United States
Environmental Protection
Agency
Office of Energy. Minerals, and
Industry
Washington DC 20460
EPA-600/7-78-155E
August 1978
Research and Development
Review of New Source
Performance Standards
for Coal-Fired
Utility Boilers
Volume I
Emissions and Non-
Air Quality
Environmental Impacts
Interagency
Energy/Environment
R&D Program
Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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REVIEW OF NEW SOURCE PERFORMANCE
STANDARDS FOR COAL-FIRED
UTILITY BOILERS
VOLUME I: EMISSIONS
AND NON-AIR QUALITY
ENVIRONMENTAL IMPACTS
March 1978
-------
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.
-------
ABSTRACT
This two volume report summarizes a study of the projected effects of several
different revisions to the current New Source Performance Standard (NSPS) for
sulfur dioxide (SO2) emissions from coal-fired utility power boilers. The revision
is assumed to apply to all coal-fired units of 25 megawatts or greater generating
capacity beginning operation after 1982. The revised standards which are
considered are: (I) mandatory 90 percent SO- removal with an upper limit on
emissions of 1.2 Ib SO- per million Btu; (2) mandatory 80 percent SO2 removal
with the same upper limit; (3) no mandatory percentage removal with an upper
limit of 0.5 Ib SO2 per million Btu. In addition, effects of revising the NSPS for
particulate emissions from the current value of O.I Ib per million BtO down to
0.03 Ib are quantified. Projections of the structure of the electric utility
industry both with and without the NSPS revisions are given out to the year 2000.
Volume I discusses air emissions, solid wastes, water consumption, and energy
requirements. Volume II discusses economic and financial effects, including
projections of pollution control costs and changes in electricity prices.
-------
PREFACE
This report is one of several volumes being submitted by Teknekron to the U.S.
Environmental Protection Agency under contract 68-01-3970, "Review of New
Source Performance Standards for Sulfur Dioxide Emissions from Coal-Fired
Steam Generators." This volume presents the emissions and non air-quality
environmental implications of alternative New Source Performance Standards as
they will apply to the U.S. electric utility industry. Volume II discusses the
economic and financial implications of the various SC>2 control alternatives
described herein and is being submitted concurrently with this volume. A third
volume discussing the air quality implications of the emissions control alternat-
ives is anticipated, as is a final volume containing a series of "issue papers"
summarizing results which bear on specific policy issues relating to EPA's
proposal to revise the current standard.
-------
CONTENTS
PAGE
PREFACE
CONTENTS "
LIST OF FIGURES '"
LIST OF TABLES iv
SUMMARY OF RESULTS vi
1.0 INTRODUCTION AND BACKGROUND l-l
I.I Base Year Data l-l
1.2 Specification of Scenarios 1-4
2.0 INDUSTRY PROJECTIONS ..... 2-1
2.1 Capacity Mix in the Base Year 2-2
2.2 Projections to 2000 2-6
3.0 AIR EMISSIONS, SOLID WASTES, WATER AND ENERGY 3-1
3.1 Baseline Emissions of SOj* NO , and Participates 3-2
3.2 Emission Changes Due to NSPS Revisions 3-10
3.2.1 Some Comments on the Alternatives _3-IO
3.2.2 Emission Data 3-11
3.3 Solid Wastes 3-22
3.4 Water Requirements 3-24
3.5 Energy Requirements . 3-30
REFERENCES 4. j
APPENDIX: Description of Teknekron's Utility Simulation Model
and Associated Data Bases A-1
-ii-
-------
UST OF FIGURES
PAGE
2-1 Projections of Electric Utility Coal Consumption 2-22
3-1 National Power-Plant SC^ Emissions
under the Baseline Scenarios 3-4
3-2 National Power-Plant Particulate Emissions
under the Baseline Scenarios 3-5
3-3 National Power-Plant NO Emissions
under the Baseline Scenarios 3-6
,3-4 National Power-Plant SCX Emissions under
Alternative Control Scenarios, Moderate Growth 3-16
3-5 National Power-Plant SOj Emissions under
Alternative Control Scenarios, High Growth 3-17
3-6 National Power-Plant Particulate Emissions,
HighGrowth 3-20
in
-------
LIST OF TABLES
PAGE
1-1 Key Scenario Elements Held Constant Throughout the Analysis . I -5
1-2 SIP SO9 Emission Limits for Coal-Fired Units Used in the
NSPS Scenarios .......................................... ' ~6
1-3 County Designations ................. t ..... ..... ..... ' "°
1-4 National Electricity Demand Growth Rates .................. ' - ' 3
1-5 Alternative NSPS Scenarios ............................... I- '5
2-1 Definition of Geographic Regions ........................ 2-3
2-2 Utility Industry Generating Capacity as of December 31, 1975. . 2-4
2-3 Scaled Energy Demand Growth Rates by Region ... ........... 2-5
2-4 Projected Capacity Mix for Selected Scenarios ............... 2-7
2-5 Projected Capacity Mix by Region for the Baseline Scenario
with Moderate Growth .................. . ........... ...... 2-10
2-6 Projected Coal-Fired Capacity by Regulatory Category ....... 2-14
2-7 Projected Coal Capacity Using Flue Gas Desulfurization ....... 2-16
2-8 Regional Breakdown of Installed FGD Capacity in 1995, Scenario
H 1 .2(90)0.03 ............................................. 2-19
3-1 National Emissions of SO7, NO , and Particulates in 1976
and 1980 .............. . ---- . ............................ 3-3
3-2 Aggregate SO7 Emissions for Fossil-Fueled Generation by
Category of Unit ......................................... 3-9
3-3 Regional and National SO^ Emissions ..... .................. 3-12
3-4 Regions with Higher than Average Emission Reductions in 1990
due to Mandatory Ninety Percent SO« Removal .............. 3-18
3-5 National Projections of Particulate and NO Emissions, High
Growth Scenarios ...................... . ...... ........... 3_ 1 9
3-6 Projections of Sludge Produced by FGD Systems .............. 3-23
IV
-------
3-7 Cumulative Land Area Needed for Sludge Disposal, 1990-2000.. 3-25
3-8 Total Coal Ash Production 3-25
3-9 Water Consumed by FGD Systems 3-26
3-10 Water Discharged by Coal-Cleaning Plants 3-29
3-11 Energy Consumed by FGD Systems in 1995 3-31
3-12 Teknekron Coal Supply Regions 3-33
3-13 Coal Demand Nodes 3-34
3-14 Energy Consumed in Transporting Coal to Electric Generating
Plants 3-34
-v-
-------
SUMMARY OF RESULTS
Several alternative New Source Performance Standards have been evaluated In
terms of their implications for the U.S. electric utility Industry. The projected
development of the industry through the year 2000 under alternative NSPS for
two different national electricity demand growth rates Is discussed in Section 2
(moderate growth: 5.8% per year before 1985, 3.4% per year after 1985; high
growth: 5.8% before 1985, 5.5% after 1985). The revised NSPS examined In this
study are assumed to affect coal plants coming on line after 1982 with the
current NSPS assumed to apply to plants coming on line between 1977 and 1982.
Baseline scenarios with no revisions to the current NSPS have also been
examined. The air emissions, solid wastes, water and energy requirements for
each of these alternatives are presented in Section 3. Salient features of these
results are summarized as follows:
The U.S. electric utility industry will grow from 507 GW
net capability in 1976 to about 750 GW in 1985 and to
1085 or 1310 GW in 1995 under the specified moderate and
high growth rates, respectively.
Given the coals selected for consumption by utilities as
used in this analysis and the present SCU emission
limitations, the installed flue gas desulfurizaTion (FGD)
capacity will amount to approximately 17 percent of net
coal-fired generating capacity by 1985 and will remain at
approximately that relative level for the following de-
cade.
In the high demand growth case under a revised NSPS
requiring 80 percent post-combustion SO^ removal and an
emissions upper bound of 5l6ng/J (I.Zlb/IO Btu) the
installed FGD capacity will be 191 GW by 1990 and
351 GW by 1995. This compares to 59 GW in 1990 and
77 GW in 1995 under a continuation of the current NSPS.
Increasing the SO- removal requirement from 80 to
90 percent will increase the installed FGD capacity by 10
to 15 percent by 1995, depending on the post-1983 growth
rate. For the high growth case net coal-fired capability
will be 580 GW nationally In 1995, FGD capacity about
403 GW.
vi
-------
The regions of the country with the highest installed
scrubber capacities by 1995, assuming a 90 percent SO^
removal requirement, are West South Central (84 GW£
East North Central (82 GW), and South Atlantic (76 GW).
These three regions contain 60 percent of the total
installed FGD capacity in 1995 in the high growth case.
Utility coal consumption will increase from 404 million
metric tons (445 million U.S. tons) in 1976 to about
910 million metric tons in 2000 for the moderate growth
case or to 1670 million metric tons in 2000 for the high
growth case.
National emissions of SCX from all electric power plants
will increase from 1976 partial compliance levels (about
13.6 million metric tons) at about two percent per year
until 1985, if electricity demand grows at 5.8 percent per
year.
Under high demand growth after 1985 (5.5 percent per
year in total demand and roughly six percent per year in
coal-fired generation) natiortal SO^ emissions under
current standards will increase at approximately
2.5 percent per year. A revised NSPS with 90 percent
required removal will slow this growth in national SC^
emissions to less than I percent per year between 1985
and 2000.
Under moderate demand growth and present emission
standards national SO^ emissions will increase at
approximately 0.4 percent per year from 1985 to 2000. A
revised NSPS with 90 percent removal will bring about a
net decrease in national SCU emissions after 1985. By the
year 2000 national SC^ emissions will be approximately
equal to or below the 1976 partial compliance level for
SO* emissions.
In 1995 SC>2 emissions in the high demand case will be
reduced from the baseline projections (current NSPS) by
17 percent for mandatory 80 percent post-combustion
removal and by 27 percent for mandatory 90 percent post-
combustion removal. In 2000 the reduction of national
SO^ emissions is projected to be 35 percent with
90 percent removal, 21 percent with 80 percent removal.
-VII-
-------
A reduction in the electricity demand growth rate after
1985 to 3.4 percent per year along with a continuation of
the current NSPS SO, standard will result in a national
SO, emissions level m 2000 comparable to the level of
emfssions achievable under a 5.5 percent per year demand
growth rate after 1985 with the 90 percent SO, removal
standard. There are, however, regional differences in the
distribution of emissions in these cases.
In all years the predominant source of S02 emissions will
be those units subject to SIP (State Implementation Plan)
emission limits. Seventy-three percent of S02 emissions
in 1995 in the moderate growth case will be due to SIP
plants (those plants on line prior to 1977), six percent due
to plants on-line between 1977 and 1982 (subject to the
current NSPS) and 21 percent due to plants on-line after
1982 (those plants assumed to be subject to a revised
NSPS).
