the United States. In 1976, national utility coal consumption was about
446 million tons.
Under the current NSPS, national utility coal consumption
is projected to grow at an average annual rate of 5.3 per-
cent between 1985 and 1995, reaching about 1,250 million
tons in 1995.
Regional coal production for electric utilities in 1995,
based on the higher FGD cost estimates, is shown in Fig-
ure 2-14. The use of low-sulfur coal (primarily from the
Northern Great Plains) is greatest under the current
NSPS. It decreases dramatically under the 0.6 Ib uniform
ceiling, while the use of Appalachian and Gulf Coast coals
increases. Under the full scrubbing option, the use of
these coals increases further.
Regional coal production for electric utilities in 1995,
ba. * on the lower FGD cost estimates, is shown in Fig-
ure i-15. Compared with the projections based on the
higher FGD costs, the position of local coals is greatly
enhanced under all standards and the production of
Northern Great Plains coal is significantly reduced. Pro-
duction of high-sulfur midwestern coals for utility use
increases under the lower FGD cost estimates as the
RNSPS become more stringent. Appalachian and Gulf
Coast coal production is greater than under the higher
FGD costs for all RNSPS except the full scrubbing option:
under full scrubbing, the projected levels using either
higher or lower FGD costs are about the same.
Coal production in all regions of the U.S. will be greater
under all RNSPS than 1978 regional production levels.
Western Coal Shipped East
The most significant differences in coal production are
demonstrated by the projections for western low-sulfur
coals shipped east of the Mississippi River. Figure 2-16
32
-------
shows the tonnages of western coal shipped east (primar-
ily to Midwestern states) under the higher FGD costs;
Figure 2-17 shows the tonnages under the lower FGD
costs. Under the current NSPS, eastward shipments of
western coal in 1995 are 240 x 10 tons under the higher
costs but only 72 million tons under the lower costs.
Under the 0.6 Ib uniform ceiling, these shipments are
reduced to 136 and 66 million tons, respectively. Using
lower future FGD costs substantially increases the pro-
jected use of local coals.
As illustrated in Figures 2-16 and 2-17, shipments of
western coal to the East also change significantly with
the RNSPS. The current NSPS and the 0.6 Ib floor
standard show the greatest use of western coal east of the
Mississippi. The 0.6 Ib uniform ceiling decreases the use
of western coal. Full scrubbing options render local coal
use more attractive and minimize the use of western coal
in the East.
Under either the higher or lower FGD cost assumptions,
the 0.6 Ib uniform ceiling enhances the position of inter-
mediate-sulfur coals, while the full scrubbing option leads
to the greatest use of cheaper, local coals (over all sulfur
contents).
Sensitivity Analyses
All the results discussed above can be considered as results of sensitivity
analyses of the national and regional effects of alternative assumptions and
alternative RNSPS. As an integral part of the Phase 3 RNSPS study, city-
specific sensitivity analyses were performed to determine ranges over which the
impacts of alternative standards will be influenced by factors over which EPA
has no control. These sensitivity analyses are discussed in greater detail in
Section 3 and Appendix C.
Ranges of Cost Uncertainties for Key Cities
In the key cities (see Appendix C for examples), the range of cost uncertainties
and utility responses due to parameters over which EPA has no control can be
33
-------
522
Figure 2-14
Utility Coal Production (10* Tons),
Higher FGD Costs
Northern Great Plains
201
Current NSPS
; I 0.6 Uniform Celling,
'I 33% Removal
0.2 Floor, 1.2 Celling
-------
Figure 2-15
Utility Coal Production (10* Tons). 1995
Lower FGD Costs
en
Northern Great Plains
33% Removal
Currant NSPS
0.6 Uniform Oiling
UnHorm Celling,
90% Removal
0.2 Floor, 1.2 Celling
-------
Figure 2-16
Western Coal Shipped East, 1995
Higher FQD Costs
o\
Western Coal 0.6 Uniform Ceiling
Shipped East of the
Mississippi | J
River
(In Millions of Tons)
-------
Figure 2-17
Western Coal Shipped East, 1995
Lower FGD Costs
0.2 Floor, 1.2 Celling
0.5 Uniform Celling, 90% Removal
Western Coal
Shipped East of the
Mississippi
River
f I ::.:PyW
-. \ - 1 '-'LiV ₯--"»f <
i ^t f ' r-v ^.^ * <,, f
-------
greater than the range of cost increases expected with the more stringent
RNSPS options. Parameters over which EPA has no control include, for example,
the sulfur contents and heating values of Powder River Basin coals, f.o.b. mine
prices for midwestern coals, and coal transportation rates. For the key cities
discussed in this report, the uncertainties in costs associated with these
parameters span a wider range than the cost increases imposed by selecting a
full scrubbing over a partial scrubbing option.
Levelized fuel-cycle costs are sensitive not only to variations in the level and
form of the emission standard but also to variations in other key parameters.
(See Section 3 and Appendixes B and C for details.) Some general conclusions
are:
As the revised NSPS become more stringent, levelized
fuel-cycle costs increase substantially (by as much as
25 percent) for low-sulfur coals while remaining nearly
constant or increasing only slightly for high-sulfur coals.
Therefore, local coals become increasingly competitive at
more stringent standards. These effects are reflected in
the impact projections discussed above.
The estimated difference in levelized fuel-cycle cost
between the cheapest local (eastern) and distant (western)
coals does not exceed approximately + 15 percent over a
range of SO, standards between 0.2 and 1.2 Ib SO,/
I06 Btu. L *
Relatively small changes (on the order of + 10 percent) in
coal mine prices, coal transportation rates, FGD cost
estimates, and/or coal characteristics (sulfur and Btu
content) can significantly affect the economic competi-
tiveness of eastern versus western coals. In many cases,
utility economic choices are more sensitive to these costs
than they are to cost differences resulting from changing
the level of the revised NSPS. In Section 3 we present
graphs that demonstrate each of these variations for coal
plants located near Columbus, Ohio. Appendix C presents
further sensitivity analyses for other key cities, examin-
ing sensitivity as a function of these variable parameters
and the SO, emission standard.
38
-------
Distinguishing Differences among the Impacts of Various
Partial Scrubbing Options
The impacts of many of the very similar partial scrubbing
options investigated in other analyses are, in practice,
indistinguishable, because of the uncertainties in future
costs likely to be faced by individual utilities in each
state. Many of the myriad numbers presented for similar
standards at EPA's December 12th hearings are, in fact,
overlapping results that add little to the ability to choose
between feasible options.
The Implications and Reliability of Cost-Effectiveness Measures
Cost per ton of SC^ removed is not definitive as a cost-effectiveness measure
for comparing alternative standards. This is because (a) it changes rapidly as a
function of the required level of emissions, and (b) uncertainties are introduced
by aggregating this measure across many different coals and power-plant
situations. This cost-effectiveness measure and the companion measures of cost
per kWh and cost per Btu of fuel input are discussed and illustrated graphically in
Section 3.
The Implications of Lower versus Higher Future FGD Costs
As previously indicated, the FGD capital and operating cost estimates supplied in
December 1978 by the Tennessee Valley Authority are substantially lower than
PEDCo's. (See Appendix A for details.) These differences reflect different
engineering cost criteria and degrees of conservatism in cost estimation. Either
set of estimates could be used to describe future FGD costs under different
utility situations. Previous RNSPS studies have used PEDCo costs. Some
important comparisons are:
For lime FGD systems, TVA's capital costs are about
30 percent lower than PEDCo's, and TVA's operating costs
are 20 percent lower. For limestone systems, TVA's
capital and operating costs are about 40 percent and
27 percent lower, respectively.
-------
In general, lower FGD costs relative to higher FGD costs will:
Increase the attractiveness of local coals and increase the
projected amount of scrubbing for any partial scrubbing
option. The amounts of scrubbing mandated under the full
scrubbing option are very similar under both sets of costs.
t
Reduce dramatically projected shipments of western coal
to the East.
Reduce projected generation and therefore projected SO?
emissions from existing plants in the East (because of
relatively cheaper operating costs for new plants under
lower as compared with higher FGD costs).
Reduce the projected differences between full and partial
scrubbing options.
The two different ranges of impacts defined by the forecasts using the TVA and
PEDCo costs can be interpreted as bounding the most likely impacts of the
RNSPS. They also reflect the other uncertainties investigated in the sensitivity
studies.
The Form of the Revised Standard
The form and technical requirements of any given standard have important
implications for pollution control costs. Some general conclusions include the
following:
Variable bypass on FGD scrubbers is less cost effective
than fixed bypass for emission control. (See Figure 2-18.)
For the same annual emission level, an annual average or
30-day standard compared with a 24-hour standard
permits greater FGD gas bypass for a given coal and
results In lower energy penalties. All standards were
evaluated assuming a constant SO2 removal efficiency,
i.e., fixed bypass. However, short-ferm emissions result-
ing from coal sulfur variability may be higher than the
annual average. This likelihood and the diurnal nature of
adverse air pollution episodes indicate the need for set-
ting appropriate 24-hour standards In conjunction with the
longer-term standards.
-------
Figura 2-18
Comparison of FGD Cost Effactivanaas par Ton of 8O2 Romovad
undar 24-Hour Avaraga SO, Control Attarnativas
with 1.2 lb/10* Btu Calling
2000-1
1800-
1800^
s
s
1400-
1200-
o
§
1000 <
800<
600-
400
T-
Subbftuminous Coal
Fixad Bypass
-Vsrisbls Bypass
BHuminous Coal
Flxsd Bypass
« Variabla Bypass
1.33 Ib S/1P Btu
- ""2.17 Ib S/10« Btu
3.87 Ib S/10* Btu
0.4 0.8 0.8 1.0 1.2
24-HOUB AVERAGE SO, FLOOR (LI SO,/10* BTU)
-------
Setting an annual or 30-day standard specified as a
uniform ceiling with no mandatory percentage removal
requirement results in equivalent emissions from all
power plants regardless of the quality of the coal burned.
All other forms of the standard result in emissions that
depend on the sulfur and Btu content and sulfur variability
of the coal burned.
To achieve the same annual emissions for a given coal, an
SO, standard with an annual averaging period compared
wifn the equivalent standard with a 24-hour averaging
period will permit lower costs per kilowatt-hour of elec-
tricity produced. This is principally due to coal sulfur
variability.
For the 24-hour standards, given the specified assump-
tions regarding scrubber design and performance, there is
very little difference in annual emissions between the
"without exemptions" and "with exemptions" cases (the
latter being those cases in which the mandatory 85 per-
cent removal is allowed to drop to 75 percent three days
per month). Since the three-day-per-month exemption
should permit greater flexibility in utility operation, it
appears to be an effective element of a 24-hour standard.
Comparison of One Full and One Partial Scrubbing Option
Numerous potential RNSPS have been analyzed. In this section we briefly
summarize the projected impacts of the 0.6 Ib uniform ceiling (a partial
scrubbing option) and the 0.2 Ib floor (a full scrubbing option). .Finally, we
mention some other factors that will influence the final choice of the RNSPS.
SO2 Emissions
In most of the East and Midwest, as indicated !n
Table 2-1, full scrubbing will reduce 502 em'ss'ons by 'ess
than 10 percent over the partial scrubbing option in 1995.
This is primarily due to the large amount of remaining SIP-
regulated plants subject to more lenient emission stan-
dards in these regions. However, in the West South
Central region and the West, SOj emissions can be
25 percent lower over the entire region under full scrub-
bing compared with partial scrubbing.
-------
Table 2-1
Percentage SO9 Emission Reduction in 1995 under
Full ScrubbingTxmpared with Partial Scrubbing0
National
East
Midwest
West South Central
West
Higher FGD Costs
8.0%
7.2%
3.0%
22.3%
25.6%
Lower FGD Costs
4.3%
1.8%
3.4%
9.6%
20.4%
Full scrubbing: 0.2 Ib floor. Partial scrubbing: 0.6 Ib uniform ceiling.
Using lower rather than higher FGD costs reduces absolute emission levels
under all RNSPS because FGD usage is relatively less expensive. Thus, the
relative emission differences are smaller.
-------
Regional aggregations belie the local emission changes
that can occur. Figures 2- 1 9, 2-20, and 2-21 show the
changes in projected emissions at the county level for
three groupings of states. Note that large percentage
differences occur in a number of counties in western
states and in the West South Central region. While
percentage change is not the definitive measure of
analysis and should not be relied upon exclusively, it
nonetheless illustrates relative local variations between
full and partial scrubbing.
It should also be noted that, compared with partial
scrubbing, full scrubbing can lead to greater emissions in
some counties. This can occur as the result, under full
scrubbing, of selecting a coal of much higher sulfur
content than would be used under partial scrubbing or of
operating SIP-regulated units at slightly higher capacity
factors. In most counties, however, the emission dif-
ferences between full and partial scrubbing are less than
ten percent.
2 emissions from RNSPS plants regulated by a full
scrubbing standard can be less than half of those from
RNSPS plants under a partial scrubbing standard. Because
emissions from SIP-regulated plants dominate total emis-
sions over the 1985-2000 period, the difference between
full and partial scrubbing will become more significant as
these older plants are retired. Differences will also be
greatest in those regions that do not currently have large
amounts of coal generating capacity.
If a partial scrubbing option were adopted now (which
would affect plants coming on line after 1982) and a full
scrubbing option were implemented four years from now
for plants coming on line after 1987, SO 2 emissions in the
year 2000 in the western U.S. would be 8 to 10 percent
higher than if a full scrubbing option were adopted now.
Economic Costs
Under the full scrubbing option, cumulative pollution
control investment is 21 percent higher than under partial
scrubbing if the higher FGD cost estimates for wet
scrubbing processes are used, but only 8 percent if the
lower estimates are used. The use of dry scrubbing
technologies would probably reduce the differentials
between the costs of full and partial scrubbing.
-------
Figure 2-19
Percentage Change in Power*Plant SO2 Emieeions in 1995:
Partial vs. Full Scrubbing
West North Central and Mountain and Pacific Regions
Each square represents a county with SO, emission changes.
P.rc.nt.9. Chsng. =
D 10-110%
Q -10%-
D <-io%
O Class I Areas
Partial Scrubbing: 0.6 Ib 8O|/10* Btu annual calling, 99% minimum removal.
Full Scrubbing: 0.63 Ib 80^10* Btu annual calling, 90% minimum removal.
-------
Figure 2-20
Parcantage Change in Power-Plant SO, Emission* in 1995:
Partial vs. Full Scrubbing
Waat South Cantral Ragion
Each square represents a county with SO, emission changes.
Percentage Change - (**%,'F"'')
B 10110%
D -10% +10%
D <-io%
C* Class I Areas
Partial Scrubbing: 0.6 Ib 80^10* Btu annual celling, 33% minimum removal.
Pull Scrubbing: 0.63 Ib SOt/10* Btu annual celling, 90% minimum removal.
-------
Figure 2-21
Percentage Change in Power-Plant SO2 Emission* in 1995:
Partial vs. Full Scrubbing
East North Central, East, and East South Central Regions
Each square represents a
county with S02 emission changes.
" Fu" )
Percentage Change = (
B 10 110%
D -10%
0 .10%-60%
Q -60%--110%
Class I Areas
Partial Scrubbing: 0.6 Ib SO,/10*Btu annual celling, 33% minimum removal.
Full Scrubbing: 0.63 Ib SO,/10* Btu annual celling, 90% minimum removal.
-------
National average monthly electricity bills vary by less
than 2 percent, between the full and partial scrubbing
options using the higher FGD cost assumptions, and by
less than I percent using the lower FGD cost assumptions.
The present value of total utility expenditures varies less
than I percent between the full and partial scrubbing
options.
Resource Utilization
The most significant differences between the resource
utilization impacts of full and partial scrubbing are in
utility coal production. Full scrubbing results in the
greater use of local coals. Full scrubbing also reduces the
movement of western coal east of the Mississippi Riyer.
Coal markets will clearly depend on the RNSPS for 502 as
well as future scrubber costs.
Under full scrubbing, compared to this partial scrubbing
option, FGD capacity increases by about 16 percent using
the higher FGD cost assumptions, and by about 9 percent
using the lower cost assumptions. FGD sludge production
increases by about 21 percent under the full scrubbing as
compared with the partial scrubbing option.
No significant differences in utility oil consumption in
1995 are likely to occur as a result of a full scrubbing
option.
Other Factors
Models and model projections have been used to highlight the probable impacts
of alternative RNSPS. The results have indicated the areas where there are
likely to be observable differences between the RNSPS, and they have indicated
the impacts that are most sensitive to the RNSPS, as well as those that cannot
be projected with certainty. (See Section 3 for more detailed sensitivity
studies.)
Exogenous factors such as the rate of growth and acceptance of nuclear power,
the availability of gas for electricity generation, the availability of oil, and the
-------
growth in electricity demand will significantly influence the impacts of any
RNSPS.
Obviously, other factors also will bear on the selection of a revised NSPS. Some
of these are listed below in two categories of questions: questions of technolog-
ical capability, and questions of political feasibility.
Questions of Technological Capability
a. Will scrubbers perform reliably at the levels required for
full scrubbing?
b. Can dry scrubbing technologies significantly reduce the
costs of scrubbing lower-sulfur coals?
c. Will greater coal sulfur variability than assumed in these
analyses necessitate using higher percentage removals or
lower-sulfur coals in order to meet 24-hour-average
standards?
d. Will emission-monitoring devices adequately measure
compliance with the proposed RNSPS?
e. Is the flexibility of utility operation significantly greater
for longer averaging times (e.g., 30 days instead of daily)?
What benefits would result from longer averaging times?
What disbenefits?
Questions of Political Feasibility
a. How will "local coals*1 be defined under Section 125 of the
1977 Clean Air Act Amendments? Will this definition
influence the availability of lower-sulfur coals for use
under a partial scrubbing option?
b. What are the employment implications of full versus
partial scrubbing?
c. How will full versus partial scrubbing affect visibility in
pristine areas of the West?
d. What regional air quality impacts will result from full
versus partial scrubbing?
-------
e. What, if any, inflationary impacts can be expected to
result from the RNSPS?
f. Will the usable reserve base of U.S. coals be affected by
the choice of RNSPS?
g. How will the new SIPs to be implemented after 1979
affect electric utility operations? What are the expected
lifetimes of SIP-regulated plants?
h. How will PSD and non-attainment provisions of the Clean
Air Act (1977) influence required emission limits?
Answers to these questions will be discussed and debated during the period prior
to selecting a revised NSPS.
50
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3. KEY QUESTIONS AND ANSWERS
This section discusses in detail the results of the sensitivity studies in order to
answer critical questions pertinent to the selection of a revised New Source
'Performance Standard for SCK- The appendixes contain additional information.
I. WHAT ARE THE LIKELY IMPACTS
OF A REVISED NSPS?
a. HOW WILL NATIONAL COSTS AND S02 EMISSION REDUCTIONS, BASED
ON THE HIGHER (PEDCO) FGD COSTS, BE DISTRIBUTED REGIONALLY IN
1995 FOR THE FULL SCRUBBING OPTION (0.2 LB FLOOR) AND THE PARTIAL
SCRUBBING OPTIONS (0.6 LB FLOOR and 0.6 LB UNIFORM CEILING)?
In 1995, national utility 502 em'ss'ons drop from 22.8 million tons projected
under the current NSPS to 19.9 million tons (12.7 percent reduction) under the
0.6 Ib uniform ceiling, 18.8 million tons (17.5 percent reduction) under a 0.6 Ib
floor, and 18.3 million tons (19.7 percent reduction) under a 0.2 Ib floor. Total
utility costs increase over those of the current NSPS by about 2.9 percent,
4.4 percent, and 5.2 percent for the uniform ceiling, 0.6 Ib floor, and 0.2 Ib floor,
respectively. The percentage changes shown in Table 3-1 indicate some signifi-
cant regional differences. These differences were illustrated earlier in
Figures 2-9 through 2-11. Regional $©2 emissions were illustrated in
Figure 2-2.
In the West South Central region, where a considerable amount of new coal-fired
capacity can be anticipated as a result of the phasing out of natural gas as a
boiler fuel, emissions are expected to decrease by as much as 44 percent while
costs increase by 15 percent. In the Mountain and Pacific regions, the combined
SO* emission reduction will be about 37 percent under a full scrubbing option,
28 percent under the 0.6 Ib floor, and 16 percent under the 0.6 Ib uniform ceiling.
Cost increases in the Mountain and Pacific Regions will be about 7 percent,
51
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Table 3-1
run win r-wTiai ocruuoing vs. v~urrenT rarjs rercemage v~nanges in rteyronui
SO2 Emissions and Total Utility Costs in I995a
0.2 Ib F>oorb 0.6 Ib Floor6 0.6 Ib Uniform Ceiling0
(Full Scrubbing) (Partial Scrubbing) (Partial Scrubbing)
Census SO? Emission Cost SO? Emission Cost SO, Emission
Regions Reduction (%) Increase (%) Ratio Reduction (%) Increase (%) Ratio Reduction (%)
Nation 19.7 5.2 3.8 17.5 4.4 4.0 12.7
r4ortheasfd 20.0 1.0 20.0 20.4 1.0 20.4 13.7
Southeast6 17.9 2.3 7.8 17.6 3.0 5.9 12.6
North Central' 7.5 4.8 1.6 4.3 5.0 0.9 5.2
West South 44.2 14.7 3.0 42.0 9.3 4.5 28.2
Central
Mountain 21.9 6.0 3.7 16.0 4.S 3.6 10.3
Pacific 55.0 7.4 7.4 41.5 5.6 7.4 21.7
0 These results reflect the higher (PEDCo) FGD costs.
1.2 Ib SO 2/10 Otu daily ceiling with exemptions; 90 percent removal with specified 24-hour floor.
c Annual average SO2 emission celling of 0.6 Ib SO^ 10 Btu.
d New England and Middle Atlantic Census Region states.
e South Atlantic and East South Central Census Region states.