The revised SO, standards will have the greatest relative
impact in those regions which do not presently have a
large base of coal-fired generation. In 1990 a 90 percent
removal standard under high growth reduces national SO,
emissions by 3.3 million metric tons (19 percent). The
West South Central region (56 percent), North Mountain
region (53 percent), South Mountain region (47 percent),
Pacific region (42 percent) and the New England region
(23 percent) have the greatest percentage emissions
reductions over current NSPS. In terms of tonnages, the
West South Central, East North Central, and South
Atlantic regions have the largest SO, emissions
reductions.
Given the coal sulfur levels used in this analysis the
amount of SO, emitted under the 80 percent removal
standard and tne 215 ng/J (0.5 Ib/IO Btu) standard are
nearly the same in most regions. Nationally emissions
differ at most by four percent. In the Mountain states
where relatively low sulfur coals are used, the 80 percent
removal requirement further reduces SO, emissions by
about 30 percent in 2000.
Assuming the moderate growth rate, total particulate
emissions will increase only slightly above the I960 full
compliance level (0.8 million metric tons per year) and
will remain nearly constant thereafter. High demand
-VIII-
-------
growth would lead to further growth in particulate
emissions in the 1990s, to about I.I million metric tons
per year.
Revising the NSPS for particulates downward to 13 ng/J
(0.03lb/l06Btu) from 43 ng/J (0.10 Ib/106 Btu) reduces
national aggregate emissions by 11 percent in 1990 and
22 percent in 2000. Particulate emissions from post-1982
units will be reduced by a greater percentage, which may
have important local impacts.
Emissions of NO from electric power generation will
increase substantially under current standards, even
assuming an effective electricity demand conservation
program. Under high demand growth NO will increase
from 5.7 million metric tons in I960 to 15.6 million metric
tons in 2000; under moderate demand growth to 8.6
million metric tons in 2000.
Under the high growth case the tons of sludge on a dry
basis generated by FGD systems will be 12 million metric
tons nationally in 1995 for the current NSPS, 46 million
metric tons for an 80 percent removal standard and
55 million metric tons for a 90 percent removal standard.
The cumulative land area required to a depth of nine
meters for disposal of this FGD sludge between 1990 and
2000 will be 15.1 krri (5.8 mi ) and 91.5 krn (35 mr) for
the current NSPS and the 90 percent removal standard,
assuming high growth.
Total coal ash production in 1995 will be 101 million
metric tons about eight percent by weight of total coal
burned. Between 1990 and 2000 cumulative storage of
this ash Jo a depth of nine meters would require 176 km
(67.8 mi ).
Assuming full scrubbing of all post-1982 coal-fired units
national water consumption by FGD systems is estimated
to be 387 million cubic meters in the year 2000 in the
moderate demand growth case, and 927 million cubic
meters with higher growth. In comparison the rate of
water consumption by generating plant cooling systems is
twenty-two times the consumptive rate projected for
scrubbers. Whether or not these water demands
constitute a significant impact will depend on regional and
local conditions.
-IX-
-------
Direct energy consumption by FGD systems in 1995 will
increase from less than one percent of the total Btu input
for coal-fired generation under the current NSPS to as
much as 3.8 percent under a 90 percent removal standard.
Fuel consumed in transporting coal will be reduced with
the imposition of more stringent controls, primarily due to
a shifting of demand away from western coals delivered to
states bordering and east of the Mississippi River. The
energy savings in 1995. 50 x 10* MJ (4.7 x \Ql* Btu) and
120 x 10* MJ (I.I x 10'^Btu), are about 10 percent of the
direct FGD energy requirements projected for that year,
(588xlO*MJ and M50xlO*MJ) in the moderate and
high growth cases, respectively.
Details of Teknekron's analysis of alternative New Source Performance Standards
are presented in the following sections.
-x-
-------
1.0 INTRODUCTION AND BACKGROUND
This study reviews for the Environmental Protection Agency several alternative
standards of performance for sulfur dioxide (SO-) emissions from coal-fired
electric generating units. Teknekron's analysis has included the following
elements:
Projections of the physical configuration and economic
state of the electric utility industry to the year 2000
Estimates of the costs of meeting different revised
standards
Calculations of the changes in sulfur dioxide and other
emissions resulting from compliance with revised stan-
dards
Corresponding air quality changes
Identification and illumination of the major issues
involved in weighing the relative benefits of different
revisions
The basic tools used to provide quantitative data were Teknekron's Utility
Simulation Model, a large-scale computer model which simulates the response of
the electric utility industry to specified economic conditions, energy policies,
and regulatory constraints, and Teknekron's Air Quality Impact Assessment
Model, which links the emissions to the atmosphere, as projected by the
Simulation Model, to ambient air-quality changes. Detailed descriptions of the
Simulation Model are available elsewhere: a brief description is given in the
appendix to this volume. The air quality modeling process will be described in an
anticipated third volume of this report.
I.I BASE YEAR DATA
The results presented here were projected from a data base containing a
description of every electric generating unit (nuclear, oil and gas-fired, hydro,
geothermal and combustion turbine, as well as coal-fired) operating as of
-------
31 December 1975, plus announced plans for new units through 1986.
Beyond 1986, the model creates new generating units and sites them by county as
needed to meet projected demand. In order to simulate the industry's response to
a pollution control regulation, including a particular new source performance
standard (NSPS) for SO2 emissions from coal-fired units, a minimum set of
"scenario parameters" must be specified. Key among these are;
The future growth rate in peak and average power demand
"Future mix fractions" for each state, giving the
breakdowns of new generating capacity beyond 1985 by
type of generation
The kinds of coal to be burned by each coal-fired unit,
including sulfur and ash content
Other non air-pollution related variables which must be specified include an
overall inflation rate, new plant construction costs, costs of water pollution
controls, assumptions about the rate of phase-out of natural gas as a utility
boiler fuel, the minimum generating reserve margin to be maintained, the size
and thermal efficiency of future generating units, fuel prices and price trends,
and the order in which each utility system will "dispatch" the available units in
order to meet the projected demand.*
Variables which relate directly to the costs and effectiveness of air pollution
controls include specification of the sulfur dioxide (SO-), particulate, and
nitrogen oxide (NO ) emission limits that must be met by both old and new units
J\
and the costs of the pollution-control devices used to insure compliance (flue gas
desulfurization (FGD) systems, electrostatic precipitators and fabric filters,
modified boiler configurations for NO control), and constraints on siting future
XV
A "utility" in the model is formed by merging data from all investor owned
and ail publicly owned utilities within each state, so that there are at most
two "utilities" per state. These are referred to as "state firms."
-------
units due to air quality considerations. Much of these data e.g., the demand
projections, future mix fractions, and coal assignments vary state by state.
Others, such as the parameters used in the pollution control cost models, are
uniform nationally - although the emission limits which the control devices must
be designed to meet may vary by state in fact by county.
The basic categories of results which the simulation produces are:
I. Economic and financial impacts at the state level
Capital requirements for new generating units and
for pollution controls
Electricity prices and utility revenues
Utility operating costs
Return on utility equfty
2. Industry composition and fuel consumption down to the
county level
Generating mix
Fuel consumption
Reserve margins and capacity factors
3. Environmental residuals at the county level
Emissions of SC^, NO , and particulates to the
atmosphere* x
Solid wastes (mainly FGD sludge)
Water consumption for condenser cooling, coal
cleaning, and FGD makeup
Emissions of twelve trace elements are also calculated, but these have not
been analyzed in this study.
1-3
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1.2 SPECIFICATION OF SCENARIOS
The set of key input variables which must be specified before a simulation can be
run collectively define one "scenario" for which estimates of costs and
environmental benefits can be quantified. These variables can reflect both broad
national policies such as those outlined in the President's National Energy Plan ,
or very region-specific assumptions such as the fraction of post 1985 base-load
generating capacity in a particular state that will be nuclear. The key
assumptions which are common to all scenarios analyzed to date are summarized
in Table l-l.
Assumptions about State Implementation Plan (SIP) standards, although invariant
among scenarios, are critical in defining the "baseline" emission levels against
which changes due to the NSPS revisions are to be measured. The SIP limits for
coal-fired units that were used in this analysis were based on unit-by-unit data
supplied by EPA's Office of Planning and Evaluation in August 1977. Some
simplifications to the data were made. First, those limits which varied within a
state were simplified to only two values, a more stringent limit, referred to as a
"Metropolitan SIP", and a less stringent limit, referred to as a "Non-Metro-
politan SIP". All counties within each state were so designated. The numerical
limits were chosen to approximate the means of the generally bi-modal
distribution of actual SIP limits within states. Second, judgment was used to
convert those limits which were expressed in terms of concentrations of SC^ in
the stack gas, or ambient air concentrations, into equivalent emission rates
(nanograms per joule or pounds per million Btu). Third, limits for several western
states were tightened below those currently being applied to reflect EPA's
judgments about probable SIP revisions due to "prevention of significant
deterioration" and attempts to protect visibility in the relatively pristine western
regions. As a result, there are several western states in which the SIP limits for
502 em'ss'ons are more stringent than the current new source standard. In these
cases the SIP takes precedent: i.e., it is applied to all affected units coming on-
line before 1983. Tables 1-2 and 1-3 give the SIP SO2 limits and county
1-4
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Table i-l
Key Scenario Elements Held Constant Throughout the Analysis
Air Pollution Regulations;
State Implementation Plan emission standards (as of 8/77) for SO, and participates
applied to all units on-line before 1977. Full compliance assumed By 12/31/79.
Current (1977) NSPS far fossil-fueled units applied to ail units on-line between 1977
and 1982, Values for coal are: SI6ng/J (1.2 Ib/I0*fltu) for SO-,, 43ng/J
(0.1 Ib/IITBtu) for particulates, and 301 ng/J (0.7 Ib/I068tu) for NO . Com-
pliance assumed at inception.
Siting Restrictions!
Conversions and Rerates:
Coal and oil-fired units beyond those already announced are excluded from any
county containing a portion of an Air Quality Control Region qualifying for Man-
datory Class I or Nan-Attainment status.
Conversions from oil and gas to coat, as per Prohibition Orders issued by the Fedg
eral Energy Administration as of June 30, 1977, are assumed effected by 1985.
Additional gas phase-outs based upon FEA estimates published in 1975 are also
included. All gas-fired units are retired by 1996.
No new oil or gas-fired generating capacity is built after 1984.
Announced uprates, derates, and retirements as per FPC Order 383-4, I April 1977.
Water Pollution Regulations!
Full compliance with chemical and thermal emission limits promulgated for the
steam electric power industry in 1974 is assumed by 1977 and 1981, respectively.
Populations
Census Bureau Series II Projections.
Mandatory Class I areas are defined in accordance with the Clean Air Act Amendments of 1977: wilderness
areas and memorial parks exceeding 5,000 acres, national parks exceeding 6,000 acres. Non-attainment areas
are those counties with a recorded violation of any National Ambient Air Quality Standard in 1975.
Oil and gas-fired units which began operation before 1977 but convert to coal in 1977 or later are assumed to
be subject to the applicable SIP coal limit, not the NSPS.
1-5
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Table 1-2
(Pounds SC
STATE
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
. Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland & D.C.
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
)2 per million Btu heat input)
Met SIP
1.8
0.34
1.2
0.8
0.2
0.8
1.6
1.5
0.56
1.6
1.8
1.2
5.5
3.0
1.2
4.2
2.4
1.6
I.I
2.0
3.2
2.4
2.9
2.0
Non-Met SIP
4.0
0.34
1.2
4.7
0.2
0.8
No Limit
6.2
5.3
1.6
6.0
No Limit
5.5
No Limit
5.7
4.2
4.0
1.6
2.7
2.0
4.2
4.8
6.4
2.0
1-6
-------
Td>le 1-2
(Continued)
STATE
Met SIP
Non-Met SIP
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
t
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia N
Washington
West Virginia
Wisconsin
Wyoming
2.5
0.2
4.7
0.32
0.34
0.4
1.6
3.0
1.4
2.0
2.1
0.7
I.I
2.3
3.0
1.2
2.0
0.2
1.6
1.4
3.3
2.8
2.0
0.2
2.5
0.2
4.7
1.6
1.4
4.3
1.6
3.0
4.5
2.0
2.1
3.0
I.I
3.5
3.0
4.4
2.0
0.2
1.6
3.5
3.3
2.8
2.0
0.2
1-7
-------
Table 1-3
County Designations
STATE
Met
Counties
Non-Met
Counties
No
Different-
iation
-- .
Alabama
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Idaho
Illinois
Indiana
Kansas
AQCR #5
Jefferson County
Jackson County
AQCRs #27,28,30
25, 32, 24, 29, 33
and 23
New Castle
County
Escambia, Duval
and Hillsborough
Counties
Dougherty,
Chatham, Cobb,
Camden, Bibb,
Cherokee and
Fulton Counties
AQCR #65, 67,
and 70
All others
AQCR #94, 95,
and 96
AQCR 1,2,3,4,6
+ Colbert, Cullman,
Dekalb, Franklin,
Lauderdale, Lawrence
Limestone, Madison,
Marion, Marshall,
Morgan and Winston
Counties
AQCRs #31 and 26
All others
All others
All others
All others
Greene, Clinton,
Cass and Sullivan
Counties
AQCR #97, 98, 99,
and 100
X
X
X
X
1-8
-------
Table 1-3
(Continued)
STATE
Met
Counties
Non-Met
Counties
No
Different-
iation
Kentucky
Louisiana
Maine
Maryland
&D.C.
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
AQCR #78 and
McCracken County
AQCR #110
AQCRs#ll8, 120,
and Suffolk County
AQCR #131
Washington and
Harrison Counties
AQCR #70
All others
AQCR #14
Bronx, Kings,
Queens, New York,
Nassau, Rock land,
Westchester, Rich-
mond and Suffolk
Counties
All others
AQCR #107, 109
All others
All others
All others
All others
X
X
X
X
X
X
X
Atlantic, Cape May
Cumberland, Hunter-
don, Ocean, Sussex,
and Warren Counties
All others
All others .
1-9
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Table 1-3
(Continued)
STATE
Met
Counties
Non-Met
Counties
No
Different-
iation
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
X
X
Muskingum, Cler-
mont, Ashtabula,
Greene, Rich land,
Allen, Ottawa,
Stark, Wood, Adams,
Hamilton, Butler,
Montgomery, Lake,
Cuyahoga, Morgan,
Franklin, and
Lorain Counties
Beaver, Hancock,
Brook, Washington,
Allegheny,
Westmoreland,
Somerset,
Cambria, Blair,
Perry,
Cumberland,
Adams, York,
Dauphin, Lancaster,
Chester, Delaware,
Montgomery, Bucks,
Lehigh,
Northhampton,
Luzerne,
Lackawanna,
Susquehanna,
Philadelphia, and
Armstrong
Counties
All others
X
X
All others
1-10
-------
Table 1-3
(Continued)
STATE
Met
Counties
Non-Met
Counties
No
Different-
iation
Rhode Island
S. Carolina
S. Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
X
Charleston, Aiken,
and Anderson
Counties
Humphreys, Polk,
Maury, Sullivan,
and Roane
Counties
All others
All others
X
X
X
AQCR #47
Wahtcom, Skagit,
San Juan, and
Island Counties
All others
All others
X
X
X
-------
designations which were used for coal-fired units in this study. Limits for
particulate and for oil-fired units were not changed from those used in
2
Teknekron's earlier modeling work for EPA.
The key elements which vary among the scenarios are the assumed growth rate in
demand for electricity and the revised NSPS being analyzed, the latter being
applied only to coal-fired units of at least 25 Mw on-line in 1983 or later. Table
1-4 summarizes the two sets of demand growth scenarios which were considered.
The revised NSPS which were considered involve one change in the particulate
and NO standards, combined with three different S02 standards:
SOj .1. Ninety percent mandatory post-combustion SO2 removal
with an upper limit ("cap") on emissions of 5l6ng/J
(l.2lb/!06Btu).
2. Eighty percent mandatory post-combustion SO^ removal
with an upper limit on emissions of 516ng/J
(l.2lb/!06Btu).
3. No mandatory percentage post-combustion SO~ removal,
with an upper limit on emissions of 2l5ng/J
(0.5lb/l06Btu).
Particulates No mandatory percentage removal, with an upper limit on
emissions of 12.9 mg/J (0.03 Ib/IO6 Btu).
NOx No mandatory percentage removal, with an upper limit on
emissions of 258 ng/J (0.6 Ib/IO6 Btu).
Both the demand growth assumptions and the candidate NSPS revisions were
specified by the Environmental Protection Agency. The "moderate" growth cases
are meant to reflect a successful energy conservation effort as envisioned by the
1-12
-------
Table 1-4
Notional Electricity Demand Growth Rates
(percent per year)
1975-1985 (986-2000
Peak Average Peak Average
"Moderate11 Growth 5.8 5.8 3.4 3.4
"High" Growth 5.8 5.8 5.5 5.5
i-13
-------
National Energy Plan. (Our assumptions about natural gas phase-outs and oil and
gas conversions to coal are also designed to reflect the goals of the N.E.P.)
Additional scenarios in which we impose no Clean Air Act related air pollution
regulations are also contemplated: these will be used to calculate the total cost
of air pollution control as opposed to the incremental costs incurred in complying
with a revised new source performance standard.
The nomenclature used to label results from the nine different scenarios
presented is as follows: the letter "MM or "H" first indicates "moderate" or "high"
electric demand growth. This is followed by three numbers which specify the
S07 emission "cap" (in Ib/IO Btu)j the required percent SO9 removal, and the
(\
particulate limit (in Ib/IO Btu). Since the NOx limit was set at
258ng/J(0.6 Ib/IO6 Btu) in all cases except the "baseline" scenarios (no NSPS
revisions), its value is not indicated explicitly. The scenarios are summarized in
Table 1-5.
1-14
-------
Table 1-5
Alternative NSPS Scenarios
Scenario Label
Revised NSPS
In Ib/1C6 Btu
(% Removal)
Ml.2(0)0.1
(Baseline with moderate growth)
HI.2(0)0.1
(Baseline with high«growth)
Ml.2(90)0.1
HI.2(90)0.1
Ml.2(90)0.03
HI.2(90)0.03
Ml.2(80)0.03
HI.2(80)0.03
M0.5(0)0.03
S09 = 1.2 (0)
NO; = 0.7
Participates? = O.I
Same as above
SO, = 1.2 (90)
NCT = 0.6
Particulates =0.1
Same as above
Same as Ml.2(90)0.1 but with
Particulates =0.03
Same as HI.2(90)0.1 but with
Particulates = 0.03
SO, = 1.2 (80)
NO; = 0.6
Particulates =0.03
Same as above
SO, = 0.5 (0)
Ntf = 0.6
Particulates = 0.03
1-15
-------
2. INDUSTRY PROJECTIONS
This chapter sets the stage for the simulations by first characterizing the utility
industry* in the base year (1975), and then projecting that configuration forward
in time. The characteristics which we focus on are the capacity mix, i.e. aggre-
gate generating capacity broken down by type of generation (coal, oil, nuclear,
etc.), the distribution of generating units by regulatory category (SIP, NSPS, or
revised NSPS), and the amount of capacity using FGD.
Because the Utility Simulation Model takes into account many of the complex
interactions which occur among utilities' pollution control compliance strategies
and their other planning and dispatching decisions, projections of characteristics
like capacity mix are not independent of the particular pollution control scenario
being considered. To illustrate, a decision to comply with an SC^ emission limit
through use of FGD will result in a generating capability reduction which must
eventually be compensated for somewhere in the system. If that utility system's
reserve margin is ample, then the lost capacity can be compensated for in the
short term by running the existing units at higher levels. If the reserve is already
near the safe minimum, however, the utility must plan for increased capacity
additions, either by building more combustion turbines in the short term, or
accelerating planned building schedules in the longer term. Regardless of the
particular system, more capacity will have to be added in the long run if a
substantial number of units are forced to use FGD because of a new air emissions
regulation. Fuel consumption as well varies with emissions control strategy. For
example, increased use of FGD in the Midwest and East will tend to encourage
the use of locally available medium and high sulfur coals at the expense of more
distant supplies of low sulfur western coal. This in turn changes the average
heating value of the fuel, resulting in a change in the tonnage of coal burned by
The investor owned sector and the publicly owned sector (municipal sys-
tems plus the Tennessee Valley Authority and other federal projects) are
treated together in this volume. Differences between these sectors from a
financial perspective are discussed in Volume II.
2-1
-------
the industry.* Such interactions are important characteristics of the electric
utility industry which cannot be ignored in a realistic assessment of "the costs of
pollution control." Unfortunately, they also make comparisons among scenarios
more difficult, because several variables that influence costs may be changing
simultaneously.
2.1 CAPACITY MIX IN THE BASE YEAR
Table 2-1 defines the geographical regions used in reporting capacity mix and
other industry characteristics. Table 2-2 shows the electrical generating
capacity as of December 1975 included in Teknekron's data base. Two key
scenario variables involved in projecting this base-year capacity mix to any
future year are the. electrical demand growth rates that apply to each region, and
the future fractions used in adding new units once the files of announced units
for a given state have been exhausted. State-level growth rates are scaled from
the national average values shown in Table 1-4 according to population growth.
States whose growth is projected to be higher or lower than the national level
will have higher or lower demand growth rates, respectively, with the scaling
being done so as to maintain the originally specified national energy demand (or
average power) growth.** Average compound growth rates for the periods 1976-
1985 and 1986-1995 derived by this process are given in Table 2-3.