Cost
Increase (%) Ratio
2.9 4.4
1.0 13.7
1.8 7.0
2.7 1.9
6.5 4.3
3.4 3.0
4.6 4.7
East I
-------
5 percent, and 4 percent under the three options respectively. The emission
reduction can be as large as 55 percent in the Pacific Region under a full
scrubbing option or 22 percent under the 0.6 Ib uniform ceiling.
b. THE REGIONAL EMISSION PROJECTIONS INCLUDE EMISSIONS FROM
BOTH OLD AND NEW GENERATING UNITS. THE REVISED NSPS WILL
AFFECT ONLY THOSE UNITS IN OPERATION AFTER 1982, AND THESE
PLANTS AND THEIR SUCCESSORS SHOULD BE OPERATING FOR OVER
35 YEARS AFTER 1983. WHAT ARE THE DIFFERENCES IN EMISSIONS FROM
THESE RNSPS PLANTS COMPARED WITH THE OLDER UNITS SUBJECT TO
MORE LENIENT STANDARDS?
Table 3-2 and Figure 2-3 indicate the distribution of emissions from plants
regulated under State Implementation Plan standards, under the current NSPS,
and under three alternative RNSPS. It can be seen that, when scrubbing is
required for RNSPS plants, the older SIP plants may be operated at slightly
increased loads over the baseline case. However, the older SIP plants are going
to be retired over time; and, increasingly, a greater fraction of emissions will
come from RNSPS plants. It is estimated that in 1995, for example, under the
current NSPS, 6.7 million tons of SO2 (30 percent of national S02 emissions) will
come from RNSPS plants.
The 0.6 Ib uniform ceiling option reduces S02 emissions from RNSPS plants in
1995 by 2.8 million tons (42 percent), resulting in RNSPS plant emissions of
3.9 million tons, or 20 percent of national SO2 emissions. Another partial
scrubbing option (0.6 Ib floor) reduces emissions from the RNSPS plants in 1995
by 4.6 million tons (68 percent), resulting in RNSPS plant emissions of 2.2 million
tons, or 11 percent of national SO2 emissions. A full scrubbing option reduces
RNSPS plant emissions by 4.8 million tons (71 percent), bringing S02 emissions
from these plants down to 1.9 million tons, or 10 percent of national emissions.
In other words, under a full scrubbing option, RNSPS plants will emit half the
S02 they would emit under the 0.6 Ib uniform ceiling. These reductions have
regional, and longer-term implications:
53
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Table 3-2
National Coal-Fired, Power-Plant SO, Emission* by Regulatory Category
(million US. toSs per yearr
Current NSPS for 0.6 Ib Floor for 0.2 Ib Floor for 0.6 Ib Uniform Ceiling
RNSPS Units RNSPS Units" RNSPS Unitsc for RNSPS Units'5
SIP NSPS. RNSPS SIP. NSPS, RNSPS SIP NSPS, RNSPS SIP. NSPS,
Units* Units Units9 Units Units Units* Units" Units' Units9 Units Units
1585 14.3 1.
1990 13.6 1.
1995 12.1 1.
0 These results
52 0.97 14.4 1.51 0.29 14.5 1.51 0.25 14.3 1.51
54 3.92 13.9 1.54 1.26 13.9 1.53 1.10 13.7 1.53
50 6.74 13.7 1.52 2.15 13.5 1.51 1.94 13.1 1.51
reflect the higher (PEDCo) FGO Costs.
RNSPS
Units9
0.51
2.19
3.9
b 1.2 Ib SO 2/IO° Btu daily ceiling, 85 percent daily removal, 0.6 Ib floor, partial scrubbing allowed.
c Full scrubbing (same as 0.6 Ib floor above but with 0.2 Ib floor).
Uniform ceilings (0.6 Ib SO2/10 Btu annual ceiling, 33 percent minimum SO, removal requirement,
partial scrubbing allowed).
Units regulated under State Implementation Plans.
Units regulated under the current NSPS (1.2 Ib SOj/IO* Btu, annual ceiling).
Post-1982 units regulated under a revised NSPS (RNSPS).
-------
In 1995 in the East, average RNSPS coal-plant SO2
emissions under a 0.6 Ib uniform ceiling reach 0.6 ID
SOU/10 Btu, as expected, compared w«th °/36 lb S9?/
10 Btu under the 0.2 Ib floor standard (which requires
90 percent annual removal)
In 1995 in the West South Central region, average RNSPS
plant emissions would rise from 0.29 Ib SO^AJO Btu under
a 0.2 Ib floor standard, to 0.34 Ib SO?/IP Btu under a
0.6 Ib floor standard, to 0.6 Ib SO2/10 Btu under a
uniform 0.6 Ib ceiling
In 1995 in the West, average RNSPS plant emissions rise
from 0.16 Ib SOJIO Btu under a 0.2 Ib floor standard, to
0.34 Ib£02/I0 Btu under a 0.6 Ib floor standard, to 0.6 Ib
10 Btu under the 0.6 Ib uniform ceiling
c. WHAT ARE THE EMISSION PROJECTIONS FOR COAL-FIRED PLANTS
WHEN THE LOWER (TVA) FGD COST ESTIMATES ARE USED?
The results in Table 3-2 were obtained using the higher (PEDCo) scrubber cost
estimates. Table 3-3 shows results for the current NSPS and the 0.2 Ib floor (full
scrubbing) standard using the lower (TVA) FGD cost estimates.* Several
principal differences between the higher and lower FGD cost scenarios ore
observed:
For any year, the lower FGD cost estimates reduce the
costs of operating RNSPS units with scrubbers. Thus,
under the lower FGD cost scenarios, RNSPS units will be
used to generate a greater fraction of the total electric-
ity produced. RNSPS emissions in any year will be
greater under the TVA scenarios, both because more
generation occurs in these plants and because, on the
average, higher-sulfur coals are burned. However, in
several cases SO2 emissions will be lower overall than
under the higher FGD cost scenarios, because existing
units subject to more lenient SIP standards will be oper-
ated less. See Figure 3-1 as compared with Figure 2-3.
Lower FGD costs reduce the emission differences between
full and partial scrubbing options.
A brief explanation of the engineering differences between PEDCo's and
TVA's cost estimates is presented in Appendix A.
55
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National Coal-Fired, Power-Plant S02 Emissions by Regulatory Category
(million U£. tons per year)0
Current NSPS for
RNSPS Units
1985
1990
1995
SIPr
Units0
13.9
12.9
11.8
NSPS,
Units0
1.65
1.67
1.64
RNSPS
Units6
1.05
4.07
7.13
0.2 Ib Floor for
RNSPS Units*
SIP
Unitsc
14.2
12.9
11.7
NSPS.
Unitsd
1.65
1.67
1.64
RNSPS
Units6
0.35
1.66
3.07
a These results reflect the lower (TVA) FGD Costs.
b Full scrubbing (1.2 Ib SCWIO6 Btu daily ceiling, 85 percent minimum daily
S02 removal, 0.2 Ib floor).
c Units regulated under State Implementation Plans.
d Units regulated under the current NSPS (1.2 Ib S02/I06 Btu).
e Post-1982 units regulated under a revised NSPS (RNSPS).
56
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Figure 3-1
National SO2 Emissions from Coal-Fired Power Plants, 1995
Lower FGD Cost*
20-,
Currtnt NSPS
0.6 Uniform Calling,
33% Removal
0.5 Uniform Ceiling,
90% Removal
0.2 Floor, 1.2 Ceiling
15-
SIP-Regulated
Plants
Current-NSPS-
Regulated Plants
Revieed-NSPS-
Regulated Plants
57
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Table 3-4 indicates regional cost and emission differences expressed os a
percentage change from the current NSPS baseline. Figure 3-2 shows regional
SC>2 emissions for various RNSPS under the lower cost estimates for FGD.
Figure 3-3 shows the national cost changes associated with lower FGD costs and
should be compared with Figure 2-8.
d. WHAT ARE THE PRINCIPAL UTILITY CAPITAL INVESTMENTS FOR
VARIOUS STANDARDS USING LOWER AS COMPARED WITH HIGHER ESTI-
MATES OF FUTURE SCRUBBER COSTS?
Total pollution control investment costs drop substantially under the lower FGD
cost scenarios, because TVA's lower FGD capital cost estimates are about
57 percent of PEDCo's on a dollar-per-kilowatt basis. See Figure 2-6 for a
comparison of the cumulative pollution control investments. Figure 3-4 shows
the total pollution control investment compared with total utility investments.
The total utility investment differences across RNSPS reflect a slight increase in
generating capacity required by the operation of additional FGD systems.
For both FGD cost calculations (assuming only wet scrubbing technologies),
about 320 GW of scrubbers are projected for 1995 under the full scrubbing option
(0.2 Ib floor). However, under the current NSPS baseline standard, the lower
TVA scrubber costs increase the use of higher-sulfur local coals and hence the
amount of scrubber capacity: 133 GW of scrubbers are projected for 1995 under
the higher FGD cost case, and 201 GW under the lower FGD cost case.
Tables 3-5 and 3-6 show cumulative investment figures under both sets of
scenarios. Figure 2-7 compares projections for the national average monthly
residential electricity bill in 1995.
Note that while pollution control investment increases as the RNSPS become
more stringent, the increased investment is a small fraction of total utility
investment. Thus, for example, national monthly electricity bills will increase
only from two to five percent across RNSPS.
58
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Table 3-4
Foil and Partial Scrubbing vs. Current NSPS: Percentage Changes in Regional
SO2 Emissions and Total Utility Costs in 1995
Cn
0.2 Ib Floorb 0.6 Ib Uniform Ceilingc 0.5 Ib Ceilingd
(Full Scrubbing) (Partial Scrubbing) (Partial Scru)>bing)
Census SO- Emission Cost SO- Fmission Cost SO2 Fmission Cost
Regions Reaction (%) Increase (%) Ratio Reduction (%) Increase (%) Ratio Reaction (%) Increase (%) Ratio
Nation
Northeast*
Southeast'
North Central9
West South
Central
Mountain
Pacific
19.1
15.2
14.9
13.5
39.1
70.0
49.4
a These results reflect tlio
b l.2lbSO2/IO*rjtu
Uniform ceiling: 0
2.8 6.8 15.5 2.3 6.7 23.6 3.2 7.0
1.0 15.2 16.7 1.0 16.7. 27.2 1.0 22.2
2.3 6.5 12.5 2.0 6.3 17.7 1.0 17.7
3.0 '1.5 9.8 7.6 3.8 17.8 3.5 5.1
4.0 9.8 32.6 2.7 17.1 '|6.5 4.9 9.5
5.8 3. 'i 77.3 3.3 6.8 22.3 6.3 3.5
'1.6 10.7 10.9 3.6 3.0 55.5 4.9 11.3
lower (T VA)F CD costs.
daily ceiling with exemptions; 90 percent removal with specified 2'l-hour floor.
.6 Ih SO-/IO ntu annual ceiling, 33 percent minimum SO- removal requirement.
/ L
C New Fngland and Middle Atlantic Census Region states.
South Atlantic and Fast South Central Census Region stales.
q Fast North Central ami West North Central Census Region stales.
-------
Figure 3-2
Regional SO2 Emissions (10* Tons), 1995
Lower FGD Costs
o\
o
Current NSPS
10.6 Uniform Ceiling,
33% Removal
0.5 Uniform Celling,
90% Removal
0.2 Floor, 1.2 Celling
-------
Figure 3-3
National Percentage Increase in Total Utility Cost and Percentage Decrease
in SO, Emissions for Revised NSPS, 1995
Lower FGD Costs
S02 Reduction
Increase in Total Utility Costs
26-1
0.6 Uniform Ceiling,
33% Removal
0.6 Uniform Ceiling,
90% Removal
0.2 Floor. 1.2 Ceiling
-------
Figure 3-4
Comparison of National Pollution Control Investment
and Total Cumulative Investment, 1983-2000
(Billions 1975$)
Lower FGD Costs
7001
H
Total Investment
Pollution Control Investment
628.4
635.6
633.7
612.3
600-
500-
£ 4«H
*
M
i
J 300-
200-
100-
47.5
63.8
61.8
Currant NSPS 0.6 Uniform Calling, 0.6 Uniform Catling, 0.2 Floor.
33% Ramoval 80% Removal 1.2 Calling
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Table 3-5
Compcrisan of Cumulative Pollution Control Investment, FGD Capacity,
and Total Coal Capacity
Higher FGD Costs
FGD Capacity
in 2000 (GW)C
Net Coal Capability4
in 2000 (GW)
Current NSPS 0.6 Uniform
Baseline Ceiling 0.'6 Floor 0.2 Floor
Pollution Control
Investment (1983-2000)°
40.1
+27.4
(68%)b
+28.9
(72%)b
+41.7
(I04%)b
194
630
423
629
459
628
510
628
a
b
c
d
Billions of 1975 dollars.
Percentage change from baseline.
Assumes wet scrubbing technologies only.
Reflects penalties due to pollution control devices.
63
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Table 3-6
Comparison of Cumulative Pollution Control Investment, FGD Capacity,
and Total Coal Capacity
Lower FGD Costs
Current NSPS 0.6 Uniform 0.5 Ceiling
Baseline Ceiling 0.2 Floor 90% Removal
Pollution Control
i_..A»4..~_4. /looo on
An\a
33.9
+ 13.6
//n\b
+ 17.9
/c-^b
+ 19.9
/co\b
FGD Capacity
in 2000 (GW)C
Net Coal Capability0
in 2000 (GW)
295.0
632
452
631
505
632
530
631
a
b
c
d
Bill ions of 1975 dollars.
Percentage change from baseline.
Assumes wet scrubbing technologies only.
Reflects penalties due to pollution control devices.
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e. HOW DO THE ALTERNATIVE RNSPS DIFFER IN THEIR IMPACTS ON
PRIMARY RESOURCE CONSUMPTION AND SOLID WASTE GENERATION?
For resource consumption, the major impacts presented here are utility fossil-
fuel consumption (both for electricity generation and in-plant use), consumption
of fuel for transporting coal, and water consumption for cooling and FGD use.
The major solid wastes produced by coal-fired power plants are coal ash and FGD
scrubber sludge.
The impacts of primary resource consumption and solid waste generation are felt
locally, and we have calculated these impacts for each power plant, located by
county. Here, however, we present only national impacts for the year 1995.
rossil fuel consumption. In 1995, total utility fossil-fuel
consumption increases with more stringent standards. For
example, total consumption increases from 27.8 quads
under the current NSPS to 28.4 quads under a full scrub-
bing option with a 0.2 Ib floor. The increase is due
principally to increased coal requirements (24.3 to
25.1 quads) for scrubber operations. Utility oil consump-
tion in 1995 will be about 3.1 quads and does not change
appreciably in a specific year as a result of ~cn"anges in
RNSPS. Because oil is always more expensive than coal,
the dispatching of oil plants does not change significantly
across RNSPS. Changes in oil consumption over time
arise principally from retirements of oil plants. These
retirements are projected in the USM. Oil capacity over
time is illustrated in Appendix H, and oil consumption is
indicated in Appendix F.
Existing oil plants are accounted for in the utility rate
base, and fuel cost increases are often passed directly
through to consumers. So long as oil is available in 1995,
we believe that utilities will maintain any remaining oil
plants rather than license and site additional coal capac-
ity and seek rate increases from public utility commis-
sions. Further, these existing oil plants may be located in
urban areas where coal storage is not feasible; and they
may be strategically located in the transmission grid so
that early replacement is not desirable.
Because of the costs of oil, these plants will be used for
cycling rather than baseload generation. In the 1990s,
reserve margins will average about 20 percent rather than
keep to today's level, which can exceed 30 percent. This
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will further discourage the early retirement of reliable oil
plants. (It should be noted that utility oil capacity and
consumption are forecast in the USM to decrease
substantially after 1986. The issue in question here is
whether or not different RNSPS alone will induce signifi-
cant changes in the oil retirement rate.)
Another factor should also be considered. If the future
reliability of FGO scrubbers proves to be lower than
anticipated and if this substantially reduces the availabil-
ity of coal plants, it is possible that oil plants might be
retired less rapidly under more stringent RNSPS. How-
ever, by 1995 under such a circumstance, utilities would
probably build a slightly greater number of nuclear plants
rather than retire oil plants differentially in response to
more stringent RNSPS. In addition, experience should
enhance future scrubber reliability. If the RNSPS induced
the adoption of more nuclear capacity, oil consumption
(as well as SO2 emissions) could decrease.
All these factors militate against retiring oil steam plants
simply on the basis of future oil prices. Plant-retirement
criteria in the Utility Simulation Model are based on
announced retirements, government policies mandating
retirements (e.g., gas steam), and generating-unit age
based on individual generating-unit data and the historical
and announced ages of retired plants through 1987. Since
economic criteria alone do not govern capacity expansion,
significant changes in oil consumption are not projected in
response to the cost increases imposed by RNSPS. It
should be noted that all gas steam capacity is expected to
be retired by 1992, and its retirement rate can affect
regional coal capacity, emissions, and costs.
Diesel fuel consumed in 1995 in transporting coal by rail
varies by scenario from 0.23 quads to 0.35 quads. It is
highest under the current NSPS and under the 0.6 Ib floor,
where more western coal is shipped east. Fossil fuel
consumption was illustrated earlier in Figure 2-12.
Utility water consumption. Utility water consumption for
cooling water increases across RNSPS in 1995 from about
4.9 x 10 acre-feet in the current NSPS case to 5.1 x I0b
acre-feet in the 0.2 Ib floor case. In comparison, FGD
water consumption varies directly with FGD use, from
about 0.22 x 10 acre-feet in the current NSPS case to
0.48 x 10° acre-feet under the full scrubbing option. Note
that an increase of I.I percent per year in electricity
demand between 1976 and 1995 increases cooling water
consumption to about 6.1 x 10 acre-feet by 1995. This
66
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change in overall water consumption due to a different
rate of growth in electricity demand exceeds any change
expected from FGD usage. FGD water consumption
impacts, however, will depend significantly on power-
plant location. Utility water consumption is shown in
Figure 2-13. These calculations do not assume the use
of dry scrubbing technologies, which should lead to lower
projected water consumption levels.
Solid waste production. Utility scrubber sludge produc-
tion in 1995 varies from 15 x 10 tons of sludge (dry basis)
under the current NSPS to 51 x 10 tons of sludge under
full scrubbing. (These projections are based on the higher
FGD cost estimates. Under the lower FGD cost, esti-
mates, the amounts of sludge vary from 39.5 x 10 tons
under the current NSPS to 57.7 x 10 tons under a 0.2 Ib
floor.) Total coal ash for disposal is projected to be
88 x I0b tons under the current NSPS and 100 x I06 tons
under the 0.2 Ib floor. Thus, the volumes of sludge
produced are of the same order of magnitude as the
volumes of coal ash. The costs of sludge disposal are
accounted for in our FGD cost models. Whether or not
disposal problems are encountered will depend on the
specific location of the power plant. Utility production of
solid wastes is illustrated in Figure 2-5.
f. HOW ARE UTILITY COAL PRODUCTION AND CONSUMPTION INFLU-
ENCED BY THE SO2 STANDARD AND BY DIFFERENT ESTIMATES OF FGD
COSTS?
An alternative revised NSPS for S02, when set on a national basis, can affect
regional utility coal production and consumption patterns significantly. It can
also affect total required national coal production, primarily because of the
differences in heating values of coals across regions. Assuming the higher cost
estimates for scrubbers, Tables E-1 through E-3 (Appendix E) and Figure 2-14
show regional utility coal production in 1985, 1990, and 1995 under different S02
standards: the current NSPS, a 0.6 Ib SO7/I06 Btu floor, a 0.2 Ib S0,/I06 Btu
6
floor, and a 0.6 Ib S02/IO Btu ceiling. A summary of regional growth rates
appears in Table E-4. Likewise, for the lower scrubber cost estimates, regional
utility coal production for the different S02 standards is shown in Tables E-5
through E-7 and in Figure 2-15. A summary of nominal regional growth rates
using the lower scrubber costs appears in Table E-8.
67
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Current N5PS. Using the higher scrubber cost estimates,
projected utility coal production under the current NSPS
increases from approximately 740 million tons in 1985 to
1,250 million tons in 1995. This is an increase of 510 mil-
lion tons over ten years. Coal production in the Northern
Great Plains is projected to increase by the greatest
amount, from 210 million tons in 1985 to approximately
520 million tons in 1995. For the same ten-year period
under the current NSPS, Gulf Coast lignite production is
projected not to change substantially, while midwestern
coal mining for utilities is projected to remain relatively
constant, decreasing slightly over time.
The lower scrubber cost estimates measurably enhance
the competitive position of local coal. The rate of
increase of western coal shipments east of the Mississippi
drops from 7.7 percent per year to 2.2 percent per year
when scrubber costs are lowered to the TVA estimates.