There is no tractable decision rule for predicting the proportions of future units
built beyond 1985 which will be nuclear or coal. Future-mix fractions for each
state firm are therefore specified exogenously to the model. These may be made
to vary with the emissions control scenario, or held constant. In accordance with
The amount of coal that must be burned to yield one kilowatt-hour of
electrical energy is given by the unit's heat rate (a way of expressing
thermal conversion efficiency) divided by the coal's heating value. It takes
about one pound of coal to produce one kilowatt-hour from a modern coal-
fired boiler. Variations in tonnage burned among the control scenarios
described here were not significant.
** A national peak growth rate has less physical meaning since the time of
peak power demand varies widely across the country.
2-2
-------
Table 2-1
Definition of Geographic Regions
New England (NE) Mid-Atlantic (MA) S. Atlantic (SA) EJM Central (ENC)
CT NY DE Wl
Rl PA MD/DC Ml
MA NJ VA IL
NH WV IN
VT NC OH
ME SC
GA
FA
E.S. Central (ESC) W.N. Central (WNC) W.S. Central (WSC)
KY ND TX
TN SD OK
MS NB AR
AL KS LA
IA
MO
MN
N. Mountain (NM) S. Mountain (SM) Pacific (PA)
ID NV WA
MT UT OR
WY CO CA
AZ
NM
NOTE; The first seven and the last region are identical to the Bureau of the Census
regions.
2-3
-------
N;
Table 2-2
Utility Industry Generating Capacity as of December 31. 1975°
(Gigawatts)
Region5
Nuclear
Coal
Oil
Gas
Hydro
Combustion
Turbine
Other0
Total
NE
MA
SA
EMC
ESC
WNC
WSC
NM
SM
PA
Nation
5.0
10.5
8.5
8.8
2.1
3.4
0.8
0.
0.
2.3
41.4
0.6
18.5
46.3
62.2
27.9
13.2
2.6
3.9
13.3
1.4
189.9
11.5
22.3
17.8
4.8
1.3
0.2
3.2
0.07
1.4
19.1
81.7
0.03
0.04
1.6
1.7
2.9
6.3
50.1
0.02
2.7
3.0
68.4
2.5
6.7
6.0
3.1
5.9
3.1
2.3
2.9
3.1
30.0
65.6
I.I
10.4
8.0
4.4
0.5
3.0
1.8
0.
I.I
I.I
31.4
0.4
0.2
0.8
2.3
2.2
I.I
0.2
O.I
0.6
0.7
8.6
21.1
68.6
89.0
87.3
42.8
30.3
61.0
7.0
22.2
57.6
487.0
b
c
Average of summer and winter capabilities. The total is 96% of the name-plate capacity
reported by the Edison Electric Institute.
See Table 2-1 for definitions.
Geothermal + combined cycle + internal combustion (diesel) generators.
-------
Table 2-3
Scaled Energy Demond Growth Rotes, by Region
(Average compound growth rate in percent per year)
"Moderate" Growth Scenarios
REGION0 1976-1985 1986-1995
"High" Growth Scenarios
1976-19851986-1995
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Nation
5.6
5.5
6.2
5.6
6.0
5.2
5.6
4.6
6'.3
5.7
5.8
3.4
3.3
3.7
3.3
3.4
3.0
3.3
2.8
3.8
3.4
3.4
5.6
5.5
6.2
5.6
6.0
5.2
5.6
4.6
6.3
5.7
5.8
5.5
5.4
5.9
5.4
5.5
5.1
5.4
4.8
5.9
5.5
5.5
See Table 2-1
2-5
-------
EPA's directives, the fractions used in deriving the results presented here were
supplied to Teknekron by ICF, Inc., another contractor supporting EPA's study.
(Coal assignments and coal-unit dispatch orders, by regulatory category, were
also taken from data supplied by ICF.) The approach used by ICF was to hold the
amount (megawattage) of nuclear capacity in 1995 constant - i.e. independent of
both the post-1985 growth rate and the control scenario. The rationale used to
justify keeping the nuclear capacity the same under the moderate and high
growth cases is that a variety of regulatory and other constraints are operating
which would hinder the acceleration of nuclear building schedules beyond those
currently envisioned by 1990, and that the amount of building we are assuming is
already set at an "optimistic" level. The reason for not attempting to quantify
the shift to nuclear that might occur as a result of the imposition of more
stringent emission standards on coal units beyond 1990 is related: we feel that
this issue is too complex to model realistically, at least within the context of the
current study, because: (I) many of the important determinants of a utility's
decision whether to "go nuclear" are not quantifiable (e.g., the expected licensing
period); (2) those measures which are in principle quantifiable, such as relative
power generating costs, are impossible to predict accurately in the 1990 time
frame due to great uncertainties in the cost data. (This issue is discussed more
fully in Volume II, "Economic and Financial Impacts".)
2.2 PROJECTIONS TO 2000
f-
Capacity mixes for the two baseline scenarios (Ml.2(0)0.1 and Hi.2(0)0.1) and the
two 90 percent control scenarios (Ml.2(90)0.1 and H1.2(90)0.1) are shown in Table
2-4. Note that although the total capacity in 1995 does not vary when the more
stringent SO- controls are imposed, there is a slight increase in nuclear capacity
with a corresponding decrease in coal-fired capacity. Note again that this shift
is not due to conclusions about the relative economiqs of coal vs. nuclear
generation in the future. One factor which does operate is that capacity
penalties incurred when FGD systems are applied to coal-fired units, are, over
2-6
-------
Table 2-4
Projected Capacity Mix for Selected Scenarios
(Net capability, Gigawatts)
Coal
Oil & Gas
Comb. Cycle
Hydro
Turbine
Geothermol
Nuclear
TOTAL
1985
a
285.
159.
B.OO
86.1
68.8
1.70
138.
747.
A
283.
159.
8.00
86.1
69.0
1.70
138,
745.
b
285.
159.
8.00
86.1
68.9
1.70
137.
746.
B
28/1.
159.
B.OO
86.1
68.8
1.70
139.
747.
1995
a
417.
125.
8.00
87.9
78.1
1.90
365.
1083.
A
403.
125.
8.00
86.2
80.0
1.90
378.
1082.
b
601.
125.
10.6
90.5
101.
1.90
379.
1309.
B
589.
125.
10.7
86.5
108.
1.90
387.
1308.
Additions (1977-1995)
a
219.
-32.3
6.80
20.5
36.2
1.60
358.
610.
A
204.
-32.3
6.80
18.8
38.1
1.60
338.
575.
b
403.
-32.3
9.40
23.1
59.0
1.60
339.
803.
D
390.
-32.3
9.50
19.1
66.0
1.60
347.
801.
ISJ
Legend: a= Ml.2(0)0.1 (Moderate growth baseline)
A - MT. 2(90)0. I/O.03 (Moderate growth, 90 percent SO2 removal on post-1982
units, either particulate limit)
b - HI.2(0)0.1 (High growth baseline)
D = HI .2(90)0.1/0.03 (High growth, 90 percent SO? removal on post 1982 units,
either participate limit)
-------
the long term, partially compensated for by increased nuclear capacity. Note
that the tabular values are net "capability," i.e., generating capacity after
reducitons due to all pollution control devices are taken into account: these may
amount to as much as ten percent of the "name-plate" capacity. If name-plate
values were shown, the values for coal capacity under the more stringent
controls scenarios would increase by roughly five percent in 1995. Since nuclear
units have only water pollution controls, the name-plate capacities of the nuclear
units are greater by a smaller fraction, and that fraction is independent of the
SC>2 controls assumed.
Two other aspects of the planning algorithms used by the model to create new
capacity once the announcements data file for a given state has been exhausted
bear upon the amount of nuclear capacity added in the 1990s.* New base-load
units are added in discrete sizes, not in the exact amount of capacity needed to
bring the reserve margin up to the minimum.** Secondly, the specified future
fractions are applied in a probabilistic sense. For example, specifying that 70
percent of the post-1985 capacity built in a New England state will be nuclear is
interpreted by the model as a seven out of ten probability that a new unit will be
nuclear. As a result, the exact amount of nuclear capacity installed by any year
beyond 1985 cannot be "clamped" exogeneously. While this reflects planning
uncertainties in the real world, it does complicate the process of isolating the
impacts of changing standards applied to fossil-fueled units. Aggregate nuclear
capacity can be adjusted by trial and error; this was in fact done for the
HI.2(90)0.03 scenario, in which the initial model runs produced higher nuclear
values than shown in these results.
Announced units are not necessarily put into operation at the date the
utility has projected: units are deferred if the specified demand growth
does not justify operation until a later date. We assume, however, that
steam plant construction schedules may not be accelerated and that com-
bustion turbines will be built in the short term, if demand requires and if
more announced units are planned for a later year.
V «*
The simulated sizes are: nuclear - 1,200 Mw, coal - 600 Mw, oil -
500 Mw.
2-8
-------
Table 2-5 shows capacity mix by geographic region for the baseline scenario with
moderate growth (M1.2(0)0.1). The last column gives the capacity additions over
the years 1985-1995, the period over which new builds are determined primarily
by the future-mix fractions.
The age distribution of coal-fired units is important in this study because we
apply the revised new source standards only to those units that came into
commercial operation in 1983 or later.* The following summarizes the key
dates used to categorize all fossil-fired units by applicable emission standard:
On Line Applicable Category of Emission Standards
1976 or earlier State Implementation Plan (SIP)
1977-1982 New Source Performance Standards (NSPS)
1983 or later Revised New Source Performance Standards
Table 2-6 gives the age breakdown, by category in five year intervals from 1980
to 1995. In 1985, the first year for which we will be discussing emission changes
due to a NSPS revision, the fraction of coal-fired capacity affected is only 11.5
percent. In the lower growth rate case, less than half of the coal-fired capacity
would be subject to the revised standard by 2000, the last year of the simulation.
With higher growth, the fraction affected in that year is 69 percent.
The Clean Air Act stipulates that the revised standard will apply to those
units whose construction commences after publication of the proposed
revision. The definition of "commence construction" is somewhat at issue,
and construction periods vary: we assume a fixed year of implementation,
1983.
2-9
-------
Table 2-5
with Moderate Growth
(Net generating capability, Gigawatts)
New England
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
MuTAtlantic
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
1976
0.58
11.9
0.08
2.53
1.52
0.0
4.14
20.8
1976
20.3
24.5
0.13
6.69
10.6
0.0
7.38
1985
MMMMM^
1.34
13.2
0.31
2.53
2.28
0.0
9.87
29.5
1985
24.5
25.0
0.13
8.05
13.1
0.0
21.5
1995
3.97
13.1
0.31
2.53
2.28
0.0
20.0
42.2
1995
38.2
24.1
0.13
8.05
13.1
0.0
51.6
1985-1995
2.63
-0.10
0.0
0.0
0.0
0.0
10.13
12.7
1985-1995
13.7
-0.9
0.0
0.0
0.0
0.0
30.1
TOTAL
69.6
92.3
135
42.9
South Atlantic
1976
1985
1995
1985-1995
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
41.2
22.4
0.0
5.74
9.10
0.0
9.67
88.1
53.8
24.1
1.40
9.72
15.1
0.0
27.5
132
80.6
23.6
1.40
9.78
15.5
0.0
72.0
203
26.8
-0.5
0.0
0.06
0.4
0.0
44.5
71.3
2-10
-------
Table 2-5 (cent.)
Projected Capacity Mix. by Reqion, for
the
Baseline Scenario,with Moderate Growth
(Net
East North Central
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
East South Central
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
West North Central
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
generating
1976
69.1
7.28
0.0
3.13
6.80
0.0
8.69
95.0
1976
30.5
4.32
0.0
5.98
2.69
0.0
2.30
45.8
1976
18.5
4.96
0.0
3.00
4.81
0.0
4.00
35.3
capability,
1985
89.5
8.62
0.0
3.17
11.7
0.0
28.8
142
1985
37.0
4.63
0.0
7.53
3.06
0.0
18.0
70.2
1985
31.7
2.77
0.09
4.00
7.88
0.0
6.28
52.7
Gigawatts)
1995
104.3
8.59
0.0
3.17
12.0
0.0
79.3
207
1995
44.6
4.33
0.0
7.53
3.13
0.0
39.0
98.6
J99S
42.7
2.74
0.09
4.00
8.50
0.0
14.0
72.0
1985-1995
14.80
-0.03
0.0
0.0
0.30
0.0
50.5
65.6
1985-1995
7.60
-0.30
0.0
0.0
0.07
0.0
21.0
28.4
1985-1995
11.0
-0.03
0.0
0.0
0.62
0.0
7.72
!9.3
2-11
-------
Table 2-5 (cont.)
Proiected-Copoclty Mix, by Region, for the
Baseline Scenario with Moderate Growth
(Net generating capability, Gigawatts)
West Sooth Central
Coal
Oil & Gas
Comb Cycle
Hydro
Turbine
Geothermal
Nuclear
TOTAL
N. Mountain
Coal
Oil & Gas
Comb Cycle
Hydro
f
Turbine
Geothermal
Nuclear
TOTAL
1976
2.78
57.1
0.23
2.32
2.78
0.0
0.90
66.1
1976
1.27
0.07
0.0
3.15
0.08
0.0
0.0
4.57
1985
19.6
57.0
0.46
2.57
5.83
0.0
9.03
94.5
4985
3.03
0.07
0.0
3.89
0.60
0.0
0.0
7.59
1995
58.4
25.6
0.46
2.57
12.4
0.0
34.0
133
1995
5.27
0.07
0.0
3.93
0.61
0.0
0.0
9.88
1985-1995
38.8
-31.4
0.0
0.0
6.57
0.0
25.0
38.9
1985-1995
2.24
0.0
0.0
0.04
0.01
0.0
0.0
2.29
S. Mountain
1976
1985 1995
1985-1995
Coal
Oil & Gas
Comb Cycle
Hydro
Tufa Turbine
Geothermal
Nuclear
TOTAL
12.8
3.50
0.23
3.14
1.75
0.0
0.0
21.4
19.5
3.26
0.51
3.67
2.73
0.0
0.67
30.3
27.1
2.18
0.51
3.67
2.83
0.0
7.73
44.0
7.6
-1.08
0.0
0.0
0.10
0.0
7.06
13.7
2-12
-------
Table 2-5 (cent.)
Projected Capacity Mix, by Region, for the
Baseline Scenario-with Moderate Growth
(Net generating capability, Gigawatts)
Pacific 1976 1985 1995 1985-1995
Goal 1.37 4.51 12.3 7.8
Oil & Gas 21.4 20.7 20.5 -0.2
Comb Cycle 0.57 5.08 5.08 0.0
Hydro 31.7 41.0 42.6 1.6
Turbine 1.77 6.56 7.66 I.I
Geothermal 0.32 1.72 1.93 0.21
Nuclear 3.39 16.2 47.0 30.8
TOTAL 60.5 95.8 137 41.3
2-13
-------
Table 2-6.
(Net generating capability, Gigawatts)
Year
I960
1985
1990
1995
2000
SIP Units
206.8
(87.4%)
212.5
(74.7%
212.1
(59.7%)
212.1
(50.8%)
212.1
'43.5%)
Moderate Growth
NSPS Units
29.8
(12.6%)
39.3
(13.8%)
39.3
(11.1%)
39.3
(9.4%)
39.3
(8.1%)
Scenarios
Revised NSPS Units
0.0
(0%)
32.7
(11.5%)
103.9
(29.2%)
1 66.0
(39.8%)
236.4
(43.5%)
Total
237
285
355
417
488
High Growth Scenarios
Year
1980
1985
1990
1995
2000
SIP Units
206.9
(87.4%)
212.6
(74.7%)
212.3
(50.3%)
212.3
(35.3%)
212.3
(25.8%)
NSPS Units
29.8
(12.6%)
39.3
(13.8%)
39.3
(9.3%)
39.3
(6.5%)
39.3
(4.8%)
Revised NSPS Units
0.0
(0%)
32.7
(11.5%)
170.8
(40.4%)
349.7
(58.2%)
570.1
(69.4%)
Total
237
285
422
601
822
2-14
-------
Table 2-7 gives projections of flue gas desulfurization ("scrubber") capacities for
all the S02 control variants, assuming the revised particulate limit of 12.9 ng/J
(0.03 lb/!06Btu). The numbers listed under "Capacity of FGD Systems" are
measures of the size of the scrubbers, not of the units being scrubbed. These two
capacities can differ, because the pollution control module allows for partial
scrubbing of the flue gas. More specifically, we assume full scrubbing only when
the required SC^ removal equals or exceeds 90 percent. Less than 90 percent
removal is achieved by scrubbing less than 100 percent of the gas at 90 percent
removal efficiency. The "capacity" of the FGD system for an individual boiler is
therefore the generating unit's name-plate capacity, times the fraction of the
gas scrubbed (a number between 0.3 and 1.0).* This is a measure of the design
size of the scrubber module. Finally, note that the figures reported under
"Generating Capability" include all pollution control related capacity penalties:
this explains why the FGD capacities exceed the "Revised NSPS" net generating
capabilities for units subject to the 90 percent removal requirement.
The variations in the required FGD capacities for SIP and NSPS units in 1985 are
due to differences among the scenarios in the sulfur levels of coals assigned to
SIP and NSPS units. The sulfur content and region of origin of coals used in all
the scenarios were derived from the output of a coal supply model developed by
ICF, Inc.5
Table 2-8 shows a regional breakdown of installed FGD capacity in 1990 under
the high growth scenario with the 90 percent removal requirement (H1.2(90)0.03).
Salient features of these results are:
Assumed coal sulfur values were adjusted downward to the compliance
level whenever less than 30 percent SOj removal was required to comply
with the applicable limit. This precludes the building of unrealistically
small scrubbers.
2-15
-------
Table 2-7
Projected Coal Capacity Usina Flue Gas Oesulfurizdtion
(Gigawatts)
Scenario
Ml. 2(0)0.1
Ml. 2(90)0. 03b
(Ml. 2(90)0.1)
Hi. 2(0)0.1
Year
1985
1990
1995
2000
1985
1990
1995
2000
1985-
1990
1995
2000
Capacity of
Unit Category Generating Capability FGD Systems
SIP and NSPS
All
SIP and NSPS
All
SIP and NSPS
All
SIP and NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
All
SIP and NSPS
All
SIP and NSPS
All
SIP and NSPS
All
285
285
355
355
417
417
487
487
252
31.2
283
252
94.8
347
252
151
403
252
212
464
285
285
422
422,
602
602
822
822
52.5
52.5
61.3
61.3
67.1
67.1
75.1
75.1
38.7
35.5
74.2
38.7
106
145
38.7
168
207
38.7
236
275
45.6
45.6
59.4
59.4
76.5
76.5
99.7
99.7
a See text, page 2-13.
b Differences in these results for the two different participate scenarios are insignificant.
2-16
-------
Table 2-7 (continued)
Projected Cool Capacity Using Flue Cos Desulfurization
(Gigawatts)
Scenario Year Unit Category
Hl.2(90)0.03b 1985 SIP and NSPS
(HI. 2(90)0.1) Revised NSPS
All
1990 SIP and NSPS
Revised NSPS
All
1995 SIP and NSPS
Revised NSPS
All
2000 SIP and NSPS
Revised NSPS
All
M 1 .2(30)0.03 1 985 SIP and NSPS
Revised NSPS
All
1990 SIP and NSPS
Revised NSPS
All
1995 SIP and NSPS
Revised NSPS
All
2000 SIP and NSPS
Revised NSPS
All
Generating Capacity
253
39.2
292
253
167
420
253
336
589
253
543
796
252
40.3
292
252
94.7
347
252
151
403
252
212
464
Capacity of
FGD Systems
31.0
34.0
65.0
31.0
185.0
216.0
31. CT
372.0
403.0
31.0
602.0
633.0
38.7
31.6
70,3
38.7
93.3
132
38.7
149
138
38.7
209
248
a See text, page 2-13
b Differences in these results for the two different participate scenarios are insignificant.
2-17
-------
Table 2-7 (continued)
Projected Coql Capacity Using Flue Gas Destdfurizotion
(Gigawatts;
Scenario Year
Hl.2(80)0.03b 1985
1990
1995
2000
M0.5(0)0.03 1985
1990
1995
2000
Unit Category
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
SIP and NSPS
Revised NSPS
All
3iP and NSPS
Revised NSPS
All
Generating Capacity
253
40.5
292
253
167
420
253
336
589
253
543
796
252
40.5
292
252
95.9
348
252
152
404
252
212
464
Capacity of
FGD^Systems0
30.0
30.1
61.0
30.0
161.
191
30.0
321
351
30.0
527
557
39.7
31.6
71.3
33.7
93.5
132
38.7
149
138
38.7
208
247
a See text, page 2-13.
b Differences in these results for the two different particulate scenarios are insignificant.
2-18
-------
Table 2-8
Regional Breakdown of Installed FGD Capacity in 1995. Scenario HI.2(90)0.03
(GJgawatts)
Region13 Net Coal-Fired Capacity FGD Capacity
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Nation
6.75
59.2
102
158
54.4
50.6
87.5
13.9
32.4
25.2
589
6.52
42.5
75.5
81.5
23.2
31.5
84.1
13.9
24.5
20.1
403
See Table 2-1.
2-19
-------
Given the coal assignments used in this analysis and the
present SC>2 emission limitations, installed FGD capacity
would amount to 16 to 18 percent of net coal-fired
generating capacity by 1985, remaining at approximately
that level for the following decade.
Under the "high growth" scenario, the 80 percent removal
requirement increases installed FGD capacity from 59 Gw
under the current standard to 191 Gw by 1990, and from
77 Gw to 351 Gwby 1995.
Increasing the removal requirement from 80 to 90 percent
further increases the installed FGD capacity by 10 to 15
percent by 1995, depending upon the post-1983 growth
rate.