(See Tables E-4 through E-8 in Appendix E). Likewise,
the rate of increase of Gulf Coast coal use increases
sharply, while shipments of coal from the Northern Great
Plains area (Powder River Basin) do not increase.
0.6 Ib floor (1.2 Ib ceiling, 85 percent removal). Under
the higher scrubber cost estimates, tor a national 24-hour
S02 standard with a 0.6 Ib SCWIO Btu floor, projected
utifity coal production increases from 740 million tons in
1985 to 1,270 million tons in 1995. This is an increase of
530 million tons over ten years. Coal production in the
Northern Great Plains is projected to increase by the
greatest amount, from 210 to 480 million tons per year
(45 million tons less than under the current NSPS). Appa-
lachian coal production for utilities increases more than
under the current NSPS, to 460 million tons in 1995. This
reflects the increased use of local coal. This effect is
also evident for Gulf Coast lignite and coal from other
areas - primarily at the expense of growth in Northern
Great Plains coal production. Lower FGD costs were not
applied to an examination of this standard.
0.2 Ib floor - the full scrubbing option. Under the higher
scrubber cost,estimates, for a national 24-hour floor of
0.2 Ib S02/I0 Btu (1.2 Ib ceiling, 85 percent 24-hour S02
removal), projected utility coal production increases from
740 million tons in 1985 to 1,310 million tons in 1995. The
use of local coals coals from Appalachia, the Gulf
Coast, and other areas increases significantly as com-
pared with local coal use under the current NSPS. Appa-
lachian utility coal production is projected to increase by
200 million tons. Gulf Coast lignite mining increases
-------
substantially, and much of this growth is projected to
occur between 1985 and 1990 as natural gas is phased out
as a boiler fuel.
Lower scrubber cost estimates greatly enhance the posi-
tion of local coals under the full scrubbing option. Pro-
duction of midwestern coal for electric utilities increases
between 1985 and 1995, whereas under other scenarios it
remains level or decreases over time. Also, western coal
shipments east of the Mississippi may decline, whereas
they increase for other scenarios.
0.6 Ib uniform annual ceiling. For both the lower and
higher sets of FGD cost estimates, this represents a
"middle" scenario between the current NSPS and a full
scrubbing option. Compared with the latter two stan-
dards, assuming either the higher or lower FGD costs, the
0.6 Ib ceiling enhances the position of local coal by
allowing partial scrubbing of intermediate-sulfur coals.
Utility movements of western coal. Western coal shipped
to utilities east of the Mississippi River will be signifi-
cantly affected by the level of the national SO, standard
and scrubber costs, as shown in Figures 2-16 ana 2-17.
Under the higher scrubber cost estimates and the current
NSPS, shipments of low-sulfur western coal to utilities
east of the Mississippi (predominantly to the Midwest)
increase from 110 million tons in 1985 to 240 million tons
in 1995. A similar growth pattern is observed for a 0.6 Ib
SO, floor. However, for a 0.2 Ib floor and for the 0.6 Ib
uniform ceiling, the eastern markets for western coals do
not grow substantially: shipments of western coal reach
only 80 million tons in 1990 and 93 million tons in 1995
under the full scrubbing option; and under the 0.6 Ib
uniform ceiling they reach only 136 million tons in 1995.
These patterns change markedly when .the lower scrubber
cost estimates are used. Under the current NSPS,^assum-
ing the lower estimates, eastern utility consumption of
low-sulfur western coal grows by only 2.2 percent per
year (compared with a growth of 7.7 percent per year
using the higher scrubber cost estimates). Under a 0.6 Ib
uniform annual ceiling, the rate of increase is only
1.3 percent per year; while under full scrubbing the
eastern market for western coal may even decline.
69
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The foregoing results ore summarized as follows:
Total national utility coal production is projected to
increase as a result of the tightening of SO2 emission
standards. Under the current NSPS, national utility coal
consumption is projected to grow at an average annual
rate of 5.3 percent between 1985 and 1995. This growth
rate is projected to increase to 5.4 percent under a 0.6 Ib
standard, and to 5.8 percent under a 0.2 Ib standard.
The use of low-sulfur coal in power plants east of the
Mississippi is greatest under the current NSPS. It de-
creases under a 0.6 Ib uniform ceiling option and further
under a full scrubbing option.
If lower scrubber costs are used, the position of local coal
is greatly enhanced while long-distance shipments are
curtailed. The largest differences between the higher and
lower FGD cost estimates appear in the projections for
the use of low-sulfur coal east of the Mississippi:
- Under the current NSPS, western coal shipments
eastward increase by 7.7 percent per year using the
higher FGD cost estimates but only by 2.2 percent
per year using the lower FGD costs.
- Under the full scrubbing standard, western coal
shipments eastward increase by 1.6 percent per year
using the higher FGD cost estimates but may even
decline using the lower costs.
Coal production in all regions of the U.S. will be greater
under all RNSPS than 1978 regional production levels.
II. WHAT ARE THE DIFFERENCES BETWEEN THE
PROJECTED IMPACTS OF THE FULL AND PARTIAL
SCRUBBING ALTERNATIVES?
a. WHAT ARE THE COST AND EMISSION DIFFERENCES BETWEEN THE
VARIOUS FULL AND PARTIAL SCRUBBING OPTIONS?
Using the higher (PEDCo) scrubber cost estimates, neither this nor other studies
show significant cost or emission differences L/etween the full and partial
scrubbing options based on a 24-hour averaging time (0.2 ,b '!oor arid 0.6 Ib
70
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floor). Differences do occur for the 0.6 Ib uniform ceiling option (which is an
annual form of the RNSPS), as noted above.
Why are the differences between the 0.2 Ib floor and 0.6 Ib floor options not
larger? One major reason is that the RNSPS principally affect coal-fired
capacity. While coal-fired capacity accounts for a major fraction of the total
projected national generating capacity and steadily increases over time, noncoal
capacity still represents approximately one-half of the total projected capacity
and slightly less than one-half of the electricity projected to be generated by the
year 2000. (See Appendix H.) Thus, even if the costs of generating electricity
from RNSPS coal plants were to increase very rapidly, the overall cost
difference across scenarios would be moderated by the costs associated with
noncoal plants.
However, there ore several reasons why the differences between the 0.2 Ib floor
and 0.6 Ib floor standards are not larger within the coal-fired plant category
itself. The calculated differences in cost between alternative RNSPS are
determined primarily by three elements: the design, cost, and operating
characteristics of FGD scrubbers; the form of the revised standard; and the coal
burned. A number of assumptions, including the relative standard deviation
(RSD) assumed for coal sulfur variability (24-hour RSD = 0.15 for uncleaned
coals), have served to reduce the observed cost and emission differentials
between these two very similar 24-hour $©2 standards. In practice, if different
assumptions proved true, the actual differentials could be greater.
Several key factors embedded in the analyses have influenced the estimated
pollution control costs and reduced the cost differentials between these two
options.
Compliance calculations and scrubber sizes are based on
the "worst case" situation. That is, the assumed design of
the FGD scrubber system is such that compliance is
maintained on days when the 24-hour average coal sulfur
content is 1.3 times the long-term average coal sulfur
content (and at least 1.45 times the long-term average
content in the "no exemptions" cases).
In cases where the SO, emission floor controls (that is,
where the percentage SOU removal can be less than the
prescribed 85 percent daily removal), it has been assumed
71
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that the SCX emission level will never exceed the floor.
Thus, the average coal sulfur content must produce emis-
sions below the floor by an amount determined by the coal
sulfur RSD. If the assumed RSDs were smaller than 0.15,
as they probably are for cleaned coals and for larger lot
sizes, emission levels under 24-hour or 30-day partial
scrubbing options would be higher.
FGD systems are assumed to be designed with "fixed
bypass," that is, with a constant SCU removal efficiency
achieved through bypassing a fixed percentage of the flue
gas stream around the scrubber. In general, bypassing a
portion of the flue gas results in capital cost savings,
because smaller FGD systems are required. Operating
costs are lower because less SO, is removed. The fixed
bypass conditions are determined oy the required emission
level, the coal to be burned, and the emission standard.
For days when incoming coal sulfur is below the long-term
average level, resulting in 24-hour emissions below the
emissions floor (which is never to be exceeded), no
allowance was mode for variable bypass (which would
increase emissions up to the floor). Had variable bypass
been assumed, the emission levels projected for plants
subject to the floor would have been higher by a factor of
about 1.5. As Figure 2-18 shows, variable bypass is not
cost effective, since emissions increase more rapidly tfian
cost savings, especially for low-sulfur coals. If variable
bypass were allowed, utilities would emit at the level of
the specified standard, not below it. (Tn this study's
analysis of annual standards where an annual average
ceiling controls, annual emissions are at the level of the
ceiling; that is, the annual RSD is zero.)
b. HOW DOES THE FORM OF THE REVISED STANDARD INFLUENCE THE
COSTS OF POLLUTION CONTROLS?
The form and technical requirements of any given standard have numerous
implications for pollution control costs. Many of these implications are
presented in detail in a set of graphs that appears in Appendix C. The sensitivity
studies discussed in the following sections address this question for various coals.
The general conclusions are as follows:
For the same annual emission level, an annual average
standard compared with a 24-hour standard permits
72
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greater FGD gas bypass for a given coal and results in
lower energy penalties. As noted above, all standards
were evaluated assuming a constant SO, removal effi-
ciency, i.e., fixed bypass. (The possibility of a utility
emitting at low levels and then completely bypassing the
FGD system for the rest of the year to meet an annual
average emission limit was precluded by the fixed-bypass
assumption.) Nevertheless, short-term emissions resulting
from coal sulfur variability may be higher than the annual
average. This likelihood and the diurnal nature of adverse
air pollution episodes indicate the need for setting appro-
priate 24-hour standards in conjunction with any longer-
term standards.
To achieve the same annual emission level for a given
coal, an annual average or 30-day S0~ standard compared
with the equivalent 24-hour average standard will permit
lower costs per kilowatt-hour of electricity produced.
As indicated earlier, variable bypass on FGD scrubbers is
less cost effective than fixed bypass for emission control.
(See Figure 2-18.)
For the 24-hour standards, given the specified assump-
tions regarding scrubber design and performance, there is
very little difference in annual emissions between the
"without exemptions" and "with exemptions" cases (the
latter being those cases in which the mandatory 85 per-
cent removal is allowed to drop to 75 percent three days
per month). Since the three-day-per-month exemption
should permit greater flexibility in utility operations, it
appears to be an effective element of a 24-hour standard.
HOW WILL UTILITY COAL CHOICES IN KEY STATES BE AFFECTED BY
DIFFERENT S02 EMISSION STANDARDS AND
UNCERTAINTIES IN KEY FACTORS?
a. WHAT ESTIMATES CAN BE MADE REGARDING THE TYPICAL UTILITY
COSTS OF BUYING, TRANSPORTING, AND BURNING DIFFERENT COALS,
AND OF REQUIRED POLLUTION CONTROLS, AS A FUNCTION OF THE SO2
STANDARD?
For a series of 24-hour and annual average S02 standards of between 0.2 and
1.2 Ib S02/I06 Btu, the level!zed fuel-cycle cost has been calculated for 500 MW
coal-fired power plants coming on line after 1982 (see Appendixes B and C). For
73
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each state, a power-plant location has been selected near a key city for which a
change in 502 stanc'arc' maX critically influence the chosen source of coal supply
and therefore the resulting emissions. Swing states - those most sensitive to
changes in fuel and pollution control costs and therefore subjected to the in-
depth analyses reported herein include Ohio, Indiana, Florida, and Texas.
Results for Ohio are discussed in the text; results for the other states are
included in Appendix C. These analyses show that:
For power plants located in eastern and midwestern
states, reducing the level of the 24-hour $©2 floor in-
creases the fuel-cycle cost of western coals compared
with that of eastern (local) coals. Generally for most
states, gat some level of floor or ceiling below 1.2 Ib
SO2/IO Btu, an eastern (local) coal becomes the most
ecghomical choice on the basis of levelized cost per
10 Btu of coal burned; this measure of cost is pro-
portional to the cost per kilowatt-hour of electricity
generated. (See Appendix B.) In this study, estimates
were made of "crossover points," that is, of S02 floors
above which partially scrubbed western coals will be
cheaper to use than higher-sulfur eastern coals, which
require a greater degree of scrubbing. For standards in
the "crossover" range, the responses of utilities in each
state are subject to greater uncertainty.
Levelized fuel-cycle costs per kilowatt-hour for typical
(low-sulfur) western coals may increase by as much as
24 percent over the range of 24-hour S02 floors and over
the rarge of annual ceilings of between 1.2 and 0.2 Ib
SO2/IO Btu. However, for typical (higher-sulfur) eastern
coals, fuel-cycle costs either remain constant (since
nearly "full scrubbing" will be required for all floors or
ceilings) or increase by not more than approximately
10 percent over the range of standards analyzed.
Figure 3-5 illustrates the levelized cost per million Btu of
scrubbing various coals. Figures 3-6 and 3-7 illustrate
estimated variations in fuel-cycle costs for power plants
near Columbus, Ohio; additional figures for other key
states are presented in Appendix C. The coals illustrated
in Figures 3-6 and 3-7 were selected from a list of over
30 candidate coals on the basis of their comparatively low
fuel-cycle costs near Columbus, Ohio.
Emissions from coal-fired power plants will not exceed a
specified 24-hour S02 floor (if the floor controls) and may
be less than the floor depending on additional speci-
fications. The additional specifications include coal sul-
fur RSD (relative standard deviation - see Glossary). The
74
-------
Figure 3-5
Comparison of FGD Cost Effactivanass par Btu of Fual Input
undar Annual Avaraga SO} Control Altarnativas
160-1
0)
o
u
§
§
140-
120-
100-
80-
60-
40-
20"
T-
0
(Bituminous Coal
Subbltuminous Coal
0.6
0.8
0.2 0.4
24.HOUR AVERAGE 8O, FLOOR (LB »O,/10* BTU)
1.0
75
-------
Figure 3-6
Sensitivity of Levelized Fuel-Cycle Coet to
24-Hour SO, Floor
(Columbus, Ohio)
400-
350-
300-
250-
-Powder River coal
0.5% sulfur, 6.0% ash, 8,100 Btu/lb
Northern Appalachian coal
2.6% sulfur, 9.9% ash, 12,000 Btu/lb
(0.12)
(0.22)
(CM3) (0.43) (0.43)
(0.62)
T
2 0.4 0.6 0.8 1.0
24-HOUR AVERAGE BO, FLOOR (LB 80,/10* BTU)
1.2
A/or«. Calculations assuma a 1.2 Ib SO,/10* Btu calling with 85% removal (24-hour average
with exemptions of three days per month). ( ) = annual emissions (lbSO2/10« Btu).
76
-------
Figure 3-7
Sensitivity of Levelized Fuel-Cycle Cost to
Annual SO, Ceiling
(Columbus, Ohio)
400-1
3 350-
0)
&
o
I
2
S 300-
s
2
250-
1 Powd*r River coal
0.5% sulfur, 6.0% ash, 8,100 Btu/lb
Northern Appalachian coal
2.6% sulfur, 9.9% ash, 12,000 Btu/lb
> ^
0.2
I
0.4
I
0.6
I
0.8
I
1.0
ANNUAL 8Oa CEILING (LB S0,/10« BTU)
Note: Calculations assume no mandatory parcantage removal requirement.
77
-------
higher the assumed RSD, the lower the average emissions
will be in order never to exceed the floor.
Emissions from coal-fired power plants subject to an
annual SC^ ceiling with no mandatory percentage removal
are identical for all coals. (For annual standards, the coal
sulfur RSD = 0.)
An analysis of the levelized fuel-cycle cost of the "least-
cost" western coal compared with the "least-cost" local
(eastern) coal in a number of swing states shows that the
relative differences in costs do not exceed approximately
+ 15 percent over a range of SO2 standards of between 1.2
and 0.2 Ib S02/I0 Btu (see figures in the text and Appen-
dix C). This range of relative differences indicates that
other variable factors leading to cost changes will influ-
ence coal and pollution control choices.
b. WHAT IS THE SENSITIVITY OF FUEL-CYCLE COSTS TO COAL MINE
PRICES?
Sensitivity studies have been performed by varying the f.o.b. coal mine price
within a reasonable range for several key states. Levelized fuel-cycle costs have
been estimated for percentage changes in coal mine prices and for a series of 24-
hour S02 standards of between 0.2 and 1.2 Ib SO2/IO Btu. We conclude that:
The sensitivity of the fuel-cycle cost per kilowatt-hour to
f.o.b. coal mine price is proportional to the relative
magnitude of the cost of mining compared with the sum
of transportation, coal cleaning, and pollution control
costs. Mine-mouth plants exhibit the greatest degree of
sensitivity; conversely, the fuel-cycle cost for long-dis-
tance coal shipments is relatively less sensitive to
changes in coal-mining cost.
A small change in local coal mine price for example,
+ 10 percent - may dramatically change the economic
advantage of competitive coals subject to the same S02
standard. (See Figure 3-8 for Ohio and Appendix C for
other key states.)
78
-------
Figure 3-8
Sensitivity of Levelized Fuel-Cycle Cost to 24-Hour SO2 Floor
and F.O.B. Coal Mine Prices
(Columbus, Ohio)
400-1
CD
&
CO
O
O
u
O
u
ik
O
u
Ul
U
300-
"~- Powder River coal
0.5% sulfur, 6.0% ash, 8,100 Btu/lb
Northern Appalachian coal
2.6% sulfur, 9.9% ash, 12,000 Btu/lb
F.O.B. Coal Prices (S/ton)
$1978 +10% -10%
250-
T
0
PR
NA
0.2
6.75
23.00
7.43
25.30
o!«
6.08
20.70
0.6
o!8
1.0
1
1.2
24-HOUR AVERAGE SO, FLOOR (LB 5Ot/10* BTU)
Nott: Calculations assume a 1.2 Ib SO2/10< Btu ceiling with 85% removal (24-hour average
with exemptions of three days per month). Transportation rates: rail < 250 miles,
2.25C/ton-mlle; > 250 miles, 1.20C/ton-mlle; water 0.5C/ton-mile.
79
-------
Western cool becomes increasingly competitive as coal
mine prices uniformly increase for any specified S0~
standard. (Thus, inflationary trends in coal mining tend to
favor the use of western coal in the Midwest.)
Since local coals are favored at more stringent standards,
and since increases in coal mine prices have a greater
relative impact on fuel-cycle costs for local coals, overall
costs become more sensitive to coal-mining costs as the
502 s*anc'ard becomes more stringent. In the key states
analyzed, at floors below approximately 0.6 Ib SCW
10 Btu, changes in coal mine prices of approximately
+ 10 percent tend to change the least-cost coal, usually
Trom western to local coals (see Figure 3-8 and
Appendix C).
c. WHAT IS THE SENSITIVITY OF FUEL-CYCLE COSTS TO COAL TRANS-
PORTATION COSTS?
In order to examine the effects on utility coal choices of changes in transporta-
tion costs in conjunction with the 502 standard, transportation rates have been
varied within currently experienced limits using applied cost escalation factors
agreed upon by the joint EPA/DOE working group. Levelized fuel-cycle costs
have been estimated for key cities for percentage changes in rail and barge rates
over a series of 24-hour SO2 floors of between 0.2 and 1.2 Ib S02/I0 Btu. The
generalized results that follow apply to all the states examined, except where
noted.
Uniformly escalating rail and barge rates tend economi-
cally to favor local coals - at any SO^ standard - because
transportation costs represent a relatively smaller propor-
tion of the total fuel-cycle cost of local coals. (See
Figure 3-9 for Ohio, and Appendix C for other states.)
Changes in transportation rates have their greatest im-
pact at higher levels of the 24-hour S02 floors or ceilings.
(We note above that the levelized fuel-cycle cost of local
coals is/generally unaffected by a floor below about 0.6 Ib
S02/I0 Btu.)* That is, the least-cost fuel choice is
For a 24-hour standard requiring a ceiling of 1.2 Ib SO,/10* Btu and 85 per-
cent removal. The results are also unaffected by annual standards with a
uniform celling below about 0.5 Ib SOj/IO6 Btu.
80
-------
Figure 3-9
Sensitivity of Levelizod Fuel-Cycle Cost to 24-Hour SO, Floor
and Transportation Rate
(Columbus, Ohio)
400-1
JL 350-
8
I
I
i
a
250-
Powdtr River coal
0.5% sulfur, 6.0% ash, 8,100 Btu/lb
Northern Appalachian coat
2.6% sulfur, 9.9% ash, 12,000 Btu/lb
$1970
Rale ft/ton-mlle)
Ball (mllet)
<280 >2SO
Water
A 200
B 2.25
C 2.50
1.00
1.10
1.20
(all dWanc«»)
0.4
O.S
0.6
.L, **« Only
0
T
0.4
I
0.6
I
0.8
l
1.0
I
1.2
24-HOUR AVERAGE SO, FLOOR (LB SOt/10* BTU)
Not*: Calculations assume a 1.2 Ib 8O2/10« Btu celling with 85% removal (24-hour average
with exemptions of three days per month).
81
-------
relatively insensitive to the transportation rate at levels
of the 24-hour 502 *'oor ^^ require nearly full scrub-
bing.