The amount of FGD installed in response to a revised
NSPS standard of 215 ng/J (0.5 Ib/IO6 Btu) is nearly the
same as that projected under the 80 percent removal
scenario.
The regions of the country with the highest installed
scrubber capacities by 1995, assuming a 90 percent
removal requirement, are West South Central (84 Gw),
East North Central (82 Gw), and South Atlantic (76 Gw).
These three regions contain 60 percent of the total
installed scrubbing capacity in that year.
As indicated on the previous tables, our projections of capacity mix and scrubber
usage (and, as we show in the next chapter, SCK emissions), are not sensitive to a
revision of the current new source standard for particulates. This is because the
coal assignments, capacity penalties, future-mix fractions and dispatch orders
remain the same. The costs of control do increase but not enough to affect
these key determinants of industry behavior. The small size of the cost increase
is due partially to the assumption, stipulated by EPA, that units burning low
sulfur western coals would use fabric filters rather than precipitators to comply
with new source standards. Given the control costs models used in this study,
universal use of precipitators would increase the costs of meeting the revised
particulate standard.
2-20
-------
Projections of utility coal consumption are shown in Figure 2-1 for the moderate
and the high growth scenarios. (Variations in coal consumption due to the dif-
ferent 502 contro' assumptions are too small to be significant.) The curve starts
in 1976 at 404 million metric tons (445 tons), which is very close to the actual
utility "burn" in that year as reported by the Federal Power Commission,7 406
million metric tons (448 million tons).* In the year 2000 differences in electric
demand growth rates after 1985 (3.4 to 5.5 percent) and in the percentage of
coal-fired capacity added lead to a dramatic difference in coal consumption, 910
metric tons and 1,670 metric tons in the moderate and high demand growth
cases, respectively.
The simulation model accounts for differences between coal mined and coal
burned due to tonnage loss in coal preparation plants. (Changes in utility stock-
piles are not considered.) For the sulfur levels of the coals assigned and our
assumptions about the minimum sulfur levels which are available in uncleaned
coals, the model projects that 32 million metric tons of coal would have had to
be mined in 1976 to account for refuse from producing 114 million metric tons
(126 million tons) of cleaned coal, assuming dense media separation processes
with 80 percent weight recovery. This compares with the U.S. Bureau of Mines'
estimate of 79 million metric tons (87 million tons) of steam and metallurgical
Q
coals that were cleaned by dense media separation processes in 1975.
The FPC reports both deliveries and consumption. These may differ in any
given year due to changes in stockpile levels.
2-21
-------
2000 n
1800 '
o
v
O
Q.
tn
0
5
8
2 1000
2
*
o.
O
j
O
u
1600
1400
1200
800
600
"HIGH GROWTH" SCENARIOS
400 -
"MODERATE GROWTH"
1975
1980
1985
1990
1995
2000
Year
Figure 2-1. Projections of electric utility coal consumption.
2-22
-------
3.0 AIR EMISSIONS, SOLID WASTES, WATER AND ENERGY
Emissions of the "criteria pollutants," S02, NOX and particulates, from all fossil-
fueled generating units under each of the scenarios are summarized in this
section, using the geographic regions defined in Chapter 2. The implications of
these emissions for ambient air quality will be discussed in Volume III.
Solid wastes considered are the sludges resulting from the use of FGD
("scrubber") systems. Following EPA's directives, there were three generic FGD
systems considered: lime and limestone nonregenerable, and magnesium-oxide
regenerable. The choice among these types for an individual generating unit was
made on a random basis with the distribution of selections having the following
probabilities:
Probability that a unit installing FGD will choose;
Region Lime Limestone Mag-Ox
New England* 0 0 100%
All others 38% 57% 5%
The residuals module of the simulation model also calculates the water
evaporated by cooling systems, water used by coal cleaning facilities, and the
make-up water demanded by FGD systems. (FGD make-up replaces water lost by
evaporation as well as that contained in the settled sludge.) Water data reported
in this chapter will emphasize the FGD makeup component.
Like other pollution control devices, the use of FGD on a generating unit
consumes energy and reduces the net generating capability of the unit. The
energy requirement ranges from three to ten percent of the boiler input,
depending upon the kind of system used, the coal characteristics, and the level of
See Table 2-1.
J~ I
-------
control. Generating capability penalties average about five percent of the
uncontrolled value, again depending upon the particular system and the operating
conditions. Parameters relating to energy and capability penalties, as well as the
costs of FGD and particulate controls, were adjusted for this study to be
consistent with those developed for EPA by Pedco Environmental, Inc., another
contractor supporting the NSPS review effort.
3.1 BASELINE EMISSIONS OF SO2, NOx, AND PARTICULATES
National emissions of S07, NO , and particulates from fossil-fueled electric
£ X
generating units in 1976, the first year simulated, are shown in Table 3-1. Also
shown are some estimates of emissions from other references.
In comparing the results of these simulations in the years before 1983 with data
from other sources, it is important to keep in mind the assumptions we have used
regarding compliance with emission regulations. It was noted in Table II that
full compliance with State Implementation Plan (SIP) limits is not achieved in the
s
model until 1980. In particular, retrofitting of high efficiency electrostatic
precipitators* and FGD systems for purposes of compliance with SIP limits
occurs over the period 1977 through 1979. This compliance schedule causes the
particulate levels shown in Table 3-1 to decrease dramatically between 1976 and
1980, even though the amount of electrical energy generated from coal and oil
steam plants increases by approximately 23 percent over that period. Units that
comply with their SIP limit by use of low sulfur coal, rather than by retrofit of
FGD, are in compliance as of the first year of the simulation. Since only a
Particulate controls of varying degree were imposed upon most coal-fired
generating plants even before passage of the original Clean Air Act
Amendments in 1970. Because of this, we assume that cyclone devices
were used by all units on-line by the base year for the simulation (1975).
Collection efficiencies are assumed to be 50 percent (mass basis) for units
on-line before 1950, and 85 percent for newer units. "Uncontrolled" emis-
sions of particulates include these assumptions.
3-2
-------
Table 3-1
Notional Power-Plant Emissions of SOy NO^, and Particulates in 1976 and 1980
( Million Metric Tons )
Calculated Calculated ,
Emissions Emissions l973 Emissions
Pollutant
in 1976
in I960 from Source I1
1975 Emissions
from Source 2°
so2
NO
X
Particulates
13.6
4.6
4.9
14.4
5.6
0.8
17.6
6.3
3.3
12.1
6.1
2.4
a One ton (2000 Ib) = 0.9070 metric ton.
U.S. Environmental Protection Agency, 1973 Nationol Emissions Report 450/2-76-007,
1976.
c U.S. Energy Research and Development Administration, Regional Air Emissions
Analysis of Alternative Energy Policies in 1985, 1977 (EPA data). :
relatively small fraction of SIP-controlled coal-fired units will use FGD (about
23 percent) and since oil-fired units in the model comply with all SOo emission
limits through use of low sulfur oil, the effect of the 1980 deadline for
compliance is less important in comparing the S02 numbers. The observed rise in
S02 is due to the increase in fossil-fired generation between 1976 and 1980.
Finally, very few states have SIP limits for NO , so the-assumed compliance
period is not a factor in comparing the NO values with other estimates. As can
* J\
be seen the other estimates indicated compare well with the Utility Simulation
Model results.
Projections over time of aggregate emissions for the three criteria pollutions are
shown in Figures 31, 3-2, and 3-3, assuming no change in the current NSPS.
These curves define the "baseline" projections against which reductions in
emissions due to imposition of different revised standards can be weighed. The
3-3
-------
30 n
25-
D
-------
5.0
§
I
O
to
(£
5
LU
UJ
t-
<
_i
y
i
cr
<
0.
4,0
2.0
1.0
a= H \3 (0) 0.4 scenario
b= M 1.2 (0) O.I scenario
1975
I960
1985
1990
1995
2000
Figure 3-2. National power-plant participate emissions under
baseline scenarios.
3-5
-------
16.0,
15.0-
14.0-
I2.C-
10.0-
s
&
o
8.0
6.0
to
=? 4.0
UJ
t
1975
o=H 1.2(0)0.1 scenario
b=M 1^(0)0.1 scenario
1980
1985
1990
1995
2000
YEAR
Figure 3-3. National power-plant NOy emissions under
the baseline scenarios.
3-6
-------
results lead to the following conclusions about aggregate emissions from electric
power generation:
National emissions of S02 from electric power plants will
increase from 1976 partial compliance levels (about
13.6 million metric tons) at about 2 percent per year until
1985, if electricity demand grows at 5.8 percent per year
until 1985.
Under high demand growth after 1985 (5.5 percent per
year in total demand and roughly 6 percent per year in
coal-fired generation) national 862 emisisons under cur-
rent standards will increase at approximately 2.5 percent
per year. A revised NSPS with 90 percent required
removal will slow this growth in national SC^ emissions to
less than one percent per year between 1985 and 2000.
Under moderate demand growth and the present emission
standards national SO? emissions will increase at approxi-
mately 0.4% per year Trom 1985 to 2000. A revised NSPS
with 90 percent removal will bring about a net decrease
in national SOj emissions after 1985. By the year 2000
national SOU emissions will be approximately equal to or
below 1976 aggregate SCU emissions.
_ In 1995 SO? emissions in the high demand case will be
reduced from the baseline projections (current NSPS) by
17 percent for mandatory 80 percent post-combustion
removal and by 27 percent for mandatory 90 percent post-
combustion removal. In 2000 the reduction of national
SO- emissions is projected to be 35 percent with the
90 percent removal standard, 21 percent with the 80
percent removal standard.
A reduction in the electricity demand growth rate after
1985 to 3.4 percent per year, along with a continuation of
the current NSPS S02 standard, will result in a national
S0? emissions level m 2000 comparable to the level of
emissions achievable under a 5.5 percent per year demand
growth rate after 1985 and the 90 percent SO2 removal
standard. There are, however, regional differences in the
distribution of emissions in these cases.
Assuming the moderate growth rate, total particulate
emissions will increase only slightly above the present full
compliance level, and wiH remain nearly constant there-
3-7
-------
after, again assuming full compliance with existing emis-
sion limitations. High demand growth by the mid-1980s
would lead to further growth in particulate emissions
throughout the 1990s to about I.I million metric tons per
year.
Emissions of NO from power generation will increase
substantially undei current standards, even assuming an
effective electricity demand conservation program. Ex-
tensive deployment of new combustion technologies (such
as fluidized bed), would be needed in order to slow the rise
in nationwide NO emissions in the 1990s.
In 1976 the national average capacity factor* simulated for all coal-fired
generating units was 0.54. Because of increasing demand the simulated capacity
factor rises to 0.59 in 1985. This increase is reasonable because of falling utility
reserve margins in the early 1980s and the emphasis on coal-fired generation.