However, for several states, the location of the power
plant in terms of accessibility to coal delivery by either
rail or water is the determining factor in choosing the
least-cost coal supply. In these cases, the choice of the
most economical coal may be nearly independent of the
S02 emission standard. For example, if a power plant in
Tennessee has direct access only by rail, it will economi-
cally utilize local coals. A power plant near Nashville, on
the other hand, which has direct rail and water access,
may find both Appalachian and western coals competitive,
depending on the standard.
d. WHAT IS THE SENSITIVITY OF FUEL-CYCLE COSTS TO WESTERN COAL
CHARACTERISTICS?
The sensitivity of levelized fuel-cycle costs to both the sulfur content and
heating value of western coal is significant.
For all western coals, the fuel-cycle cost per million Btu may exceed, equal, or
fall below the cost of "local" eastern coal in swing states. This wide variation as
a function of the level of the 24-hour SO2 floor is illustrated in Figure 3-10.
One particularly important western coal is that available from the Powder River
Basin. The sulfur and Btu contents of Powder River Basin coal are important in
determining the amounts of western coal to be shipped east of the Mississippi.
Powder River coal is the key western supply source that may be able to comply
with current NSPS standards or be partially scrubbed to meet the RNSPS. It is
also usually the most economical choice among other western coals per delivered
Btu. For these two reasons, the sensitivity of levelized fuel-cycle costs to the
sulfur and Btu content of this coal, for various $©2 standards, was specifically
analyzed. To the extent that Powder River coal is the economical choice, lower
emissions may result from its use.
82
-------
Figure 3-10
Sensitivity of Level ized Fuel-Cycle Coet to 24-Hour SO, Floor
and Powder River Coal Characteristics
(Columbus, Ohio)
400-1
=> 350-
0
tt
O
u
u
w 300-
u.
O
ui
N
UI
250-
Powder River coal (PR)
- Northern Appalachian coal NA)
2.6% sulfur, 10% ash, 12,000 Btu/lb
% MiHur
Btu/lb
ID S/10* Blu
0.4
9,000
0.44
b
O.S
,000
O.S6
c
O.S
8.500
0.59
d
0.5
8,000
0.63
0.5
7.500
0.67
1 .
0.6
7,500
0.80
PR-f
PR-e
NA
PR-d
PR-c
PR-b
PR-a
i
0.4
i
1.0
0.2 0.4 0.6 0.8
24-HOUR AVERAGE SO, FLOOR (LB SO,/10* BTU)
I
1.2
A/or«/ Calculations assume a 1.2 Ib SO2/10* Btu calling with 85% removal (24-hour average
with exemptions of three days per month). Powder River $1978/ton = 6.75; Northern
Appalachian $1978/ton - 23.00.
83
-------
In Columbus, Ohio, Powder River coals of lower sulfur and higher Btu content
could be economically preferred over local coals for any level of 24-hour SO?
floor. However, Powder River coals of below a certain Btu value or above a
certain sulfur percentage could cost more than local coals for any level of 24-
hour 502 ^oor' The most probable Powder River Basin coal to be mined between
now and 1990 should be that with about 0.6 Ib S/IO Btu. (See Appendix D.) In
Ohio, this coal would be competitive with local coals.
Figure 3-10 illustrates the wide variation in costs possible for different composi-
tions of Powder River coals. In our national projections using the higher
scrubber costs, we show a significant variation in shipments of western coal east
of the Mississippi as the RNSPS become more stringent. However, as shown in
Figure 3-10, Powder River coals with more than 0.7 Ib S/IO Btu will be less
competitive in swing states.
e. WHAT IS THE SENSITIVITY OF COAL AND POLLUTION CONTROL
CHOICES TO DIFFERENT ENGINEERING ESTIMATES OF FGD COSTS?
For a typical coal-fired power plant, examination was made of the sensitivity of
the levelized fuel-cycle cost to the two independent sets of engineering FGD
cost estimates, PEDCo's and TVA's.* These analyses were for various wet
scrubbing technologies. The analysis of the final, promulgated RNSPS also
includes dry scrubbing. Figure 3-11 illustrates the variation as a function of the
RNSPS for a location near Columbus, Ohio. (The higher FGD cost estimates are
identical to those used for Figure 3-7 and the preceding sensitivity analyses.)
Comparison of the two sets of FGD cost estimates reveals that, for lime FGD
systems, TVA's capital costs are about 30 percent lower than PEDCO's, and
TVA's operating costs are about 20 percent lower. For limestone systems, TVA's
capital and operating costs are about 40 percent and 27 percent lower, respec-
tively, than PEDCo's.
Again, the engineering differences between the PEDCo and TVA estimates
are discussed briefly in Appendix A.
84
-------
Figure 3-11
Sensitivity of Lavslizsd Fuel-Cycle Cost to FGD Cost
(Columbus, Ohio)
400-1
350-
CO
O
5
2
§ 300-
250-
Powder River coal
Northern Appalachian coat
FGD Cost
Higher (PEDCo)
.... Lower (TVA)
PE!
(90)
TVA
T
0.4
0'.6
o's
1.0
I
1.2
ANNUAL SO, CEILING (LB 8O,/10* BTU)
Note: ( ) = percentage SO2 removal.
85
-------
The TVA costs appear to be less sensitive than PEDCo's to scrubber size, to the
gas flow measured in actual cubic feet per minute, and to SO2 removed per hour.
PEDCo's and TVA's estimates of FGD electricity consumption (and resulting
capacity penalty) are about the same, while TVA's estimate of reheat steam is
only about 20 percent of PEDCo's.
Since the TVA capital and operating costs are less sensitive to FGD size, and
since TVA's reheat steam is much less than PEDCo's, use of the TVA FGD cost
estimates results in smaller cost differentials between partial scrubbing and full
scrubbing. Use of TVA's lower estimates enhances the competitive position of
local, higher-sulfur coals and the relative attractiveness of scrubbing these
coals. The substantial effects on national impact projections have been
discussed previously.
As shown in Figure 3-11, the scrubber cost estimates used
can significantly affect a utility's choice of the most
economical coal supply - and hence the resultant SO2
emissions. Higher FGD cost estimates render Powder
River coal competitive with local Ohio coal for RNSPS
above an annual S02 ceiling of about 0.6 Ib SCWIO Btu.
However, with lower FGD cost estimates, local northern
Appalachian coal is economically preferred at every ceil-
ing below the current NSPS. The cost difference, using
the lower estimates, substantially increases the attrac-
tiveness of scrubbing coals of high and intermediate sulfur
content.
It should be noted from Figure 3-11 that, at an annual
ceiling of about 1.2 Ib SCWIO Btu, some Powder River
coals can be compliance coals and not require FGD. Thus,
the fuel-cycle costs under the higher and lower estimates
are nearly identical. At a ceiling of 0.2 Ib SCWIO Btu,
however, these coals are fully scrubbed at an annual S02
removal efficiency of about 90 percent. The cost varia-
tion in moving from partial to full scrubbing is substan-
tially less for the lower FGD cost estimates.
-------
As shown in the preceding discussion, this reduced cost variation under the lower
FGD cost estimates would lead to dramatically lower consumption of western
coals east of the Mississippi and to the increased utilization of local coals.
IV. HOW ACCURATE AND RELIABLE ARE MEASURES OF THE
COST EFFECTIVENESS OF VARIOUS STANDARDS?
Cost effectiveness is usually measured as the incremental benefit divided by the
incremental cost. Measures used most frequently in this type of analysis include
the cost required to generate a kilowatt-hour of electricity (also measured in
Btu's of fuel input) and/or the cost required to remove a ton of SO? ^rom tne
power-plant stack.
Any measure of cost effectiveness reflects the point of view of the decision
maker regarding the objective for which costs are incurred. In selecting
measures of cost effectiveness, it is important to distinguish between the cost
per ton of S02 removed and other measures, such as the cost per Btu of fuel
used. These two measures capture the differences between EPA's primary
objective of reducing air pollution and a utility's primary objective of generating
electricity as cheaply as possible. For purposes of selecting a revised New
Source Performance Standard, it is understood that meeting these two objectives
necessitates a trade-off between $©2 emission reductions and increased costs.
In other words, it is difficult to minimize simultaneously the cost of reducing air
pollution (cost per ton of SOj removed) and the cost of generating electricity
(cost per Btu of fuel). However, in some cases it may be possible to select a fuel
and pollution control option that minimizes the sum of these costs for options
available to a particular power plant.
The cost of FGD affects the cost of removing S02 from power-plant emissions as
well as the cost of producing a kilowatt-hour of electric power. The cost
effectiveness of FGD using these two distinct measures is illustrated in
Figures 3-5 and 3-12.
87
-------
Figure 3.12
Comparison of FGD Cost Eff*ctiv*n»M per Ton of
8O2 R«mov«d und*r Annual Avarag* SO2
Control Altarnativas
fc
I
1800-1
1600-
1400-
o
UJ
> 1200<
ui
ff
o
v>
O
1000-
800'
CO
O
O
O
o
u.
2
* 600
H!
3
400'
200-
Bituminous Coal
Subbituminous Coal
1.33 Ib S/10« Btu
2.17 Ib S/10« Btu
3.85 Ib S/10< Btu
0.2 0.4 0.6 0.8 1.0
ANNUAL AVERAGE SO, LIMIT (LB SO,/10« BTl>\
-------
A comparison of FGD cost effectiveness per 10° Btu of coal burned (Figure 3-5)
shows that FGD costs can be minimized for a given standard by using the coal
with the lowest sulfur content per I06 Btu. The cost of FGD per I06 Btu can be
reduced to a minimum by allowing the SOj emission standard to increase toward
uncontrolled levels. This is, of course, the measure which is directly related to
the cost of generating each kilowatt-hour of electricity.
In contrast, a comparison of FGD cost effectiveness per ton of SCK removed
(Figure 3-12) shows that FGD costs are lower per ton of S00 removed for fuels
£
with the highest sulfur content per 10 Btu. The cost of FGD per ton of SG>2
removed can be reduced to a minimum by allowing the SC^ emission standard to
be lowered toward the most stringent levels. This measure is indirectly related
to the cost of electricity but may be informative as to the cost effectiveness of
any particular standard.
It is incumbent to ask, "How well can we determine the cost effectiveness per
ton of S(>2 removed?" and "Does this measure add any new knowledge or give us
the capability to distinguish between similar RNSPS?" As will be shown,
calculations of the marginal cost per ton of SC^ removed are subject to
considerable uncertainty. Relying on this measure when comparing similar
alternative standards (as has been done by both opponents and proponents of
various standards) is simplistic in that it ignores the difficulties and variations
associated with the calculation. Aggregating the measure can also wash out
significant regional and local cost differences. We illustrate the difficulties by
referring to Figure 3-13 for an individual power plant subject to an annual SOj
standard. The difficulties are increased for 24-hour standards.
As shown, the cost per ton of SC^ emitted increases rapidly as the emission
standard becomes more stringent (that is, as SC^ emissions decrease). The
marginal cost per ton of SO- removed for a particular standard ideally measures
the slope of the tangent to the curves in Figure 3-13; tons removed are usually
calculated from the differences in emissions projected under two different
standards. In practice, the value claimed for the marginal cost is actually an
"incremental" cost per ton of SC>2 removed, calculated from differences in
89
-------
Figure 3-13
Lavalizad Fual-Cycla Costa par Pound of SO2 Eminad
aa a Function of Annual SO2 Limit
(Illinois)
1800-1
1800'
g- 1400-
ui
ui
O
CO
a
Inttrior Eastern coal
2.7% sulfur
10.85% ash
10,850 Btu/lb
1200-
fc
O
o
o
§
ui
UL
s
N
Ul
Ul
1000-
800.
600-
400-
200-
Central Appalachian coal
1.08% sulfur
17% ash
11,200 Btu/lb
, Northern Appalachian coal
1.0% sulfur
17.2% ash
11,200 Btu/lb
Central Western coal
0.5% sulfur
6.07% ash .
11,000 Btu/lb
Powder River coal
0.5% sulfur
6% ash
8,100 Btu/lb
0.2
i
0.4
T
0.6
i
0.8
i
1.0
i
1.2
ANNUAL SOj LIMIT (LB SCylO* BTU)
90
-------
emissions and costs using point estimates which do not provide good measures
of the tangent. For example, consider the calculation of cost per ton removed
by comparing emissions and costs under standards of 1.2, 0.6, and 0.2. Taking
differences in emissions and costs at these discrete points cannot measure the
true marginal costs accurately. Further, these differences are subject to
considerable uncertainty and geographic variation. Because of the changing
slope of the curve, calculated values can change significantly with small changes
in the estimated locations of points along the curve. Indeed, each curve in
Figure 3-13 is subject to uncertainty (it may be shifted right or left and up or
down), and this would be the case for any particular power plant. Moreover,
utility system operations (for example, whether or not the plant is baseloaded)
will also influence the final shape of the curve. With aggregation of the results
using a number of new power plants in different utility systems, the range of
uncertainty increases and each point becomes a range of values. Taking
differences at points for widely different standards does not measure marginal
costs; while taking differences at points for closely similar standards belies the
range of uncertainty surrounding each point.
Because of the wide variation in the cost per ton of SC^ emitted for different
power plants, and because of the inherent uncertainties in both cost and emission
estimates, the usefulness of national calculations of the marginal cost per ton of
SO2 removed as a measure of individual standards is quite limited. For standards
close in value, the uncertainties overwhelm our ability to distinguish a reliable
cost per ton of SC^ removed. For standards far apart, we already know that the
costs per ton removed are different, and we know the direction of that
difference. What cannot be measured accurately is the magnitude.
All the above considerations render comparisons of the absolute values of this
measure, calculated using different national utility models (with slightly dif-
ferent assumptions), not at all definitive or even comparable. It is not surprising
that similar alternative standards can be ranked differently using this measure.
For example, the national cost effectiveness ranking presented at EPA's Decem-
ber 12, 1978, hearings is not especially useful, for it indicates neither the
regional differences nor the ranges of uncertainty involved for any of the
91
-------
numerous standards that were analyzed. Nevertheless, simple cost effectiveness
measures can be instructive so long as their shortcomings are recognized and use
is made of a variety of different measures that are appropriate to the decision at
hand.
92
-------
REFERENCES
I. Teknekron, Inc., Energy and Environmental Systems Division, Review of
New Source Performance Standards for Coal-Fired Utility Boilers,
vol. I, Emissions and Non-Air Quality Environmental Impacts,
EPA-600/7-78-l55a, Report prepared for the U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards
(Berkeley, Calif., March 1978).
2. Teknekron, Inc., Energy and Environmental Systems Division, Review of
New Source Performance Standards for Coal-Fired Utility Boilers,
vol. 2, Economic and Financial Impacts. EPA-600/7-78-l55b. Report
prepared for the U.S. Environmental Protection Agency, Office of
Planning and Evaluation (Berkeley, Calif., March 1978).
3. Teknekron, Inc., Energy and Environmental Systems Division, Review of
New Source Performance Standards for Coal-Fired Utility Boilers;
Phase 2 Report. R-002-EPA-79, Report prepared for the U.S. Envi-
ronmental Protection Agency, Office of Air Quality Planning and
Standards (Berkeley, Calif., December 1978).
4. PEDCo Environmental, Inc., Summary Report Utility Flue Gas Desul-
furization Systems, Oct.-Nov. 1977, Report prepared for the U.S.
Environmental Protection Agency, Division of Stationary Source
Enforcement and Industrial Environmental Research Laboratory
(Cincinnati, Ohio, 25 January 1978).
5. PEDCo Environmental, Inc., Particulgte and Sulfur Dioxide Emission
Control Costs for Large Coal-Fired Boilers. EPA-450/3-78-007,
Prepared for the U.S. Environmental Protection Agency, Office of
Air Quality Planning and Standards, Research Triangle Park, N.C.
(Cincinnati, Ohio, February 1978). Includes detailed computer print-
outs for all case studies.
6. TVA-Bechtel Shawnee Limestone-Lime Computer Program: Ten printouts
(lime 25 MW, 100 MW, 200 MW, 500 MW, 1000 MW; and limestone
25 MW, 100 MW, 200 MW, 500 MW, 1000 MW). Provided by C. David
Stephenson, National Fertilizer Development Center, Muscle Shoals,
Alabama, December 1978.
7. "Additional Information on EPA's Proposed Revision to New Source Per-
formance Standard for Power Plants," Federal Register 43 (8 Decem-
ber 1978): 57834-59.
8. ICF, Inc., Still Further Analyses of Alternative New Source Performance
Standards for New Coal-Fired Power Plants, Draft report prepared
for the U.S. Environmental Protection Agency (Washington, D.C.:
January 1979).
93
-------
APPENDIX A
PEDCO AND TVA FGD COSTS
-------
APPENDIX A
PEDCO AND TVA FGD COSTS
Teknekron has developed FGD cost and performance models based on PEDCo
(February 1978) and TVA (December 1978) engineering and cost estimates for
lime and limestone systems and PEDCo cost estimates for magnesium oxide
systems. ' ' The models can be used to predict new or retrofit FGD costs for
generating plants of between 25 MW and 2,000 MW in size burning coal of any
sulfur content and meeting any emission limit.
In this report, which assesses the sensitivity of projections to future FGD costs,
we have referred to the PEDCo estimates as representing "higher FGD costs"
and the TVA estimates as representing "lower FGD costs." The TVA and PEDCo
estimates have been used to represent a reasonable range of FGD costs. The
PEDCo costs are higher than TVA's and are probably representative of the cost
estimates that may be used by utilities without extensive experience with FGD
systems. The TVA costs, on the other hand, are less conservative and represent
cost estimates that may be used in the future by utilities that have had favorable
FGD experience. When similar assumptions are used, the differences between
these cost estimates are reduced. These two sets of cost estimates may also be
viewed as representing two points on the FGD "learning curve," with the lower
cost estimates indicative of lower, future FGD costs.
The three FGD systems are modular in design, with module sizes of between
50 MW and 130 MW except for plants of less than 50 MW in size. One redundant
module is included for all systems of 100 MW or greater for a design reliability
of 90 percent. The design of the three FGD systems is based on a three-stage
turbulent contact absorber (TCA). In determining the fuel-cycle costs of coal
utilization, FGD electricity and steam costs are included in the annual operating
costs. In the Utility Simulation Model, electricity and steam requirements for
FGD are used to calculate plant capacity penalties. Particulate control costs
are also calculated and included using the Teknekron particulate control cost and
performance models developed for EPA.
97
-------
Within the model, plant characteristics, c*xil properties, and emission limits are
used to determine the required rate of sulfur dioxide removal in pounds per hour
and the required gas flow rate in actual cubic feet per minute for an FGD system
having an annual average removal efficiency of 90 percent (92 percent for lime
systems) or greater. If a given generating plant needs to remove less than
90 percent of the SO2 produced to meet applicable emission limits, an FGD
system with an efficiency of 90 percent will be used to scrub a portion of the
flue gas. The remaining flue gas will be bypassed and mixed with the scrubbed
gas to yield the required SC^ emissions and to reduce or eliminate the fuel
required for reheating the flue gas. If 90 percent or more of the S02 must be
removed, an FGD system having the required efficiency up to the limits of
technology will be used to scrub the entire flue gas stream.
The cost of such equipment as pumps, hold tanks, feed preparation equipment,
and sludge ponds is based on the sulfur dioxide removal rate, while the cost of
such items as fans, absorbers, and soot blowers is based on the gas flow rate.
Likewise, operating costs are based on either the sulfur dioxide removal rate
(e.g., raw material) or the gas flow rate (e.g., electricity, reheat steam or oil).
Outputs from the FGD model include:
Capital cost
Fixed operating cost (independent of plant capacity
factor)
Variable operating cost (dependent on capacity factor)
Removal efficiency
Scrubber size
Capacity penalty (plant capacity used to operate the FGD
system)
Heat rate penalty (accounts for fuel required to operate
the FGD system)
Water used and water cost
98
-------
Oil used for magnesium oxide regeneration
Oil used for reheat
Annual sludge generation
S0? emissions are calculated on the basis of the uncontrolled emission rate and
the required removal efficiency.
Input data required for the FGD model include:
Individual generating-unit characteristics
Size
Age (new or retrofit)
Heat rate
Coal properties
Heating value
- Composition (C, H, O, N, S, H2O, ash)
Class (bituminous, subbituminous, lignite)
Environmental factors
Emission limit (specific limits: percentage removal,
ceiling, floor, and averaging time)
Economic factors
- Year scrubber was built (escalation, inflation)
TVA's capital and operating cost estimates for Hme and limestone FGD systems
are significantly lower than PEDCo's. (Tables A-1 and A-2 illustrate the
differences for a limestone system.)
The primary differences in capital cost are associated with the costs of the SO2
scrubber, sludge pond, and contingencies and fees. The difference between the
502 scrubber cost estimates is due primarily to the estimates for the absorber
99
-------
Table A-1
Comfxrison of TVA aid PEDCo Limestone FGD Capital Carts"
Capital Cost Item
Direct Costs
Limestone preparation
SQj scrubber
Sludge disposal
Sludge pond
Total direct costs
Indirect costs
Contingency and fee
Working capital
Total capital investment
PEDCo5
2,471,400
21,686,700
1,203,300
7,108,900
32,470,300
12,460,800
11,725,000
0
56,656,100
TVAC
3,133,000
14,800,000
2,144,000
Od
20,077,000
10,637,000
3,181,000
975.000
34,870,000
a Basis: Coal sulfur content = 2.76 Ib S/IO6 Btu
Plant size = 500 MW
Five scrubber modules at 125 MW each
90 percent annual average FGD removal efficiency
1975 costs and dollars
Adapted from raw PEDCo data for a 3-hour averaging time.
f+
Adapted from raw TVA data for a 365-day averaging time.
Sludge pond capitalization included in sludge disposal operating cost (see
Table A-2).
100
-------
Table A-2
Comparison of TVA and PEDCo Limestone FGD Operating Costs0
Cost Item
Limestone
Labor
Maintenance
Overhead
Electricity
Steam
Water
Sludge fix chemical
Sludge pumping
Sludge disposal
Total OAM costs
F
Units Required
32.4 tons/lw
80 man-hours/day
1 3,250 kW
92 x I06 Btu/hr
664.IGPM
9.1 tons/lir
520,000 Ion-mi les/yr
'EIXTo Estimate"5
Unit Cost
$6.48/ton
$7.I2/MH
25 mills/kWh
$2.257 106 Dtu
$0.0001 'i/gal
$l'i.23/lon
$l.4?/ton-mile
Annual Cost
$ 1,195,500
207,900
2,S50,000
1,59?, 600
1,886,100
1,178,700
32,300
737,300
738, 'lOO
0
$ 10, 418,800
1
Units Reguired
27.5 tons/hr
1 25 man-liours/day
7320 kW
67 x I06 BtiP/hr
5'«5.4 GPM
190,300 tons/yr
VA Estimateb
Unit Cost
$6.00/ton
$II.OO/MH
25 mills/kWh
$2. 257 I06 Dtu
$0.0001 2/gal
$7.50/ton
Annual Cost
$ 939,500
501,900
1,266,900
1,256,400
1,042,000
858,400
22,400
0
0
1,487,300
$7,374,800
Hasis: Coal sulfur content -- 2.76 Ib S/IO Otu
Plant size = 500 MW
90 percent anrHial overago CGI) removal efficiency
Capacity factor = 0.65
1975 costs and dollars
Adapted from raw PI:.IXTo and TVA doto.
-------
and not to the estimates for the various peripheral items, such as pumps, motors,
fans, and reheaters. As for the sludge pond, PEDCo estimates a capital cost of
about $7.1 million, while TVA includes sludge pond capitalization in the sludge
disposal cost. Finally, with respect to contingency and fee, PEDCo assumes a
20 percent contingency and a 6 percent fee on both direct and indirect capital
costs, while TVA assumes a contingency equal to 10 percent of the direct
investment and a fee of 5 percent of the direct investment.
The primary differences in the PEDCo and TVA operating cost estimates are in
the cost of maintenance and electricity. Both PEDCo and TVA maintenance
costs are based on a percentage of the capital cost. PEDCo's maintenance-cost
estimates are higher than TVA's because of PEDCo's higher capital costs and
somewhat higher percentage. Electricity costs depend directly on system
configuration and estimated motor sizes and duty cycles. The TVA system is
more efficiently designed in this regard, resulting in significantly lower elec-
tricity requirements.
Overall, the PEDCo cost estimates reflect design conservatism and are typical
of estimates that could be used by utilities that wish to be conservative in their
estimates of FGD system costs. The TVA costs, on the other hand, reflect a
greater confidence in the design basis for FGD systems and are less conservative
than the current PEDCo estimates.
Capital and operating costs for full limestone scrubbing on a 500 MW plant,
calculated by Teknekron's SC^ control cost model using PEDCo and TVA costs,
are shown in Tables A-3 and A-4. The PEDCo versus TVA-cost differences in
these tables are similar to those in Tables A-1 and A-2.
The cost of electricity and steam required to operate the FGD system is not
calculated in the Teknekron SOo model; instead, electricity and steam require-
ments are used to calculate unit capacity penalties and are accounted for in this
manner by the Utility Simulation Model. For the case illustrated in Tables A-3
and A-4, the TVA capacity penalty is 2.96 percent, and the PEDCo capacity
penalty is 4.25 percent.
102
-------
Table A-3
Comparison of Modeled TV A and PEDCo Limestone FGO Capital Costs0
Capital Cost Item
PEDCoc
TVAL
Direct costs
Limestone preparation
S02 scrubber
Sludge disposal
Sludge pond
Raw material inventory
Total direct costs
Indirect costs
Contingency and fee
Total capital investment
$ 2,423,800
21,012,600
1,201,900
5,632,800
162,600
$30,433,700
9,271,900
10,283,000
$49,988,600
$ 3,322,100
14,786,800
2,248,900
Oc
0
$20,357,800
7,348,700
3,053,700
$30,760,200
Note; More recent estimates by TVA include about $7 million for the
sludge pond and a contingency and fee of 25 percent of total direct costs.
Total TVA investment is therefore increased to about $42 million.
a Basis: Coal sulfur content = 2.50 Ib S/IO6 Btu
Sulfur RSD = 0.15, no exempt ions ,
Design sulfur content = 3.63 Ib S/IO Btu
Plant size = 500 MW
Five scrubber modules at 125 MW each
85 percent 24-hour average S02 removal
1975 costs and dollars
b Costs predicted by Teknekron's SO2 control model. Not included are
interest during construction, workingcapital, and taxes; these are calcu-
lated in the Utility Simulation Model's financial module.
c Sludge pond capitalization included in sludge disposal operating cost (see
Table A-4).
103
-------
Table A-4
.a
Comparison or moaeiea i VM ana ra-»co i_imesrone rvju» \jperaring COSTS
Cost Item
Limestone
Labor
Maintenance
Water
Sludge disposal
Analysis cost
Total O&M costs
PEDCob
$ 804,400
406,500
3,736,600
38,000
996,100
0
$5,981,600
TVAb
$ 769,900
783,400
1,816,800
21,800
1,219,700
69,400
$4,684,000
Note; More recent estimates by TVA include a higher cost for maintenance
(due to higher capital cost) and sludge disposal. Total TVA operating
cost estimates are about the same as the PEDCo estimates.
a Basis: Coal sulfur content = 2.50 Ib S/IO6 Btu
Plant size = 500 MW
85 percent 24-hour average S0? removal
Capacity factor = 0.65
1975 costs and dollars
Costs predicted by Teknekron's SOj control model. Not included are:
(a) steam and electricity costs, whicn are used in the Utility Simulation
Model to calculate capacity penalties; and (b) fixed charges, which are
calculated in the Utility Simulation Model's financial module.
104
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APPENDIX B
LIFE-CYCLE COSTING
105
-------
APPENDIX B
LFE-CYCLE COSTWG
When faced with an investment decision, an industrial firm usually compares the
present values of all costs (operating as well as capital costs) associated with
each alternative investment under consideration. It is common to think of the
cost of alternative systems in terms of annual costs over the economic life of a
facility. Within the present-value framework, this can be done by levelizing
capital and operating expenditures and then comparing between alternatives,
choosing those that have the lowest levelized capital and operating cost.
In levelizing, one derives a series of equivalent annual costs that gives the same
present value as a series of varying annual operating costs or one-time capital
costs that are expected to occur. By definition, each annual term in the
levelized series is equivalent; the level ized cost is thus equal to the value of any
one of the terms in the series. Mathematically, present value is represented as:
C,tl * P|) C,(Up,XUpk|) C,(l + p,)... (U p.|t
where
PV, = present value of variable being evaluated in initial year j,
C. = cost of variable being evaluated in initial year] (beginning of
J the year),
p. = price escalation of that variable in year j,
N = economic lifetime,
d = average discount rate over time period considered = weighted
average cost of corporate capital.
107
-------
The levelized cost is related to the present value as follows:
vN
/ Jv
O\ I + QJ DW
N
(Ud)N-l
I +
'--HI
N
(3)
where
LF = levelization factor,
p = average price escalation rate for entire time period N.
In practice and in our applications, p is not necessarily constant. The use of
these formulae in levelizing operating costs is illustrated in Tables B-l and B-2.
For capital costs, there are additional charges associated with an investment
beyond the initial ones levelized by applying equation (2). The taxes and
insurance required for capital equipment should be accounted for as well. This is
usually done by applying a fixed charge rate to the initial investment amount
rather than using equation (2) to arrive at a total levelized cost associated with
capital expenditures. The fixed charge rate is defined as
where
FCR =
WACC =
FCR = WACC + DEPRCR + TAX + IRT,
fixed charge rate,
weighted average cost of capital,
108
-------
TotteB-1
Calculation of Present Value
Year
Initial-Year
Cost
Price
Escalation
Factor
Escalated
Cost
Discount
Factor
(I * p)'
N
I
(l+d)r
Present
Value
PV
I
2
3
4
Total
1.0700
1.1449
I.2250
1.3108
1.0700
1.1449
1.225
1.3108
.9091
.8264
.75.13
.6830
.9727
.9462
.9204
.8953
3.7346°
Note; p = annual price escalation rate; N = number of years; d = discount rate.
0 Present value is the same, whether calculated by this long method or by the method of discounting levelized costs shown
in Table B-2.
-------
Table B-2
Calculation of Present Value by Discounting Levelized Costs
Initial-Year
Cost
Year C
1 1
2 1
3 1
4 1
Total
Level ization
Factor
x LF
1.1782
1.1782
1.1782
1.1782
Levelized
Cost
LC, LC
1.1782
1.1782
1.1782
1.1782
Discount
Factor
1
* N
(Ud)N
.9091
.8264
.7513
.6830
Present
Value
PV
1.0710
.9737
.8852
.8047
3.7346°
d-p
«T
a Present value is the same, whether calculated by this method or by the long method in Table B-1.
d(l + d)N .
Note also that LC = PV x
(Ud)N-l
x .3155 = I.
-------
DEPRpp = depreciation for capital recovery as a level!zed percentage of
initial investment,
TAX = taxes as a levelized percentage of initial investment,
IRT = insurance and real estate taxes as a percentage of initial
investment.*
Because of the lower cost of capital associated with pollution control invest-
ments, the fixed charge rate used to evaluate such an investment by a privately
owned utility is usually lower than the rate used for other investments. The
fixed charge rates and levelization factors used in the analyses contained in this
report are presented in Table B-3, and the cost elements of the coal fuel cycle
that are levelized are shown in Table B-4.
*Sometimes equation (4) is written as
FCR = CRF * TAX + IRT,
where
CRF = capital recovery factor
= WACC + DEPRCR,
and where DEPR^ is calculated by the sinking fund formula as
DEPR WACC
(UWACC)-I
Then:
WACC + DEPRCR = WACC + WACC ^ = WACC (I + WACC)N .
CK (U WACC)N - I (I + WACC)N - I
This last expression, when multiplied by the initial investment, is equivalent to
LC calculated in equation (2).
Ill
-------
Table B-3
Fixed Charge Rotes end Levellzatian Factors Used to Evaluate Investments
In Publicly and Privately Owned Electric Utilities0
Public Private Pollution Control Investment
Variable Ownership Ownership (Private Ownership)
Fixed charge rate 11.3% 20.1% 19.4%
Levelization factor 1.94 1.73 1.73
a Assuming a plant life of 30 years.
112
-------
Table B-*
Oats Levelized to the Coal Fuel Cycle
Capital Costs
Electrostatic precipitator
Fabric filter
Flue Gas Desulfurization
Boiler
Operating Costs
F.o.b. mine price
Transportation cost
Coal cleaning cost (if applicable)
Participate control O&M
Flue gas desulfurization O&M
113
-------
It is also important to examine the sensitivity of level! zed costs with respect to
various parameters of the life-cycle costing formulation. A simplifying assump-
tion that can be used to determine operating cost sensitivity, as discussed in this
appendix, is to allow the average discount rate over time to be equal to the
average price escalation rate. This produces the largest sensitivities to be
expected. Numerical sensitivities can be examined, since equation (3) then
reduces to:
IF/ - Nd(Ud>N-'
' ' (5)
Selected numerical values for price escalation and economic lifetime when
applied to equation (5) are shown in Table B-5. This information shows that
levelized operating costs may vary considerably in this worst-case analysis
depending on both the economic lifetime and the average price escalation to be
expected.
The sensitivity of life-cycle cost to capital costs is directly dependent on the
fixed charge rate assumed. Values assumed in this analysis are shown in
Table B-3. The overall life-cycle cost is the sum of capital and operating costs,
so that the sensitivity of key parameters to total cost must be considered on a
specific basis. For example, if 60 percent of the total levelized cost were
capital-related, the variations shown in Table B-5 would apply to only 40 percent
of the cost.
-------
Table B-5
Sensitivity of Levelizotion Factors
N p = d
^^B ^^^^'^^^^^^^^^(^^^^^^MBVI
8% 12%
20 1.8 2.39
25 2.17 2.85
30 2.47 3.33
115
-------
APPENDIX C
CITY-SPECFIC SENSITIVITY ANALYSES
117
-------
APPENDIX C
CITY-SPECFIC SENSITIVITY ANALYSES
In order to demonstrate regional implications of the various sensitivity analyses
conducted in this study, several city-specific cases are presented in this
appendix. The case for Columbus, Ohio, is presented in detail in the text.
This appendix includes graphic presentations of the sensitivity analyses for the
following key factors as a function of the SC^ standard (considering both the
standard with a 24-hour floor and that with an annual ceiling):
F.o.b. coal mine prices
Coal transportation rates
Western coal sulfur and Btu characteristics
The key cities covered here are:
Indianapolis, Indiana
Orlando, Florida
Austin, Texas
Together with Columbus, Ohio, they are representative of a range of geograph-
ical and other differences.
24-Hour S02 Standard
Sensitivity to Coal Mine Price
The sensitivity of fuel-cycle costs with respect to the 24-hour S02 floor and
f.o.b. coal mine price is shown for Indiana, Florida, and Texas in Figures C-1
through C-3.
119'
-------
Figura C-1
Sensitivity of Uvallzad Fual-Cycla Cost to 24-Hour SO, Floor
and F.O.B. Coal Mlna Prices
(Indianapolis, Indiana)
350-
260-
Powdar Rlvar coal
0.5% sulfur, 6.0% ash, 8,100 Btu/lb
« Csntrsl Appalachian coal
1.6% sulfur, 6.0% ash, 12,000 Btu/lb
±11 Wo
±10%
F.O.B. CoslPrteM (S/ten)
t1»7i +10*
PR t.75 7.43 «.M
CA 25.00 27^0 22.50
2 0.4 0.6 0.8 1.0
24-HOUR AVIRAOE SO, FLOOR (LB SO^O* ITU)
Not9: Calculations sssums a 1.2 Ib SOa/10* Btu calling with 85% removal (24-hour avsrags
with axsmptions of thrat dsys par month). Transportation ratas: rail < 250 mllst,
2.25C/ton-mll«; > 250 milts, 1.20C/ton-mlla; watar O^C/ton-mlla.
(20
-------
Figure C-2
Sensitivity off Levelized Fuel-Cycle Cost to 24-Hour SO2 Floor
and F.O.B. Coal Mine Prices
(Orlando. Florida)
400-1
£
3
o
I
I
I
350-
300-
250-
«" Powder River coal
0.5 % sulfur, 6% Mh, 8,000 Btu/lb
Southern Appalachian coal
2.1% sulfur, 8.2% ash, 12,000 Btu/lb
F.O.B. CoilPrlcts (S/ton)
$1976 +10% -10*6
PR 6.75 7.43 6.08
8A 23.00 25.30 20.70
I
0.2
I
0.4
I
0.6
I
0.8
I
1.0
I
1.2
24-HOUR AVERAGE 80, FLOOR (LB 8O,/10* BTU)
Calculations assume a 1.2 Ib SO,/10* Btu celling with 85% removal (24-hour average
with exemptions of three days per month). Transportation rates: rail < 250 miles,
2.25t/ton-mile; > 250 miles, 1.20/ton-mile; water 0.50/ton-mlle.
I2I
-------
Figure C-3
Sensitivity of Levelized Fuel-Cycle Coet to 24-Hour SO2 Floor
and F.O.B. Coal Mine Prices
(Austin, Texas)
400-t
350-
300-
250-
Powder River coal
0.5% sulfur, 6% ash, 8,100 Btu/lb
Gulf Coast lignite
0.8% sulfur, 10% ash, 6,500 Btu/lb
±10% «^---
F.O.B. Coal PriOM (S/lon)
S1978 +10* -10*
PR 6.75 7.43 6.08
GC 6.00 6.60 S.40
I
0.6
I
0.8
0.2 0.4
24-HOUR AVERAGE 60, FLOOR (LB 80^10* BTU)
I
1.0
1.2
Not*: Calculations assume a 1.2 Ib SOj/10* Btu celling with 85% removal (24-hour averse*
with exemptions of three days per month). Transportation rates: rail < 250 mitZT
2.25C/ton-mile; > 250 miles, 1.20C/ton-mlle; water O^C/ton-mile. '
122
-------
Western coal becomes increasingly competitive at all floors as coal mine prices
uniformly escalate. That is, the floor above which western coal is economically
preferred decreases as the relative coal price increases) as shown in Table C-1.
Table C-1
24-Hour SO, Floors above Which Western Coal Is Economically
Preferred for Various Coal Mine Prices
Ohio (Columbus)
Indiana (Indianapolis)
Florida (Orlando)
Texas (Austin)
+ 10%
-0.7
-0.2
-0.6
-0.2
F.o.b. Mine Price
1978 Level
-0.9
-0.5
-0.8
<0.2
-10%
~l.2
-0.9
>t.2
~0.4
For this analysis, as shown in Figures C-1 through C-3, the following f.o.b. coal
mine prices were assumed:
F.o.b. Coal Mine Prices (1978 $/ton)
Base Price +10% -10%
Powder River (PR) 6.75 7.43 6.08
Northern Appalachian (NA) 23.00 25.30 20.70
Central Appalachian (CA) 25.00 27.50 22.50
Southern Appalachian (SA) 23.00 25.30 20.70
Gulf Coast Lignite (GO 6.00 6.60 5.40
Thus, general inflation in coal mining cost tends to favor distant western coals.
This is because the proportion of coal mine price to total cost is much smaller
123
-------
for these than for local coals. However, even though escalating coal mine price
favors western coals, whether or not these coals are chosen by a utility depends
on plant location and other site-specific factors as well as on the level of the
applicable S02 standard.
Sensitivity to Coal Transportation Rate
The sensitivity of fuel-cycle costs with respect to the 24-hour SO2 floor and coal
transportation rate is shown for Indiana, Florida, and Texas in Figures C-4
through C-6.
Escalating rail and barge rates favor local coals, causing them to become
increasingly competitive at all floors. That is, the emission floor above which
western coal is economically preferred increases as transportation rates in-
crease, as shown in Table C-2.
Table C-2
24-Hour SO, Floors above Which Western Coal Is Economically
Preferred for Various Transportation Rates
Ohio (Columbus)
Indiana (Indianapolis)
Florida (Orlando)
Texas (Austin)
Lowest Rate (A)
-0.6
>0.2
-0.5
-0.6
Medium Rate (B) Highest Rate (C)
-0.9 >l.2
-0.5 ~0.8
-0.9 >|.2
>l.2 >,.2
This is because the proportion of transportation cost to total cost is much
smaller for local than for western coals. The following coal transportation rates
were assumed for the sensitivity analyses:
124
-------
Figure C-4
Sensitivity of Lavelizod Fual-Cycl« Cost to 24-Hour SO, Floor
and Transportation Rat*
(Indianapolis. Indiana)
400-n
350-
300-
250
Powder River coal
0.5 % sulfur, 6% a*h, 8,000 Btu/lb
Central Appalachian coal
1.6% sulfur, 8.0% ash, 12,000 Btu/lb
$1978
Raft ((/lon-mllt)
Rill (mll«t)
<2SO >250
A 2.00 1.00
B 2.25 1.10
C 2.50 1.20
Rail Only
Watar
dltttne»i)
0.4
O.S
1
0.2
i
0.4
0.6
0.8
1.0
1.2
24-HOUR AVERAGE SO, FLOOR (LB SOt/10* BTU)
Not*: Calculations a»»ume a 1.2 Ib SO2/10« Btu celling with 85% removal (24-hour average
with exemptions of three days per month).
125
-------
Figure C-5
Sensitivity of Lsvalizsd Fuel-Cycle Cost to 24-Hour S02 Floor
and Transportation Rats
(Orlando, Florida)
400-1
5- 350-
o
CO
O
o
u
IU
u.
O
IU
N
IU
U
300-
250-
1 Powder River coal
0.5 % sulfur, 6% ash, 8,000 Btu/lb
Southern Appalachian coal
2.1% sulfur, 8.2% ash, 12,000 Btu/lb
S197S
Rat* ((/Ion-mile)
Wtltr
Rail (mll*«)
<2SO >2SO (all dltUnct*)
A 2.00 1.00
B 2.25 1.10
C 2.50 1.20
0.4
O.S
0.6
JL *R«H Only
0
i
0.4
I
0.6
0.2 0.4 0.6 0.8 1.0
24-HOUR AVERAGE SO, FLOOR (LB S02/10* BTU)
I
1.2
Not*: Calculations assume a 1.2 Ib SO2/10« Btu celling with 85% removal (24-hour average
with exemptions of three days per month).