Since existing coal units are generally cheaper than newer units to operate and
since existing coal units are subject to SIP emission limits which are usually less
stringent than the current new source limits of 516 ng/J (1.2 Ib/IO Btu) for coal
and 413 ng/J (0.8 Ib/IO Btu) for oil units, this increase in capacity factors for
existing units will have adverse air quality impacts. Indeed plants subject to SIP
regulation account fqr the bulk of $©2 emissions as shown in Table 32. This
data suggests that tighter standards for SIP plants may eventually be needed to
substantially reduce SO2 emissions in some regions.
In the Utility Simulation Model each type of generating unit is constrained by an
availability and a maximum capacity factor for each state. This reflects the
fact that all units need to be out of commission for scheduled maintenance and
unanticipated down-time. The projections reported here assume a yearly
The capacity factor measures the extent to which a generating unit is
utilized. It is calculated as the ratio of the energy actually generated in a
given year to that which would have been generated if the unit had run at
full rated capability throughout the entire year. "Base-load" units normally
have capacity factors between 0.5 and 0.8.
3-8
-------
Table 3-2
Aggregate SO^ Emissions from Fossil-Fueled Generation, by Category of Unit
(10 metric tons/year)
Year
1985
1995
2000
a
b
c
Scenario M 1
SIP
Units
13.3 (89%)
11.5 (73%)
10.5 (66%)
.2(0)0.1°
NSPS
Units
I.I (7%)
1.0 (6%)
1.0 (7%)
Scenario HI. 2(0)0. lb
Post
I982C
Units
0.7 (4%)
3.3 (21%)
4.4 (27%)
Moderate growth baseline. (Chapter 1, Table
SIP
Units
14.1 (89%)
12.3 (61%)
11.7 (49%)
1-4)
NSPS
Units
1.0 (7%)
I.I (5%)
I.I (5%)
Post
I982C
Units
0.6 (4%)
6.9 (34%)
11.0 (46%)
High growth baseline.'
These are assumed
NOTE: See Table 2-6
to be subject to any revision to the
current NSPS
for corresponding generating capacities.
availability of 0.85 for coal units and base-loaded coal units may be dispatched
up to a maximum capacity factor of 0.77. Daily load curves and a least-cost
dispatch order always lead to lower aggregate capacity factors for each class of
unit for each state and year. However, it has been argued that future
availabilities of coal units with FGD systems will be less than present
i,
availabilities. The question of availabilities and of the expected capacity factors
is of importance, particularly in the early 1980s when a number of states will
have reduced reserve margins. Further work is anticipated to test the sensitivity
of the absolute levels of emissions to our assumptions of future availabilities and
maximum allowable capacity factors.
3-9
-------
EMISSION CHANGES DUE TO NSPS REVISIONS
3.2.1 Some Comments on the Alternatives
As detailed in Chapter I, there are three alternative forms of a revised New
Source Performance Standard for S02 emissions from coal-fired boilers which
are discussed in this report:
Mandatory 90 percent post-combustion SO, removal with
an upper limit on emissions of 516 ng/J (I.z Ib/IO Btu).
Mandatory 80 percent post-combustion S02 removal with
the same upper limit.
An upper limit of 215 ng/J (0.5 Ib/IO6 Btu) with no postu-
lated minimum percentage removal.
Depending upon the circumstance, either the percentage removal requirement or
the emission "cap" can be the controlling factor. Consider an "average"
midwestern coal with a sulfur content of 3.5 percent and a heating value of
25,600 kJ/kg (11,000 Btu/lb). The rate of uncontrolled SO2 emissions in this case
would be 2,580 ng/J (6.0 Ib/IO6 Btu).* Emissions under the 90 percent removal
requirement would be 258 ng/J (0.6 Ib/IO6 Btu), and 516 ng/J (1.2 Ib/IO6 Btu)
with the 80 percent variation. In both cases, the 516 ng/J cap is not controlling -
- and in fact it would not be controlling for all coals whose sulfur content is equal
to or less than about 1,370 nanogram sulfur per Joule (3.2 Ib/IO btu), which are
the bulk of the utility steam coals currently being burned. Note also that for the
example coal just considered, 80 percent removal would be dictated by the
current NSPS of 516 ng/J. Hence, utilities subject to the current NSPS and
We assume an emission factor, K, of 0.95 for bituminous coals and 0.85 for
subbituminous coals. Uncontrolled emissions of SO, are calculated as
(2KS(%))/(HV/IO ), where HV is the coal heating value (English units).
3-10
-------
burning coals where sulfur levels are at least 1,370 ng/J (3.2 Ib sulfur/106 Btu)
would incur no additional S02 control costs in complying with the 80 percent,
516 ng/J "cap" standard, assuming the averaging times used to define compliance
and monitoring requirements were the same.
The third type of revised standard, a limit of 215 ng/J with no minimum removal
requirement, would amount to a less stringent standard than the 90 percent
removal case for many coals, namely those with sulfur levels less than 1,130 ng/J
(2.63 Ib/10 Btu). For a good quality bituminous coal with two percent sulfur and
a heating value of 27,900 kJ/kg (12,000 Btu/lb), an emission limit of 215 ng/J
(0.5 Ib/IO Btu) and an 80 percent removal requirement are nearly equivalent, all
other factors being equal.
Quantitative projections of SO^ and participate emissions by geographic region
under the present standard and the candidate NSPS revisions are given in the
next section. Projections of NO emissions are not shown, since all alternatives
ft
assumed the same limit (258 ng/J or 0.6 Ib/IO Btu),, and because the changes
from the baseline projections are very small (less than 10 percent decrease in the
year 2000). Variations in sulfur emissions brought about by a change in the
particulate limit are also small, and therefore not all combinations of revised
particulate and SQ^ limits are shown. Finally, the reader is reminded that we
have assumed in this study that the NSPS revisions apply only to coal-fired
generating units of 25 Mw or greater rated capacity which begin operation in
1983 or later. As a result, variations caused by revised controls are zero or
negligible before 1985. (Refer to Chapter 2, Table 2-6 for a breakdown of
generating capacity by SIP, NSPS, and revised NSPS categories.)
3,2.2 Emission Data
^
National and regional projections of SC^ emissions under all the SC>2 control
variants are given in Table 3-3, including the baseline scenarios. National
emissions are plotted in Figures 3-4 and 3-5. (Results for scenario M0.5(0)0.03)
3-11
-------
Table 3-3
Regional ond Notional Power-Plant SCX Emissions
(Million metric tons per year)
Scenario Ml.2(0)0.1
Region 1976 1985 1990 1995 2000
NE .23 0.25 0.31 0.25 0.26
MA 2.06 |.70 1.66 1.62 1.69
SA 3.09 3.62 3.53 3.73 3.80
ENC 3.50 3.96 3.79 3.69 3.61
ESC 2.64 2.44 2.38 2.28 2.00
WNC 1.32 |.6I 1.58 1-70 1.83
WSC O.I I 0.95 1.52 1.73 1.91
NM 0.12 o.09 0.13 0.18 0.24
SM 0.34 o.23 0.30 0.28 0.28
PA 0.20 o.3l 0.31 0.33 0.29
National 13.6 15.2 15.5 15.8 15.9
Scenario Ml.2(80)0.03
Region 1985 1990 1995 2000
NE .24 0.29 0.22 0.22
MA |.68 ' 1.59 1.52 1.53
SA 3.93 3.82 3.82 3.68
ENC 4.36 3.96 3.64 3.22
ESC 2.44 2.39 2.28 2.05
WNC |.43 1.37 1.53 1.76
WSC 0.78 1.02 1.12 1.14
NM 0.07 0.07 0.09 0.1 I
SM 0.20 0.20 0.20 0.18
PA 0.27 0.25 0.21 0.16
National 15.4 15.0 14.3 14.1
3-12
-------
Table 3-3 (continued)
Regional and National Power-Plant SO., Emissions
Scenario Ml. 2(90)0.03
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
Scenario M0.5(OX).03
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
(Million
1985
0.23
1.65
3.88
4.30
2.44
1.43
0.74
0.06
0.19
0.26
15.2
1985
0.23
1.65
3.88
4.30
2.44
1.43
0.79
0.08
0.21
0.28
15.3
metric tons per
1990
0.25
1.49
3.60
3.90
2.35
1.35
0.84
0.05
0.17
0.22
14.3
1990
0.26
1.49
3.61
3.90
2.36
1.41
1.08
0.09
0.23
0.27
14.7
i
year)
1995
0.18
1.36
3.49
3.58
2.25
1.49
0.79
0.06
0.16
0.19
13.6
1995
0.19
1.37
3.50
3.59
2.25
1.53
1.20
0.12
0.25
0.24
14.3
2000
0.18
1.29
3.24
3.17
2.00
1.69
0.76
0.07
0.13
0.13
12.7
2000
0.18
1.30
3.26
3.17
2.01
1.75
1.23
0.16
0.25
0.19
13.5
3-13
-------
Table 3-3 (cont.)
Regional and National Power-Plont SQ^ Emissions
(Million metric tons per year)
Sc«ncrioH 1.2(0)0. 1
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
1985
0.25
1.67
4.04
4.29
2.43
1.56
0.94
0.07
0.23
0.32
15.9
1990
0.26
1.62
4,19
4.75
2.28
1.63
1.84
0.14
0.31
0.43
17.5
1995
0.32
1.72
4.67
5.45
2.26
1.93
2.71
0.28
0.38
0.60
20.3
2000
0.44
1.87
5.18
6.14
2.44
2.29
3.49
0.42
0.56
0.90
23.8
Scenario Hi.2(80)0.03
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Motional
]985
0.24
0.00
3.75
3.66
2.40
1.30
0.75
0.06
0.20
0.26
14.3
1990
0.24
1.67
3.96
4.11
2.30
1.34
0.98
0.09
0.20
0.26
15.2
1995
0.29
1.97
4.04
4.78
2.25
1.65
1.22
0.12
0.21
0.26
16.8
2000
0.38
2.16
4.09
5.56
2.51
1.91
1.44
0,15
0.24
0.32
18.8
3-14
-------
Table 3-3 (coot,)
Regional and National Power-Plant SO-> Emissions
(Mi IIion "metric tons per year)
Scenario HI. 2(90)0.03
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
19
1
3
6
4
3
1
2
0
0
1
24
1985
0.23
1.65
3.70
3.60
2.39
1.30
0.73
0.06
0.19
0.25
14.1
1990
0.20
1.54
3.62
3.91
2.27
1.31
0.82
0.07
0.17
0.24
14.2
1995
0.22
1.59
3.46
4.29
2.37
1.59
0.90
0.08
0.15
0.22
14.9
2000
0.24
1.60
3.27
4.67
2.47
1.75
0.98
0.09
0.15
0.24
15.5
3-k5
-------
30-i
25-
o
v
I
20-
o
o
15-
to
g
to
to
LLl
(N
O
CO
10-
a = M 1.2(0)0.1 scerKirio
b = M 1.2(80) 0.03 scenario
c = M 1.2(90) 0.03 scenario
5-
1975
1980
1985
1990
1995
2000
Figure 3-4. National power-plant SO- emissions
under alternative control scenarios, moderate growth.