126
-------
Figure C-6
Sensitivity of Lavelizsd Fuel-Cycle Cost to 24-Hour SO2 Floor
and Transportation Rate
(Austin, Texas)
400-i
350-
&
w
8
!
2
I
Powder River coal
0.5% »ulfur, 6.0% ash, 8,100 Btu/lb
Gulf Coast lignite
0.8% sulfur, 10% ash, 6,500 Btu/lb
250-
* 1»7S
fUtt (t/ton-mllt)
Hall (mltei)
<2SO >250
Water
(II
A 2.00
B 2.2S
C 2.SO
1.00
1.10
1.20
0.4
O.S
-L. *R«|| only
I
0.2
I
0.6
I
1.0
0.4 0.6 0.8
24-HOUR AVERAGE SO, FLOOR (LB »O>/10* BTU)
1.2
Nott: Calculations assume a 1.2 Ib SCyiO* Btu ceiling with 85% removal (24-hour average
with exemptions of three days per month).
127
-------
Coal Transportation Rate (1978 C/ton-mile)
<250
2.00
2.25
2.50
RAIL (miles)
>250
1.00
1.10
1.20
WATER
(all distances)
0.4
0.5
0.6
A
B
C
It should be noted that, when coal mine prices and transportation rates uniformly
escalate simultaneously, they have opposite effects on the selection of a least-
cost local versus a distant western coal. This can be observed by comparing
Figures C-1 through C-6.
Sensitivity to Western Coal Characteristics
The sensitivity of fuel-cycle costs with respect to the 24-hour SOj floor and
typical western coal characteristics is shown for Indiana, Florida, and Texas in
Figures C-7 through C-9. The western coal chosen is that from the Powder
River Basin (see Appendix D).
The levelized fuel-cycle cost of lower-sulfur Powder River coal increases by as
much as 30 percent over the range'of standards from 1.2 to 0.2 Ib SC^/IO Btu;
the cost of higher-sulfur Powder River coal increases by no more than about
15 percent. By comparison, high-sulfur eastern coal increases in cost by no more
than 10 percent over the range of 1.2 to 0.2 Ib SO^IO Btu. Powder River coal
is more competitive as the standard becomes less stringent and as the sulfur
content of the coal decreases.
In the states considered here, Powder River coals of very low sulfur content are
preferred to local coals at every floor within the range of 1.2 to 0.2 Ib S02/I06
Btu. Conversely, Powder River coals of very high sulfur content are not likely to
128
-------
Figure C-7
Sensitivity of Uvalizad Fuel-Cycle Co»t to 24-Hour SO, Floor
nd Powder Rivar Coal Characteristics
(Indianapolis. Indiana)
4QOi
350-
I
o
o
Si
2
300-
Powdsr River eosl (PR)
Central Appalachian cost (CA)
1.6% sulfur, 8.0% sth, 12,000 Btu/lb
PR-I
2801 Ib 8/10*
PR-C
PR-b
Btu
PR-s
OJ 0.4 0.6 OJ 1.0
24-HOUR AVERAGE SO, FLOOR (LB »O«/10* ITU)
l
1.2
Csteulstlono sssums s 1.2 Ib 80|/10« Btu eslllng with 65% removal (24-hour avsrsot
with exemption* of three dsys per month). Powder River $197t/ton * 6.75; Centrsl
Appslsehlsn $1976/ton * 25.00.
(29
-------
Figure C-8
Sensitivity of Levelized Fuel-Cycle Coet to 24-Hour 8O2 Floor
and Powder River Coal Characteristics
(Orlando, Florida)
400-i
5- 350-
B
&
10
O
u
iu
U
O
iu
2
O
s
300-
ui
250-
PR-f
PR-e
SA
PR-d
PR-c
Powder River coal (PR)
- Southern Appalachian coal (SA)
2.1% sulfur, 8.2% ash, 12,000 Btu/lb
Powder fthwr (PR)
PR-b
PR-a
*tuHiir
Btu/ft
Ib t/UC Shi
0.4
t,000
0.44
b
03
MOO
O.M
c
0.5
300
o.»
d
9A
4K»
0.63
t
03
7400
OJ7
f
0.1
7300
OJO
I
0.2
0.4
l
0.6
0.8
1.0
I
1.2
24-HOUR AVERAGE 8O, FLOOR (LB SO,/10* BTU)
Noto: Calculations assume a 1.2 Ib SO,/10« Btu celling with 85% removal (24-hour averaoe
with exemptions of three days per month). Powder River $1978/ton = 6.75; Southern
Appalachian $1978/ton = 23.00. m
130
-------
Figure C-9
Sensitivity of Levelized Fuel-Cycle Coet to 24-Hour SO, Floor
and Powder River Coal Characteristics
(Austin, Texas)
400-1
5- 3501
a
&
u
IU
o
£
N
300-
250
Powder River coal (PR)
Gulf Coett lignite (GC)
0.8% Milfur, 10% ash, 6,500 Btu/lb
PR-t
PR-d
Btvtr (PR)
*MiHur
Btu/lb
Ib S/10* Btu
0.4
9,000
0.44
b
O.S
»,000
O.S6
c
O.S
8,500
O.W
d
0.5
1.000
O.S3
0.5
7300
0.67
»
o.«
7300
O.SO
PR-C
PR-b
PR-a
I
0.6
I
1.0
0.2 0.4 0.6 0.8
24-HOUR AVERAGE SO, FLOOR (LB SO,/10* BTU)
1.2
Note: Calculations assume a 1.2 Ib SO2/10* Btu calling with 85% removal (24-hour average
with exemptions of three days per month). Powder River coal S1978/ton = 6.75; Gulf
Coast lignite $1978/ton = 10.00.
I3I
-------
be selected as the least-cost coal for any level of floor. Figures C-7 through
C-9 indicate that the following Powder River coals are of "minimum competitive
quality": For Indiana, 0.60 Ib S/IO6 Btu; for Florida, 0.57 Ib S/IO6 Btu; and for
Texas, 0.62 Ib S/IO Btu. It should be noted that the average sulfur content of
the Wodak-Anderson seam is approximately 0.61 Ib S/IO Btu (see Appendix D
for characteristics of Powder River coals likely to be mined between now and
1990). Thus, the particular coal characteristics available to an individual utility
are very important to its selection of coal and pollution controls.
Annual SO2 Ceiling
This final section of Appendix C discusses the sensitivity of typical utility cost
estimates for buying, transporting, and burning different coals in several states
as a function of an annual SO2 ceiling. For each state represented in
Figures C-10 through C-12, a representative power-plant location has been
selected for which a change in SO2 standard may critically influence the choice
of coal and therefore the resulting emissions.
For power plants located in eastern and midwestern states, reductions in the
level of the annual S02 ceiling increase the levelized fuel-cycle cost of western
coal relative to that of eastern (local) coal. For many states, at some level of
standard below 1.2 Ib SO,/10 Btu, an eastern (local) coal becomes the econom-
* £
ical choice on the basis of levelized cost per 10 Btu of coal burned.
The levelized fuel-cycle cost for a typical (low-sulfur) western coal may increase
by as much as 30 percent as the annual SO2 ceiling increases in stringency from
1.2 to 0.2 Ib SO2/I06 Btu. For a typical (higher-sulfur) eastern coal, fuel-cycle
costs increase by not more than approximately 15 percent over this range.
A comparison of the levelized fuel-cycle costs of the "least-cost" western and
"least-cost" eastern (local) coal in the states considered here shows that the
differences do not exceed approximately + 15 percent. These states represent
sufficient geographic diversity to suggest this conclusion on a national basis.
132
-------
Figure C-10
Sensitivity of Levelized Fuel-Cycle Coet to
Annual SO2 Ceiling
(Indianapolis, Indiana)
400-«
~ 350-
fc
O
u
300-
250-
Powder River coal
0.5 % sulfur, 6% ash, 8,000 Btu/lb
-Central Appalachian coal
1.6% aulfur, 8.0% ash, 12,000 Btu/lb
T-
i
0.2
I
0.4
I
0.6
I
0.8
1.0
l
1.2
ANNUAL 80, CEILING (LB SO,/10> BTU)
133
-------
Figure C-11
Sensitivity of Levalized Fuel-Cycle Cost to
Annual SO, Coiling
(Orlando, Florida)
400-1
i
a
&
5
o
o
Ul
d
H
i
3
250-
Powder River coal
0.5% MiHur, 6.0% a»h, 8,100 Btu/lb
Southern Appalachian coal
2.1% auHur, 8.2% aah, 12,000 Btu/lb
0.4 0.6 0.8
ANNUAL SO, CEILING (LB §0^10* BTU)
I
1.0
1.2
(34
-------
Figure C-12
Sensitivity of Levelized Fuel-Cycle Cost to
Annual SO2 Ceiling
(Austin, Texas)
400-1
£> 350-
£
&
i
300-
HI
250-
Powder River coal
0.5% sulfur, 6.0% ssh, 8,100 Btu/lb
Gulf Coast lignite
0.8% sulfur, 10% ash, 6,500 Btu/lb
I
0.2
I
0.4
I
0.6
l
0.8
I
1.0
I
1.2
ANNUAL SO, CEILING (LB 8O,/10* BTU)
135
-------
For the city-specific data selected for Ohio (see Section 3) and Florida
(Figure C-10), eastern (local) coals are preferred at ceilings below about 0.65
and have the economic advantage of being able to increase in cost by as much as
8 percent and still remain the preferred least-cost coal. In Indiana (Figure C-l I)
and Texas (Figure C-l2), western coals (Powder River) are preferred at nearly
every ceiling. In Texas, however, mine mouth plants located near lignite fields
are likely to select the local coal. In all states, western coals have the economic
advantage of being able to increase in cost and still remain competitive at higher
ceilings. However, at lower ceilings the converse is true, and local coals will be
selected.
136
-------
APPENDIX D
CHARACTERISTICS OF MAJOR POWDER RIVER BASIN COAL SEAMS
137
-------
APPENDIX D
CHARACTERISTICS OF MAJOR POWDER RIVER BASIN COAL SEAMS
The sulfur and Btu contents of western, and in particular Powder River Basin,
coals are significant for evaluating the impacts of alternative revised New
Source Performance Standards. The sensitivity to these parameters is analyzed
in the text and in Appendix C of this report.
Table D-1 lists the most important seams in the Powder River Basin and, for
each seam, shows the sulfur, ash, and Btu content of the coal. Average sulfur
content varies between approximately 0.4 percent and 0.6 percent, while the
heating value may range from 7,500 to 9,500 Btu/lb; this is the equivalent of a
range of 0.42 to 0.80 Ib S/IO6 Btu. The ash content of Powder River coal varies
from about 4 percent to 7 percent on the average.
139
-------
Table D-1
uiaracverisrics or major rowaer rviver oasin i^aai yearns
Sulfur (%)
Seam
Anderson
Badger
Canyon
Felix
Heal/
Monarch
School
Smith
Sussex
Wodak-Anderson
Range
0.17 -
0.4 -
0.14 -
0.32 -
0.26 -
0.3 -
0.5 -
0.2 -
1.13
0.5
0.92
3.26
3.0
0.7
0.7
1.2
Average
0.52
0.45
0.34
0.89
0.6
0.4
0.6
0.63
0.49
0.5
Ash(%)
Range
3.5 -
6.9 -
3.1 -
4.5 -
5.| -
3.1 -
8.8 -
3.9 -
12.2
9.8
7.4
14.9
22.1
B.2
15.7
12.2
Average
6.5
7.9
5.1
7.8
7.6
4.4
11.4
4.7
5.2
6.0
Btu/lb
Range
7,128-
7,606 -
7,537 -
7,180-
6,480 -
9,000-
7,830 -
7,420 -
8,737
8,290
8,609
9,535
8,270
10,410
8,870
9,600
lbS/l06Btu
Average
7,979
7,951
8,286
8,053
7,884
9,600
8,183
7,991
9,160
8,224
Range
0.19 -
0.48 -
0.16 -
0.34 -
0.31 -
0.29 -
0.56 -
0.21 -
1.59
0.66
1.22
4.54
4.63
0.78
0.89
1.62
Average
0.65
0.57
0.41
l.ll
0.76
0.42
0.73
0.79
0.53
0.61
Source; Keystone Cool Industry Manual, 1977, pp. 711-13.
-------
APPENDIX E
PROJECTED REGIONAL AND NATIONAL UTILITY COAL PRODUCTION
141
-------
APPENDIX E
PROJECTED REGIONAL AND NATIONAL UTILITY COAL PRODUCTION
Tobies
El - E3 Regional Utility Coal Production: 1985, 1990, 1995 (scrubber cost
estimates by PEDCo)
E4 Summary of Regional Growth Rates in Utility Coal Production,
1985-1995 (scrubber cost estimates by PEDCo)
E5 - E7 Regional Utility Coal Production: 1985, 1990, 1995 (scrubber cost
estimates by TV A)
E8 Summary of Regional Growth Rates in Utility Coal Production,
1985-1995 (scrubber cost estimates by TV A)
Region Definitions
Appalachia = Ohio, Pennsylvania, West Virginia, Virginia, Kentucky
(east), Tennessee, Alabama
Midwest = Illinois, Indiana, Kentucky (west), Iowa, Missouri, Kansas,
Oklahoma
Northern Great
Plains = Montana, Wyoming (north), North Dakota, South Dakota
Rocky Mountain = Wyoming (south), Colorado, Utah, Arizona, New Mexico
Gulf Coast = Texas, Arkansas, Louisiana
Other = Washington, Oregon, Nevada, California
-------
Table E-l
Regional Utility Coal Production: 1985*
(10 tons per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
Other
National
Western coal shipped east
of the Mississippi River
Current
NSPS
322.2
79.7
213.4
102.4
17.0
2.8
737.5
110.7
0.6 Ib
Floor
321.9
82.7
206.1
103.6
22.7
2.8
739.8
109.5
0.2 Ib
Floor
342.7
8216
170.0
95.4
42.3
2^
735.8
79.2
0.6 Ib
Ceiling
335.6
81.1
182.5
103.5
27.6
2.8
733.1
89.8
*Scrubber cost estimates by PEDCo.
144
-------
Table E-2
Regional Utility Coal Production: I990»
(Mr tons per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
Other
National
Western coal shipped east
of the Mississippi River
Current
NSPS
382.2
73.6
362.2
150.3
17.0
2.2
987.5
179.0
0.6 Ib
Floor
379.4
81.0
343.6
160.3
23.1
15.0
1002.4
167.5
02 Ib
Floor
437.1
81.0
214.3
107.4
168.2
15.2
1023.2
79.3
0.6 Ib
Ceiling
414.0
78.3
249.7
154.7
77.9
15.0
989.6
III. 5
Scrubber cost estimates by PEDCo.
145
-------
Table E-3
Regional Utility Coal Production: 1995*
(10 tons per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
Other
National
Western coal shipped east
of the Mississippi River
Current
NSPS
446.8
68.4
521.8
193.0
17.0
2.7
1249.7
239.5
0.6 Ib
Floor
459.8
79.6
476.8
206.2
24.3
23.0
1269.7
216.6
0.2 Ib
Floor
539.7
79.6
273.8
133.1
260.4
22.6
1309.2
92.9
0.6 Ib
Ceiling
503.5
79.5
319.6
200.9
120.1
22.9
1246.5
136.2
*Scrubber cost estimates by PEDCo.
146
-------
Table E-4
Summary of Regional Growth Rates in Utility
Coal Production, 1985-1995*
(% per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
National
Western coal shipped east
of the Mississippi River
Current
NSPS
3.3
-1.5
8.9
6.3
0.0
5.3
7.7
0.6 Ib
Floor
3.6
-0.4
8.4
6.9
0.7
5.4
6.8
0.2 Ib
Floor
4.5
-0.4
4.8
3.3
18.2
5.8
1.6
0.6 Ib
Ceiling
4.1
-0.2
5.6
6.6
14.7
5.3
4.2
*Scrubber cost estimates by PEDCo.
147
-------
Table E-5
Regional Utility Coal Production: 1985*
(10 tons per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
Other
National
Western coal shipped east
of the Mississippi River
Current
NSPS
349.8
79.5
143.1
62.3
96.1
4.2
735.0
58.0
0.2 Ib
Floor
350.6
83.3
141.4
62.4
92.3
4^/7
734.7
56.2
0.6 Ib
Ceiling
350.5
81.7
143.1
62.4
92.3
4^3
734.3
58.0
*Scrubber cost estimates by TVA.
148
-------
Table E-6
Regional Utility Coal Production: 1990*
(10 tons per year)
Region
Appolochia
Midwest
Northern Great Plains
/
Rocky Mountain
Gulf Coast
Other
National
Western coal shipped east
of the Mississippi River
Current
NSPS
433.1
72.5
188.3
71.2
209.4
J5.5
990.0
61.0
0.2 Ib
Floor
435.0
90.3
172.2
70.7
205.6
15.7
989.5
40.5
0.6 Ib
Ceiling
434.6
74.4
190.6
70.5
203.9
15.7
989.7
60.1
*Scrubber cost estimates by TVA.
149
-------
Tdble E-7
Regional Utility Coal Production: 1995*
(10 tons per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
Other
National
Current
NSPS
528.7
66. 8
264.4
87.2
286.5
24.1
1257.7
0.2 Ib
Floor
531.9
101.2
210.4
90.1
285.7
23.5
1242.8
0.6 Ib
Ceiling
532.0
73.9
241.5
89.3
286.0
24.4
1247.1
Western coal shipped east
of the Mississippi River 72.1 32.7 66.1
*Scrubber cost estimates by TVA.
150
-------
Table E-8
Summary of Regional Growth Rates in Utility
Coal Production, 1985-1995*
(% per year)
Region
Appalachia
Midwest
Northern Great Plains
Rocky Mountain
Gulf Coast
National
Western coal shipped east
of the Mississippi River
Current
NSPS
4.1
-1.7
6.1
3.4
10.9
5.4
2.2
02 Ib
Floor
4.2
1.9
4.0
3.7
11.3
5.3
-5.4
0.6 Ib
Ceiling
4.2
-0.1
5.2
3.6
11.3
5.3
1.3
*Scrubber cost estimates by TVA.
151
-------
APPENDIX F
SELECTED RESULTS FOR 1990 AND 1995
153
-------
APPENDIX F
SELECTED RESULTS FOR 1990 AND 1995
Tables
F-l-F-4 USM Emission Projections, 1990 and 1995 (PEDCo FGD Costs,
TVA FGD Costs)
F-5-F-8 USM Cost Projections, 1990 and 1995 (PEDCo FGD Costs, TVA
FGD Costs)
F-9-F-I2 USM Fuel Impact Projections, 1990 and 1995 (PEDCo FGD
Costs, TVA FGD Costs)
Region Definitions
Definitions for Emission Summary Tables
Northeast
Southeast
North Central
West South
Central
Mountain
Pacific
New England (Maine, Connecticut, Rhode Island, Massa-
chusetts, New Hampshire, Vermont)
Middle Atlantic (New York, New Jersey, Pennsylvania)
South Atlantic (Delaware, Maryland/D.C., Virginia, West
Virginia, North Carolina, South Carolina, Georgia,
Florida)
East South Central (Kentucky, Tennessee, Mississippi,
Alabama)
East North Central (Wisconsin, Michigan, Illinois, Indiana,
Ohio)
West North Central (North Dakota, South Dakota, Nebras-
ka, Kansas, Iowa, Missouri, Minnesota)
Texas, Oklahoma, Arkansas, Louisiana
Idaho, Montana, Wyoming, Nevada, Utah, Colorado, Ari-
zona, New Mexico
Washington, Oregon, California
155
-------
Definitions for Fuel Impact Tables
Appalachia
Midwest
Northern Great
Plains
West
Gulf Coast
Ohio, Pennsylvania, West Virginia, Virginia, Kentucky
(eastern), Tennessee, Alabama
Illinois, Indiana, Kentucky (western), Iowa, Missouri, Kan-
sas, Oklahoma
Montana, Wyoming (northern), North Dakota, South
Dakota
Wyoming (southern), Colorado, Utah, Arizona, New
Mexico, Washington
Texas, Arkansas, Louisiana
156
-------
Table F-1
USM Emission Projections, 1990
(PEDCo FGD Costs)
Current NSPS . 0.6 Ib .
(Baseline)0 0.2 Ib Floor0 Uniform Ceiling0 0.6 Ib Floor0
Regional power-plant S02
emissions (10 tons)
Northeast 1.96 1.75 1.85 1.79
Southeast 7.92 7.09 7.25 7.02
North Central 7.11 6.93 6.89 6.99
West South Central 2.67 1.75 2.08 1.80
Mountain 0.63 0.53 0.57 0.55
Pacific 0.49 0.29 0.40 0.34
Total 20.8 18.3 19.1 18.5
National S02 emissions from
cool-fired plants (10 tons)
SIP-regulated plants 13.58 13.91 13.65 13.92
NSPS-regulated plants 1.54 1.53 1.53 1.54
RNSPS-regulated plants 3.92 1. 10 2.19 1.26
Cool consumption ( I OISBtu/yr) 19.5 20.0 19.8 19.9
National overage
lbS02/IO*Btu
SlP-regulated plants 2.60 2.72 2.72 2.70
NSPS-regulated plants 1.20 1.20 1.20 1.20
RNSPS-regulated plants 1.20 0.30 0.60 0.35
° Current NSPS: l^lbSCWIO Btu, no mandatory percentage removal, annual average.
b September 1978 proposed standard: 1.2 Ib SO,/ 10 Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib S0,/I06
floor with three-doy-per-month exemption. * *
c 33 percent removal, 0.6 Ib ceiling, annual average.
d Equivalent to b, but with 0.6 Ib S02/I06 floor, 24-hour standard.
157
-------
Tcfcle F-2
USM Emission Projections, 1990
(TVA FGD Costs)
Current NSPS
(Baseline)0
0.2 Ib Floor
0.5 Ib Ceiling.
90% Removal
0.6 Ib ,
Uniform Ceilingd
Regional power-plant SO,
emissions(l06tons)
Northeast
Southeast
North Central
West South Central
Mountain
Pacific
Total
1.86
7.55
7.03
2.72
0.62
0.49
20.3
1.76
6.87
6.67
1.87
0.53
0.32
18.0
1.69
6.81
6.54
1.72
0.52
0.30
17.6
1.73
6.97
6.59
2.05
0.57
0.40
18.3
National SO, emissions from
coal-fired plants (I0b tons)
5 IP-regulated plants
NSPS-reguloted plants
RNSPS-regulated plants
Cool consumption (10 Btu/yr)
12.83
1.67
4.13
19.4
12.93
1.65
1.68
19.6
13.12
1.64
1.10
19.6
12.84
1.56
2.24
19.5
National average
lbS02/IObBtu
SIP-regulated plants
NSPS-regulated plants
RNSPS-regulated plants
2.60
1.20
1.20
2.73
1.20
2.74
1.20
0.30
2.72
1.20
0.60
Current NSPS: 1.2 Ib SO,/10 Btu, no mandatory percentage removal, annual average.
September 1978 proposed standard: 1.2 Ib S0,/I0 Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib SO,/I06
floor with three-day-per-month exemption. i
90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual average.
158
-------
Table F-3
USM Emission Projections, 1995
(PEDCoFGD Costs)
Current NSPS . 0.6 Ib
(Baseline) 0.2 Ib Floor" Uniform Celling0 CUIbFloord
Regional power-plant SO,
emissions (10° tons)
Northeast 2.11 (.69 1.82 1.68
Southeast 8.54 7.01 7.46 7.04
North Central 7.51 6.95 7.12 7.19
West South Central 3.19 1.78 2.29 1.85
Mountain 0.76 0.59 0.68 0.63
Pacific 0.66 0.30 0.51 0.38
Total 22.8 18.3 19.9 18.8
National SO,eml*siogs from
cool-fired plants (10° tons)
SIP-regulated plants 13.13 13.45 13.06 13.67
NSPS-regulated plants 1.50 1.51 1.50 1.52
RNSPS-regulated plants 6.74 1.94 3.87 2.15
Coal consumption ( 10 158tu/yr) 24.3 25.1 24.6 24.9
National average
^
0
b
SIP-regulated plants
NSPS-regulated plants
RNSPS-regulated plants
2.49
1.20
1.20
Current NSPSt 1 .2 Ib SOj/ 10* Btu, no mandatory percentage
September 1978 proposed standard: 1.2 Ib SO,/ 10* Btu, 85
floor with three-day-per-month exemption.
2.77.
1.20
0.29
removal
percent
2
1
0
.76
.20
.60
, annual average.
SOj removal, 24-hour
2.
1.
0.
average; 0.2 Ib
65
20
35
so2/io*
c 33 percent removal, 0.6 Ib ceiling, annual average.
d Equivalent to b, but with 0.6 Ib SCy 10* floor, 24-hour standard.
159
-------
Table F-*
USM Emission Projections, 1995
(TVA FGD Costs)
Regional power-plant SO,
emissions (IO6 tons) t
Northeast
Southeast
North Central
West South Central
Mountain
Pacific
Total
Current NSPS
(Baseline)0
0.2 Ib Floor0
1.98
8.01
7.35
3.25
0.75
0.67
22.0
1.68
6.82
6.36
1.98
0.60
0.34
17.8
0.5 Ib Ceilina
90% Removal
1.54
6.59
6.04
1.74
0.58
0.30
16.8
0.6 Ib .
Uniform Ceiling*3
1.65
7.01
6.63
2.19
0.58
0.60
18.7
National SO, emissions from
coal-fired plants (10° tons)
SIP-reguloted plants
NSPS-regulofed plants
RNSPS-regulated plants
Coal consumption (10 Btu/yr)
11.82
1.64
7.13
24.1
11.66
1.64
3.07
24.4
11.78
1.66
2.00
24.4
11.87
1.44
3.98
24.3
National average
lbS02/»0*Btu
SIP-regulated plants
NSPS-reguloted plants
RNSPS-reguloted plants
2.50
1.20
1.20
2.78
1.20
0.47
2.75
1.20
0.31
2.75
1.20
0.60
Current NSPS: 1.2 Ib SO?/10 Btu, no mandatory percentage removal, annual average.
September 1978 proposed standard! 1.2 Ib SO,/10 Btu, 85 percent SO, removal, 24-hour overage; 0.2 Ib S0,/I06
fl«k«h» ...t*L& *WBA& ^1^.. _.._.. *J- - . , ^tiT .. " £
floor with three-doy-per-month exemption.
90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual average.
160
-------
TdbfeF-5
USM Cost Projections, 1990
(PEOCoFGD Costs)
Current NSPS°
(Baseline)
0.6 Ib
0.2 Ib Floorb Uniform Ceiling0 0.6 Ib Floord
Average monthly residential
bill ($ 1975)
Present value of
total utility expenditures
(10*1975$)
Cost of SO, reduction
(1975 $/tori)
$ 46.36
683.77
$ 48.24
692.34
2,174
$ 47.46
688.49
1,900
$ 47.82
690.83
1,824
° Current NSPS: 1.2 Ib SOj/IO Btu, no mandatory percentage removal, annual average.
September 1978 proposed standard: 1.2 Ib SO2/IO Btu, 85 percent SO2>emoval, 24-hour average; 0.2 Ib
floor with three-day-per-month exemption.
c 33 percent removal, 0.6 Ib ceiling, annual average.
d Equivalent to b, but with 0.6 Ib SO2/106 floor, 24-hour standard.
-------
Table
USM Cast Projections, 1990
(TVA FGD Costs)
Current NSPS . 0.5 Ib Ceilina 0.6 Ib .
(Baseline)0 0.2 Ib Floor0 90% RemovaF Uniform Ceilingd
ON
NJ
Average monthly residential
bill ($ 1975)
Present value of
total utility expenditures
1975$)
Cost of SO, reduction
(l975$/tori)
$ 44.98
673.88
$ 45.87
677.5
1,155
$ 46.02
678.17
1,146
$ 45.69
676.63
1,031
a Current NSPS: 1.2 Ib SCL/10 Btu, no mandatory percentage removal, annual average.
b September 1978 proposed standard: 1.2 Ib SO2/I06 Btu, 85 percent SO2 removal, 24-hour average; 0.2 Ib SCWIO6
floor with three-day-per-month exemption.
c 90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual average.
-------
Tdble F-7
USM Cost Projections, 1995
(PEDCo FGD Costs)
o\
CO
Average monthly residential
bill (1975$)
Present value ofjotal utility
expenditures (NT 1975$)
Cost of SO, reduction
(1975 $/tori)
Pollution control investment6
(1983-2000) (I09 1975 $)
Current NSPS
(Baseline)0
$ 54.68
819.17
40.1
0.2 Ib Floorb
$ 57.37
(4.9%)
832.37
(1.6%)
1,591
+41.7
(104%)
0.6 Ib
Uniform Ceiling0
$ 56.21
(2.8%)
826.21
(0.8%)
1,375
+27.4
(68%)
0.6 Ib Floord
$ 57.02
(4.2%)
830.4
(1.4%)
1,531
+28.9
(72%)
Note; Numbers in parentheses indicate percentage change "from baseline.
a Current NSPS: 1.2 Ib SCWIO Btu, no mandatory percentage removal, annual average.
b September 1978 proposed standard: 1.2 Ib SO^/IO Btu, 85 percent SO2 removal, 24-hour average; 0.2 Ib SC>2/IO
floor with three-day-per-month exemption.
c 33 percent removal, 0.6 Ib ceiling, annual average.
d Equivalent to b, but with 0.6 Ib SO2/I06 floor, 24-hour standard.
e Assumes wet scrubbing technologies.
-------
Table F-8
USM Cost Projections, 1995
(TVA FGD Costs)
Average monthly residential
bill (1 975 $/month)
Present value of total q
utility expenditures (10* 1975 $)
Cost of SOj reduction
reduction (T975 $/ton)
Pollution control investment6
(1983-2000) (I09 1975$)
Current NSPS
(Baseline)0
$ 52.67
805.07
33.9
0.2 Ib Floorb
$ 53.99
(2.5%)
811.0
(0.7%)
900
+ 17.9
(53%)
0.5 Ib Ceiling.
90% Removar
$ 54.61
(3.6%)
812.07
(0.9%)
831
+ 19.9
(59%)
0.6 Ib .
Uniform Ceiling
$ 53.75
(2.1%)
809.73
(0.6%)
900
+ 13.6
(40%)
Note; Numbers in parentheses indicate percentage change from baseline.
a Current NSPS: 1.2 Ib SC^/IO Btu, no mandatory percentage removal, annual average.
September 1978 proposed standard: 1.2 Ib SO^/IO Btu, 85 percent SO2 removal, 24-hour average; 0.2 Ib SO2/IO
floor with three-day-per-month exemption.
c 90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual average.
e Assumes wet scrubbing technologies.
-------
Table F-9
USM Fuel Impact Projections, 1990
(PEDCo FGD Costs)
Current NSPS
(Baseline)0
0.2 Ib Floorb
0.6 Ib
Uniform Ceiling
0.6 Ib Floorc
Utility coal production
by region (10 tons/yr)
Appalachia
Midwest
Northern Great Plains
West and Gulf Coast
National
382
74
362
167
988
437
81
214
275
1023
78
250
233
990
379
81
344
183
1003
Western coal shipped
east of the Mississippi River
(IO6 tons/yr)
167
79
112
168
Utility fossil fuel
consumption
Coal(IOl5Btu/yr)
OiKlo'/Btu/yr)
(I06bbls/day)
CoqLtransportation
(lO^Btu/yr)
Total fossil fuel consumption
(lO^Btu)
19.5 20.0 19.8 19.9
3.95 3.95 3.90 3.90
1.78 1.79 1.76 1.76
0.26 0.185 0.205 0.261
23.8 24.2 23.9 24.1
a Current NSPS: I.ZIbSCWIO Btu, no mandatory percentage removal, annual average.
b September 1978 proposed standard: 1.2 Ib S0,/I06 Btu, 85 percent SO, removal, 24-hour average; 0.2 tb SO,/I06
floor with three-doy-per-month exemption. * £
c 33 percent removal, 0.6 Ib ceiling, annual average.
6 Equivalent to b, but with 0.6 Ib S02/I06 floor, 24-hour standard.
e Includes only coal produced for electric utility consumption.
165
-------
Table F-10
USM Foci Impact Projections, 1990
(TVA FGD Costs)
Utility coal production
by region (10° tons/yr)e
Appalachia
Midwest
Northern Great Plains
West and Gulf Coast
National
Western coal shipped
east of the Mississippi River
(I06tons/yr»
Current NSPS
(Baseline)0
0.2 Ib Floor0
0.5 Ib Ceiling.
90% Removal
433
73
197
269
987
435
90
172
276
990
435
74
191
274
990
60
0.6 Ib d
Uniform Ceiling
436
91
172
277
991
41
Utility fossil fuel
consumption
Coal flOISBtu/yr)
Oildo'/Btu/yr)
(I06bbls/day)
CoqLtransportation
(IOl:>Btu/yr)
Total fossil fuel consumption
^
19.4
3.84
1.73
0.163
23.4
19.6
3.90
1.76
0.159
23.6
19.5
3.91
1.76
0.160
23.6
19.6
3.90
1.76
0.160
23.6
Current NSPS: 1.2 Ib SO,/10 Btu, no mandatory percentage removal, annual average.
September 1978 proposed standard: 1.2 Ib SO?/10* Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib S0,/I06
floor with three-day-per-month exemption. t
90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual overage.
Includes only coal produqpd for electric utility consumption.
\66
-------
Table F-11
USM Fuel Impact Projections, 1995
(PEDCo FGD Costs)
Current NSPS
(Baseline)0
0.2 Ib Floor"
0.6 Ib
Uniform Ceiling0
0,6 Ib Floor0
Utility coal production
by region (10 tons/yr)
Appalachia
Midwest
Northern Great Plains
West and Gulf Coast
National
447
68
522
210
1250
540
80
274
394
1309
504
80
320
321
1247
460
80
477
231
1270
Western cool shipped
east of the Mississippi River
(I06 tons/yr)
240
217
Utility fossil fuel
consumption
Coal(IOISBtu/yr)
24.3
25.1
24.6
24.9
OiKIO'/Btu/yr)
U06bbls/day)
CoqLtransportation
d07iBtu/yr)
Total fossil fuel consumption
(lO^Btu)
3.1
1.42
0.353
27.8
3.096
1.40
0.226
28.4
3.11
1.41
0.254
28.0
3.098
1.39
0.340
28.3
0 Current NSPS: 1.2 Ib SOj/IO Bfu, no mandatory percentage removal, annual overage.
b September 1978 proposed standard: 1.2 Ib S0?/I06 Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib S0,/I0£
floor with three-day-per-month exemption. l
c 33 percent removal, 0.6 Ib ceiling, annual average.
d Equivalent to b, but with 0.6 Ib SC>2/I06 floor, 24-hour standard.
* Includes only coal produced for electric utility consumption.
167
-------
TobleF-12
USM Fuel Impact Projections, 1995
(TVA FGD Costs)
Current NSPS
(Baseline)0
0.2 Ib Floorb
0.5 Ib Ceiling.
90% Remover
0.6 Ib .
Uniform Ceiling
Utility coal production
by region (10 tons/yr)e
Appalachia
Midwest
Northern Great Plains
West and Gulf Coast
National
Western coal shipped
east of the Mississippi River
(I06tons/yr)
529
69
255
262
1236
72
532
101
210
376
1243
33
532
74
242
375
1247
533
101
211
378
1247
33
Utility fossil fuel
consumption
Coal(IOISBtu/yr)
Oildo'/Btu/yr)
(I06bbls/day)
CoqLtransportation
(IO'3Btu/yr)
Total fossil fuel consumption
(ID"3 Btu)
24.1
3.08
1.39
0.197
27.2
24.4
3.09
1.4
0.195
27.5
24.3
3.07
1.39
0.194
27.4
24.4
3.09
1.40
0.196
27.5
Current NSPS: 1.2 Ib SCWIO Btu, no mandatory percentage removal, annual average.
b September 1978 proposed standard* 1.2 Ib S0,/I0* Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib SCVIO6
floor with three-day-per-month exemption.
c 90 percent removal, 0.5 Ib ceiling, annual average.
33 percent removal, 0.6 Ib ceiling, annual average.
' Includes only coal produced far electric utility consumption.
168
-------
APPENDIX G
INPUT ASSUMPTIONS FOR THE PHASE 3 ANALYSIS
169
-------
APPENDIX G
INPUT ASSUMPTIONS FOR THE PHASE 3 ANALYSIS*
Electricity Peak and Average Growth Rates (%/yr)
1975- 1985
1985- 1995
Nuclear Capacity (GW)
1985
1990
1995
OilPrices(l975$/bbl)
1985
1990
1995
General Inflation Rate (GIR) (%/yr)
Coal Transportation Cost Escalation
Coal-Mining Labor Cost Escalation
4.8
4.0
99
165
228
12.90
16.40
21.00
5.5
1.8% +GIR 1975-1985,
GIR 1985-1995
1% + GIR
* 7
Specified by the Joint EPA/DOE Working Group.
171
-------
APPENDIX H
PROJECTED NATIONAL ELECTRIC GENERATING CAPABILITY AND
ELECTRICITY GENERATION BY FUEL, 1974-2000
173
-------
APPENDIX H
PROJECTED NATIONAL ELECTRIC GENERATING CAPABILITY AND
ELECTRICITY GENERATION BY FUEL, 1976-2000
Figure H-l Projected National Electric Generating Capability
Figure H-2 Projected National Electricity Generation by Fuel
Table H-l Projected National Generating Capacity
175
-------
Figure H-1
Utility Simulation Model
Projected National Electric Generating Capability
Total Net Capability
1976 1980
1985 1990
YEAR
1995
1200
Combustion Turbine plus CC and Other
Hydro plus Geothermal
2000
176
-------
Figure H-2
Utility Simulation Model
Projected National Electricity Generation
1976 1980
Total Generation
by Fuel
Hydro plus Geothermat
I I
1985 1990
YEAR
1995
4800
4000
3200
2400
-1600
- 800
2000
177
-------
Table H-l
Projected National Generating Capacity
(Net Capability, Gigawatts)
Coal
Nuclear
Oil/gas
Hydro and pumped hydro
Combustion turbine and
other
Combined cycle
Geothermal
Total
1980
234.4
60.3
162.5
78.2
67.5
3.0
1.0
606.8
1985
283.0
99.5
141.4
84.9
88.3
6.4
1.9
705.4
1990
383.3
164.3
114.0
92.9
93.6
7.7
3.0
858.8
1995
489.9
227.8
103.4
101. 0
98.6
7.7
4.0
1,032.4
2000
629.4
294.6
91.5
110.4
104.4
7.7
5.1
1,243.1
Current NSPS, higher FGD costs; capacity mixes for other scenarios
are within a few percent of each other.
178
-------
APPENDIX I
USM PROJECTIONS FOR 1995 UNDER
THE FINAL PROMULGATED RNSPS
179
-------
APPENDIX I
USM PROJECTIONS FOR 1995 UNDER
THE FINAL PROMULGATED RNSPS
On May 25, 1979 the EPA Administrator announced the final revised New Source
Performance Standards for electric utilities. This appendix briefly compares the
final standard with two potential RNSPS options investigated in this report. This
comparison is followed by an EPA description of the final standard.
Projected Impacts of the Final RNSPS
There are two principal changes between our Phase 3 projections and our
projection of the implications of the final RNSPS.
I. The definition of the final RNSPS. For coal plants "SO,
emissions to the atmosphere are limited to 1.20 ID
SCWmillion Btu heat input, and a 90 percent reduction in
potential SO, emissions is required at all times except
when emissions to the atmosphere are less than 0.60 Ib
SCWmillion Btu heat input. When SO, emissions are less
than 0.60 Ib SO^/million Btu heat input, a 70 percent
reduction in potential emissions is required. Compliance
is determined on a continuous basis by using continuous
monitors to obtain a 30-day rolling average."*
As can be seen from Table I-1 in the text, the final
RNSPS is less stringent than the September 1978 proposed
full scrubbing option, but is more stringent than the
potential RNSPS with a 0.6 Ib SO,/10°^ Btu uniform
ceiling requiring 33 percent removal.
2. The use of dry scrubbing for FGD. Dry scrubbing technol-
ogies are an important element of the final RNSPS. For
lower-sulfur coals dry scrubbing technologies should be
less expensive than wet scrubbing processes. A new cost
and performance model for dry scrubbing was developed
in order to analyze the final RNSPS and to carry out
comparisons with lime, limestone, and magnesium-oxide
wet scrubbing technologies.
* EPA Summary of Standards (Fact Sheet), May 25, 1979.
181
-------
Table I-1 presents Utility Simulation Model projections for 1995 under the final
promulgated RNSPS.
Because dry scrubbing technologies were not assumed for the Phase 3 analyses,
the projections for the final RNSPS are not strictly comparable to the Phase 3
projections. With this caveat, Tables 1-2 and 1-3 present a general comparison of
the projected impacts of the final RNSPS and the two RNSPS options contrasted
at the end of Section 2.
The following observations are pertinent:
National SO^ emissions are higher under the final RNSPS
than under the September 1978 proposed RNSPS, which
required 90 percent annual removal on all coals. This is
principally due to the lower 70 percent removal require-
ment under the final RNSPS, which applies to low-sulfur
coals with less than about 0.9 Ib S/IO Btu. These coals
will predominantly be used in the western U.S. Emissions
under the final RNSPS wilt be lower than those projected
under the 0.6 Ib SCWIO Btu uniform ceiling partial
scrubbing option and will be substantially lower than
under a continuation of the current NSPS.
Dry scrubbers would also be cheaper in many cases for
meeting SIP standards. The extent to which dry scrubbing
can be used at all on SIP-regulated plants will depend on
SIP compliance schedules, and the availability and accep-
tance of dry scrubbing.
The lower cost of dry scrubbers is reflected in cumulative
Pollution Control Investment, which is estimated to be
$48 billion (1975$) from 1983-2000. The corresponding
investments for Phase 3 results using solely wet scrubbing
are:
v
$40 billion under the current NSPS
$82 billion under the September 1978 proposed RNSPS
$67 billion under the 0.6 uniform ceiling with 33 percent
removal.
These pollution control investment figures include all
pollution controls. PEDCo FGD costs were used for wet
scrubbing; EPA costs for dry scrubbing.
182
-------
The lower cost of dry scrubbers results in lower levels of
projected Eastern and Gulf Coast coal production relative
to the wet scrubbing scenarios. Correspondingly,
Northern Great Plains production increases. This occurs
because low-sulfur Western coals will comply with the
RNSPS at 70 percent removal using dry FGD technologies,
increasing the attractiveness of these low-sulfur coals.
The average monthly electricity bill is lower under the
promulgated standard than for any alternative RNSPS
analyzed using only wet scrubbing and PEDCo FGD costs.
For example, under the September 1978 proposed standard
the national average monthly electricity bill in 1995 was
projected to be $57.37; under the final RNSPS it is $55.06.
The remainder of this Appendix quotes the EPA "Summary of Standards" released
upon the announcement of the final revised NSPS, May 25, 1979.
SUMMARY OF STANDARDS
Applicability
The standards apply to electric utility steam generating units capable of firing
more than 250 million Btu/hour heat input of fossil-fuel, for which construction
is commenced after September 18, 1978.
SO2 Standards
The S02 standards are as follows:
I. Solid and solid-derived fuels (except solid solvent refined
coal): SCU emissions to the atmosphere are limited to
1.20 Ib/milfion Btu heat input , and a 90 percent reduction
in potential 502 emissions is required at all times except
when emissions to the atmosphere are less than
0.60 Ib/million Btu heat input. When S0? emissions are
less than 0.60 Ib/million Btu heat inpur, a 70 percent
reduction in potential emissions is required. Compliance
is determined on a continuous basis by using continuous
monitors to obtain a 30-day rolling average.
183
-------
Table I-1
USM Projections far 1995 under the Final Promulgated RNSPS
National S02 Emissions (I06 tons)
Coal
SIP 14.2
NSPS 1.3
RNSPS 2.9
Oil 1.2
Total (including turbines) 19.7
Regional SC^ Emissions from All Power Plants (10 tons)
New England 0.22
Mid Atlantic 1.28
South Atlantic 4.29
East North Central 5.00
West North Central 2.22
East South Central 3.46
West South Central 2.14
North Mountain 0.20
South Mountain 0.47
Pacific 0.46
Cumulative Total Utility Investment, 1983 onward in
Billions of 1975$ 566.5
Cumulative Pollution Control Investment, 1983 onward in
Billions of 1975$ 47.9
Present Value of Total Utility Costs
Billions of 1975$ 815.5
National Average Household Monthly Electricity Bill
(1975$) 55.06
Utility Coal Production (I06 tons)
Appalachia 441.8
Midwest 87.8
Gulf Coast 74.0
Northern Great Plains 431.6
Rocky Mountains 164.9
Other 22.7
National 1,222.8
Western Coal Shipped East of Mississippi River (10* tons) 192
184
-------
Table I-1 (Continued)
Annual Oil Consumption CIO15 Btu) 3.1
(I06bbl/day) 1.51
Scrubber Capacities (GW)
New England 2.8
Mid Atlantic 46.1
South Atlantic 56.3
East North Central 67.9
West North Central 22.7
East South Central 21.8
West South Central 78.1
North Mountain 5.2
South Mountain 19.6
Pacific 19.1
Total 339.6
Total SIP 56.0
Total NSPS 2/4.6
Total RNSPS 259.0
Total Coal Capacity (GW) 492.9
Total Nuclear Capacity (GW) 228.0
Total Oil Steam Capacity (GW) 103.4
Total System Size (GW) 1,030.5
Total Generation (IO9 kWh) 4,469.8
185
-------
Definition of Regions for Emission
Summary Tables
East
New England (ME, CT, Rl, MA, NH, VT),
Middle Atlantic (NY, NJ, PA), and
South Atlantic (DE, MD/DC, VA, WV, NC, SC, GA, FL)
M idwest
East North Central (Wl, Ml, IL, IN, OH),
East South Central (KY, TN, MS, AD, and
West North Central (ND, SD, NE, KS, IA, MO, MN)
West South
Central
West South Central (TX, OK, AR, LA)
West
Mountain (ID, MT, WY, NV, UT, CO, AZ, NM), and
Pacific (WA, OR, CA).
186
-------
Table 1-2
Utility Simulation Model Emission Impact Projections, 1995
May 1979
Current NSPS k 0.6 Ib Promulgated
(Baseline)0 0.2 Ib Floor6 Uniform Ceiling0 RNSPSd
Regional powtr-plant SO,
emissions (10° tons)
East 7.17 5.83 6.28 5.79
Midwest 10.99 9.82 10.12 10.68
West South Central 3.19 1.78 2.29 2.14
West 1.41 0.89 1.19 . 1.12
Total 22.8 18.3 19.9 19.7
National SO, emissions from
coal-fired plants (10 tons)
SlP-regulated plants 13.13 13.45 13.06 14.2
NSPS-regulated plants 1.50 1.51 1.50 1.31
RNSPS-regulated plants 6.74 1.94 3.87 2.85
Coal consumption (IOISBtu/yr) 24.3 25.1 24.6 24.4
National average
lbS02/IO*Btu
SIP-reguloted plants 2.49 2.77 2.76 2.80
NSPS-regulated plants 1.20 1.20 1.20 1.20
RNSPS-regulated plants 1.20 0.29 0.60 0.47
a Current NSPS: 1.2 Ib S0210 /Btu, no mandatory percentage removal, annual average.
September 1978 proposed RNSPS: 1.2 Ib SO,/10 Btu, 85 percent SO, removal, 24-hour average; 0.2 Ib
SOj/IO floor with three-day-per-month exemption.
c 33 percent removal, 0.6 Ib ceiling, annual average.
The May 1979 promulgated RNSPS projection utilizes dry scrubbing technologies as well as wet. Hence, the
results are not strictly comparable to the other RNSPS projections which assumed only wet scrubbing processes.
187
-------
Table 1-3
Utility Simulation Model Cast Projections, 1995
Current NSPS
(Baseline)0
0.6 Ib
May 1979
. u.o tu Promulgated
0.2 Ib Floor0 Uniform Ceiling0 RNSPSd
Average monthly residential
bill (1975$)
Present value ofjotal utility
expenditures (I0y 1975$)
Cost of SO, reduction
(l975$/tori)
Pollution control investment
(1 983-2000) (I(T 1975$)
$ 54.68 $ 57.37
(4.9%)
819.17 832.37
(1.6%)
1,591
40.1 81.7
$ 56.21
(2.8%)
826.21
(0.8%)
1,375
67.5
$ 55.06
815.5
47.9
Note: Numbers in parentheses indicate percentage change from baseline.
° Current NSPS: l^lbSCWlO Btu, no mandatory percentage removal, annual average.
D September 1978 proposed RNSPS: 1.2 Ib SO2/I06 Btu, 85 percent SO2 removal, 24-hour average; 0.2 Ib
SO-/10 floor with three-day-per-month exemption.
f%
33 percent removal, 0.6 Ib ceiling, annual average.
The May 1979 promulgated RNSPS projection utilizes dry scrubbing technologies as well as wet. Hence, the
results are not strictly comparable to the other RNSPS projections which assumed only wet scrubbing processes.
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2. Gaseous and liquid fuels not derived from solid fuels: ^
emissions into the atmosphere are limited to
0.80 Ib/million Btu heat input, and a 90 percent reduction
!n potential 502 em'ss^ons 's required. The percent
reduction requirement does not apply if SO2 emissions
into the atmosphere are less than 0.20 Ib/million Btu heat
input. Compliance is determined on a continuous basis by
using continuous monitors to obtain a 30-day rolling
average.
3. Anthracite coal: electric utility steam generating units
firing anthracite coal alone are exempt from the percent-
age reduction requirement of the SO, standard but are
subject to the 1.20 Ib/million Btu heat input emission limit
on a 30-day rolling average, and all other provisions of
the regulations including the pariculate matter and NO
standards.
4. Noncontinental areas: Electric utility steam generating
units located in noncontinental areas (State of Hawaii, the
Virgin Islands, Guam, American Samoa, the Common-
wealth of Puerto Rico, and the Northern Mariana Islands)
are exempt from the percentage reduction requirement of
the S02 standard but are subject to the applicable SO2
emission limitation and all other provisions of the regula-
tions including the particulate matter and NO standards.
5. Resource recovery facilities: Resource recovery facili-
ties that fire less than 25 percent fossil-fuel on a quar-
terly (90-day) heat input basis are not subject to the
percentage reduction requirements but are subject to the
1.20 Ib/million Btu heat input emission limit. Compliance
is determined on a continuous basts using continuous
monitoring to obtain a 30-day rolling average.
Particulate Matter Standards
The particulate matter standard limits emissions to 0.03 Ib/million Btu heat
input. The opacity standard limits the opacity of emissions to 20 percent
(6-minute average).
189
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NOX Standards
The NO standards limit emissions according to fuel types as follows:
f\
I. 0.20 Ib/million Btu heat input from the combustion of any
gaseous fuel, except gaseous fuel derived from coal;
2. 0.30 Ib/million Btu heat input from the combustion of any
liquid fuel, except shale oil and liquid fuel derived from
coal;
3. 0.50 Ib/million Btu heat input from the combustion of
subbituminous coal, shale oil, or any solid, liquid, or
gaseous fuel derived from coal;
4. 0.80 Ib/million Btu heat input from the combustion in a
slag tap furnace of any fuel containing more than 25 per-
cent, by weight, lignite which has been mined in North
Dakota, South Dakota, or Montana;
5. Combustion of a fuel containing more than 25 percent, by
weight, coal refuse is exempt from the NO standards and
monitoring requirements; and
6. 0.60 Ib/million Btu heat input from the combustion of any
solid fuel not specified under (3), (4), or (5).
Continuous compliance with the NO standards is required, based on a 30-day
J\
rolling average.
Emerging Technologies
The standards include provisions which allow the Administrator to grant
commercial demonstration permits to allow less stringent requirements for the
initial full-scale demonstration plants of certain technologies. The standards
include the following provisions:
I. Facilities using SRC I would be subject to an emission
limitation of 1.20 Ib/million Btu heat input, based on a 30-
day rolling average, and an emission reduction require-
ment of 85 percent, based on a 24-hour average.
190
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However, the percentage reduction allowed under a
commercial demonstration permit for the initial full-scale
demonstration plants using SRC I would be 80 percent
(based on a 24-hour average). The plant producing the
SRC I would monitor to insure that the required percent-
age reduction (24-hour average) is achieved and the power
plant using the SRC I would monitor to ensure that the
l.20lb/million Btu heat input limit (30-day rolling
average) is achieved.
2. Facilities using fluidized bed combustion (FBC) and coal
liquefaction would be subject to the emission limitation
and percentage reduction requirement of the S02 stan-
dard and to the particulate matter and NO standards.
However, the reduction in potential S02 emissions
allowed under a commercial demonstration permit for the
initial full-scale demonstration plants using FBC would be
85 percent (based on a 30-day rolling average). The NO
emission limitation allowed under a commercial demon-
stration permit for the initial full-scale demonstration
plants using coal liquefaction would be 0.70 Ib/million Btu
heat input, based on a 30-day rolling average.
3. No more than 15,000 MW equivalent electrical capacity
would be allotted for the purpose of commerical demon-
stration permits. The capacity will be allocated as
follows:
Equivalent
Electrical
Capacity
Technology Pollutant MW
Solid solvent-refined coal S02 5,000- 10,000
Fluidized bed combustion
(atmospheric) S02 400 - 3,000
Fluidized bed combustion
(pressurized) S02 200 - 1,200
Coal liquefaction NOV 750 - 10,000
/\
SO2 Standard
Standard is based on the performance of well designed,
operated, and maintained wet lime/limestone S02
scrubbing system.
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The minimum requirement of 70 percent removal provides
an opportunity for the full development of dry SC^
removal systems.
Sulfur removed through coal washing or in the fly ash and
bottom ash is also credited toward achievement of the
standard.
Lime/limestone wet scrubbing is capable of 90 percent
SO2 reduction on all coals and up to 95 percent SCU
reduction on low-sulfur coals.
Regenerate wet scrubbing, which is capable of higher
percent SO^ reductions at added cost, has also been
demonstratea and is applicable where limited (and area is
available for sludge disposal.
Several wet scrubbing systems have demonstrated high
percentages of SOj reduction. These are:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Unit
Columbus & So. Ohio
Conesville Station
No. Indiana Publ. Serv.
Mitchell Station
Tennessee Vol. Auth.
Shawnee Station
Kansas Power & Light
Lawrence Station
Louisville Gas & Elec.
Cane Run Station
Arizona Publ. Serv.
Cholla Station
Southern California Ed.
Mohave Station
Pennsylvania Power
Bruce Mansfield Station
Elec. Power Devel.
Takasago Station
Elec. Power Devel.
Isogp Station
Size
(MW)
400
115
10
I2S
178
115
170
800
500
530
Type
Lime
Regen.
Lime
Limestone
Lime
Limestone
Limestone
Limestone
Limestone
Limestone
Location
U.S.A.
U.S.A.
U.S.A.
U.S.A.
U.S.A.
U.S.A.
U.S.A.
U.S.A.
Japan
Japan
Percent
Reduction
89.2
89.2
88.6
96.6
89.8
92
95
85.3
93
93
192
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Size Percent
Unit (MW) Type Location Reduction
11. Elec. Power Devel.
Takehara Station 256 Limestone Japan 93
12. Mitsui Aluminum
Miiki Station 175 Limestone Japan 90
Water and solid waste products of wet scrubbing can be
managed in an environmentally sound manner.
Dry scrubbing is considerably less complex than
lime/limestone wet scrubbing systems.
Dry scrubbing involves contacting 502- laden *'ue 9as
an alkaline solution in a spray dryer which simultaneously
drys the liquid and allows absorption of the SO^ by the
alkaline reagent. The dry solid reaction produce, along
with fly ash, is collected in a conventional boghouse or
electrostatic precipitator.
Five commercial dry SO^ control systems are on order;
three for utility boilers and two for industrial applica-
tions. The utility units will commence operation in the
1 981-1 982 time frame.
The utility boilers are:
Size Percent
Unit (MW) Reduction
I. Otter Trail Power
Coyote//1, N.D. 400 50
2. Basin Electric
Laramie River #I, Wyoming 550 85
3. Basin Electric
Antelope Valley tf I, N,D. 455 70
All utility units are on low-sulfur high-alkaline coal.
The industrial applications are:
193
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Size Percent
Unit (SCFM) Reduction
I. Celanese Corporation
Cumberland Plant, Md. 57,700 70
2. Struthmore Paper Company
Woronoco Plant, Mass. 22,000 N/A
Successful testing of the spray dryer process at the pilot
scale has been performed. The data suggest that at a
70 percent sulfur removal requirement, dry systems offer
, major cost advantages over lime/limestone wet scrubbers
for low-sulfur coal applications.
Annual revenue requirements are estimated at one-third
less than corresponding wet lime scrubbing assuming a
subbituminous (0.7 percent sulfur) coal and a 70 percent
control requirement.
Dry and wet costs are approximately equal for a 2 percent
sulfur coal.
Other benefits:
Reduction in consumptive water use
Potential for higher reliability due to simpler
process
Substantial reduction in energy losses since reheat
requirement is eliminated
- Production of a dry solid waste material. Although
larger in quantity, it can be more easily disposed of
than wet scrubber sludge
Participate Matter Standard
Standard is based on performance of well designed, oper-
ated, and maintained electrostatic precipitator (ESP) or
baghouse control systems.
ESPs were initially installed by the utility industry in the
1920s, with widespread use since the 1950s.
ESPs with sufficient collection area can achieve the
standard on both high- and low-sulfur coal applications.
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On Western, low-sulfur coal applications, however, ESPs
must be much larger due to the electrical resistivity of
the fly ash, making the equipment more expensive.
Baghouses (fabric filters), which are relatively new to
utility applications, offer a lower cost alternative to ESPs
on Western, low-sulfur coals.
Baghouses, however, are not new to large industrial and
boiler applications. They have been used in industrial
applications for more than 20 years.
To date, most baghouses have been installed on small
stations, but this is changing rapidly as utilities order
baghouses for larger installations.
Since proposal, a 350-MW unit equipped with a baghouse
has started operation and test results show that it meets
the new standard.
NO Standards
^
The NO standards can be achieved with the use of
combustfon modification. This technique reduces the
formation of nitrogen oxide gases in the furnace where
the fuel is burned. No external control device, such as a
stack-gas scrubber, is required.
In developing the NO standards, EPA tested six well-
controlled electric utilfty power plants. Two of the plants
burned Eastern bituminous coal, one burned Western
bituminous coal, and three burned Western subbituminous
coal. All of the plants had NO emission levels below the
new standards.
In addition to the EPA test data, boiler manufacturer and
electric utility test data have been obtained for a number
of coal-fired power plants, including 30 months of contin-
uously monitored NO data. Virtually all of these data
support the NO standards.
x\
Compliance with the NO standards is based on a 30-day
rolling average of emission levels. This averaging period
is intended to give boiler operators the flexibility they
need to handle conditions which occur during the normal
operation of an electric utility boiler. Some of the
conditions, such as slagging, may require elevated NOX
emission levels over short periods of time. (Slagging
195
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reduces boiler efficiency and is caused by the accumula-
tion of coal ash on the boiler tubes.)
The NO standard for bituminous coal is higher than the
NO standard for subbituminous coal due to concern over
boiler tube corrosion when bituminous coal is burned
during low-NO operation. The NOX standard for bitumi-
nous coal represents an emission level at which an elec-
tric utility boiler can operate without increasing corrosion
which can shorten the life of boiler tubes and cause
-'xoensive repairs.
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GLOSSARY OF SO2 STANDARDS TERMINOLOGY
197
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GLOSSARY OF SO2 STANDARDS TERMINOLOGY
Averoging time
Bypass
Required percentage removal
RSD
Period of time over which the emissions are
averaged. Coal sulfur content is variable, and
the maximum 24-hour emission is greater than
the maximum 30-day emission, which makes a
shorter averaging time a more stringent
requirement.
Flue gas that is not treated by the flue gas
desulfurization (FGD) system. The bypass may
be operated such that either a fixed or a
variable percentage of the flue gas is by-
passed. If the bypass is variable, it is assumed
that it will be operated to minimize cost and
maximize emissions.
An emission limit that is not to be exceeded
except as specified.
Number of days per month the ceiling can be
exceeded.
A limit that allows fuels of very low sulfur
content (e.g., natural gas, distillate oil, bio-
mass) to be burned without SO^ controls. The
floor also allows partial scrubbing of low-
sulfur coals and bypassing of unscrubbed flue
gas for reheating.
The percentage of the flue gas SOj that must
be removed unless the ceiling or the floor
controls. If the ceiling controls, a larger
portion of the $©2 must be removed; if the
floor controls, a smaller portion may be
removed.
Relative standard deviation. The RSD is equal
to the standard deviation divided by the mean
of a set of samples. For a normally distrib-
uted sample population, 95 percent of the
samples would be within two standard devia-
tions of the mean. With respect to coal sulfur
content, 90 percent of the time (the equiva-
lent of 27 days per month), it is assumed that
the measured coal sulfur content would be
within roughly + 2 standard deviations of the
mean. It is assumed that essentially all of the
samples fall below three standard deviations
199
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA 600/7-79-215
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Review of New Source Performance Standards for
C6al Fired Utility Boilers, Phase Three Report
5. REPORT DATE
.Tnpo ]Q7Q
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(s)Van Horn, A.J., G.C. Ferrell,
R.M. Brandi, R.A. Chapman
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS ,
Energy and Environmental Engineering Division
Teknekron, Inc.
2118 Milvia Street
Berkeley, California 94704
10. PROGRAM ELEMENT NO.
1NE 827
11. CONTRACT/GRANT NO.
68-01-3092
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Environmental Engineering & Technology
Office of Research and Development
Washington, DC 20460
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/ORD/17
15. SUPPLEMENTARY NOTES
This project is part of the EPA-planned and coordinated Federal Interagency
Energy/Environment R&D Program.
16. ABSTRACT
This report summarizes Teknekron1s Phase 3 study of the projected effects
of several different potential revisions to the current New Source Performance
Standards (NSPS) for sulfur dioxide (SO2> emissions from coal-fired electric
utility boilers. The revised NSPS (RNSPS) is assumed to apply to all coal-
fired units with a generating capacity of 25 megawatts or more, beginning
operation after 1982. A principal purpose of this phase of the RNSPS analysis
is to present to decision makers the critical uncertainties that will influence
utility costs, coal choices, and pollution control measures adopted by utili-i
ties in response to alternative standards. 'Answers are presented to the fol-
lowing generic questions (which are broken down into highly specific questions
in the report):
1. How will utility choices be affected by different standards and un-
certainties in key factors?
2. How well can the impacts of various full and partial scrubbing options
be distinguished?
3. What are the likely energy, economic, environmental, and resource
impacts of a revised NSPS?
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Earth Atmosphere
Combustion
Energy Conversion
Energy Cycle: Energy
Conversion
Fuel: Coal
6F 8P
10A 10B
7B 13B
97A 97F 97G
18. DISTRIBUTION STATEMENT
Release to public
19. SECURITY CLASS (jTUf Ktporrf
unelasaified
rtw. or PAGES
219
20. SECURITY CLASS (Tntspagt)
unclassified
22. PRICE
PA Form
(»-73)
«UJ. OOVIMMMNT PH1NTINO OWCt: 1980 3U-U2/60 1-3
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