3-16
-------
30
25-
o
0)
fc
a.
0)
o
20-
15 -
to
O
co
CO
LU
C
O
CO
10 -
a = H 1.2(0)0.1 scenario
b = H 1.2(80) 0.03 scenario
c = H 1.2(90) 0.03 scenario
5 -
1975
I960
1985
1990
1995
2000
Figure 3-5. National power-plant SO^ emissions under
alternative control scenarios, high growth.
3-17
-------
Table 3-4
Regional Emission Reductions in 1990 Due
to Mandatory
90 Percent S>O? Removal High Growth Scenarios
(Million metric tons emitted)
Region
South Mountain
West South Central
North Mountain
Pacific
New England
West North Central
East North Central
South Atlantic
Mid Atlantic
East South Central
National
HI. 2(0)0.1
0.32
1.85
0.15
0.43
0.26
1.64
4.75
4.20
1.63
2.28
17.5
H 1.2(90)0.03
0.17
0.82
0.07
0.25
0.20
1.31
3.91
3.63
1.54
2.27
14.2
Change in SO2 Emissions
I06 Tonnes
- .15
-1.03
- .08
- .18
- .06
- .33
- .84
- .57
- .09
- .01
-3.3
Percent
-47%
-56%
-53%
-42%
-23%
-20%
-18%
-14%
- 6%
- 0%
-19%
3-18
-------
are not shown because the results are close to those for scenario M1.2(80)0.03;
see Table 3-3.)
The revised standards have the greatest relative impact in those geographic
areas which do not presently have a large base of coal-fired generation. This is
particularly true of the West South Central region in which 87 percent of the
base-year (1975) generating capacity was oil and gas-fired. For the 90 percent
control scenario with high growth Table 3-4 shows aggregate emission reductions
in 1990 by region.
In 1990 a ninety percent removal standard reduces national SOj emissions by
3.3 million metric tons (19%), while the West South Central region (56%),
North Mountain region (53%), South Mountain region (47%), Pacific region (42%)
and the New England region (23%) have the greatest percentage emissions
reductions.. In terms of total tonnage emission reduction the West South Central,
East North Central and South Atlantic regions have the largest SC^ emissions
removal.
National projections of particulate and NOX emissions, assuming the higher
growth rate, are shown in Table 3-5 and Figure 3-6.
3-19
-------
Table t-5a
Regional and National Power-Plant NO Emissions
(Million metric tons per year)
Scenario Hl.2(90)0.03
Region 1985 1990 1995 2000
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
.11
.69
1.23
1.66
.62
.75
1.08
.19
.45
.33
7.17
.13
.80
1.58
2.02
.65
.91
1.81
.31
.56
.56
9.33
.17
1.10
1.85
2.57
.81
1.32
2.61
.47
.66
.73
12.29
.26
1.34
2.13
3.18
1.03
1.78
3.61
.62
.82
1.17
15.93
-------
Table 3-5b
Regional and National Power-Plant Particulate Emissions
(Million metric tons per year)
Scenario Hl.2(0)0.1
Region 1985 1990 1995 2000
NE .016 .018 .023 .034
MA .14 .12 .11 .10
SA .26 .28 .34 .39
EMC .25 .27 .31 .36
ESC .11 .11 .11 .12
WNC .10 .12 .14 .15
WSC .06 .08 .09 .11
MM .005 .006 .009 .Oil
SM .044 .045 .043 .042
PA .033 .037 .040 .055
National 1.02 1.09 1.22 1.38
Scenario Hl.2(90)0.03
Region 1985 1990 1995 2000
.015
.11
.21
.28
.14
.137
1.05
.012
.031
.048
1.08
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
National
.015
.14
.24
.24
.12
.070
.04
.005
.042
.030
.94
.012
.12
.23
.25
.12
.096
.06
.007
.037
.035
.97
.013
.11
.22
.27
.13
.120
.08
.010
.031
.037
1.03
-------
5.0 T
x
to
Q.
ID
O
to
O
to
LU
LJ
<
_J
u
h-
tr
<
CL
4.0 -
3.0 -
2.0
1.0
1.2(0)0.1
b = H 1.2(90)0.03
1975
1980 1985 1990 1995
YEAR
2000
Figure 3-6. National power-plant particulate emissions,
high growth
3-20
-------
These results show that tightening the participate NSPS for coal-fired units from
the current 43 ng/J (0.1 lb/!06Btu) to 13 ng/J (0.03 Ib/IO6 Btu) reduces total
particulate emissions from power generation by II percent by 1990 and by
22 percent by 2000, assuming a 5.5 percent per year energy demand growth
after 1985. (Corresponding results for the lower growth rate scenarios are
9.0 percent and 12 percent, respectively.) Changes in aggregate emissions of
N0x due to a revised NSPS value of 258 ng/J (0.6 lb/!06Btu) are negligible,
since emissions from the large base of unaffected (pre 1983) units swamp the
14 percent reduction achieved by individual post 1982 units. (Similarly, it should
be remembered that the revised particulate standard would reduce emissions
from individual post-1982 units to one-third, which might have a more substantial
effect at the local level than the national aggregate numbers imply.)
Salient features of these data can be summarized as follows:
The maximum reduction in national SO, emissions from
the level projected with the current NSPS is projected to
be 35 percent, obtained in the year 2000 under high
growth conditions with a 90 percent removal revised
standard.
Relaxing the SC^ removal requirement from 90 percent to
80 percent reduces the maximum projected reduction to
21 percent.
Assuming a moderate electricity demand growth rate
after 1985, the maximum projected reduction in SC>2
emissions in 2000 at the national level is 20 percent.
More stringent new source standards have a more substan-
tial impact at the regional level: emissions of SC^ in the
Mountain and West Central states will be reduced by
49 percent and 39 percent by 1990, respectively, assuming
the 90 percent removal requirement.
Given the coal sulfur levels used in this analysis, the
amount of SO7 emitted under the 80 percent removal
standard and 1T»e 2l5ng/J (0.5 Ib/IO* Btu) standard are
nearly the same in most regions. Nationally, emissions
differ by a maximum of four percent. In the Mountain
states, where relatively low sulfur coals are used, the
80 percent removal requirement further reduces emissions
by about 30 percent in 2000.
3-21
-------
Revising the new source standard for participates down-
ward to 13 ng/J (0.03 lb/10 Btu) reduces national aggre-
gate emissions by a maximum II percent in 1990 and
22 percent in 2000.
3.3 SOUD WASTES
Since this analysis assumes that lime and limestone FGD systems will be the
predominate technology used to meet the revised SO2 emissions standards,
quantifying the solid wastes generated by them is an important part of the
impact assessment.* The principal chemical constituents of FGD sludge are
calcium sulfite (CaSO.0, calcium sulfate (CaSOj, and calcium carbonate
(limestone, CaCO.0. Sludge solids also contain various trace elements with
concentrations ranging up to 100 mg/l. Some of these, such as soluble species of
mercury, are considered toxic. (Arsenic, lead, and selenium are also of concern.)
The potential environmental problems associated with sludge disposal, and the
available techniques that may be used to solve these problems, are discussed in
another report commissioned by EPA.
Tons of sludge generated by FGD systems under the high growth scenarios are
shown in Table 3-6. Note that the figures are expressed on a dry basis. The
actual mass of sludge that has to be disposed is double the tonnage shown since
the settled waste product is approximately 40-50 percent water. (Also, collected
fly ash is not included in these figures.)
Our assumptions about the distribution of different types of FGD systems
are given at the beginning of Chapter 3.
3-22
-------
Table 3-6
Projections of Sludge Produced by FGD Systems
(Million metric tons, dry basis)
Year = 1990
Year = 1995
Region0
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Nation
HI. 2(0)0.1
negligible
0.52
1.8
2.0
0.14
0.
0.89
0.18
0.82
0.18
8.1
HI. 2(80)0.03
negligible
3.6
7.9
5.0
0.43
0.48
3.6
0.67
1.2
0.64
24.
HI. 2(90)0.03
negligible
4.5
9.0
5.7
0.50
0.59
4.1
0.77
1.4
0.88
27.
H 1.2(0)0.1
negligible
0.38
1.5
4.7
0.044
0.
0.90
0.18
0.76
3.7
12.
HI. 2(80)0.03
negligible
8.3
13.
II.
1.3
1.8
6.8
I.I
1.5
I.I
46.
HI. 2(90)0.03
negligible
10.
15.
13.
2.0
2.2
7.8
1.3
1.8
1.4
55.
a
b
See Table 2-1.
See discussion at beginning of this chapter: wastes produced by regenerable
systems are neglected.
3-23
-------
Estimates of the land requirements for sludge ponding are shown in Table 3-7,
assuming that the settled sludge is allowed to accumulate to a depth of
9.1 meters (30 feet), and that it is 47 percent water with a density of 1.4 g/cc.'
The areas shown are cumulative for the period 1990 to 2000.
The solid waste besides scrubber sludge which is produced in quantity at a
generating plant is coal ash. Approximately 80 percent of the ash is carried with
the flue gas (fly ash), the remaining being bottom ash. All but a few percent of
the fly ash must be captured to satisfy even the SIP emission limits (limits for
particulates averaging about 86 ng/J, or 0.2 Ib/IO Btu), and therefore essentially
all of the coal ash appears as solid waste. Since the particulate limits considered
here are in terms of emission rates (grams per Joule or pounds per million Btu)
rather than percent removals, ash production depends mainly on the growth in
coal consumption. Thus variations among the different SC^ control options are
not significant. Values for 1990, 1995, and 2000 are shown in Table 3-8. By
dividing these figures by the total coal tonnages consumed in these years
(cf. Figure 2-1) we infer an average coal ash content of about eight percent by
weight.
Assuming an ash storage requirement of 1.54 cubic meters per metric ton of ash
and a storage depth of nine meters, cumulative ash production over the years
1990-2000 under the high growth assumption would require 176 square kilometers
o
(68.0 mi ) of storage area. This compares with the 91.5 square kilometers
o
(35.3 mi ) for sludge disposal shown in Table 3-7.
3.4 WATER REQUIREMENTS
Table 3-9 gives the regional breakdown of water consumed by FGD systems under
the moderate and high growth scenarios, assuming full scrubbing of all post 1982
coal-fired units (90 percent SO2 removal requirement), and then 89 percent
scrubbing (80 percent removal requirement: cf. discussion in Chapter 2,
Section 2.2).
3-24
-------
Table 3-7
Cumulative Land Area Needed for Sludge Disposal, 1990-2000°
(square kilometers)
Scenario
Ml. 2(0)0.1
Ml. 2(80)0.03
Ml. 2(90)0.03
HI. 2(0)0.1
HI. 2(80)0.03
HI. 2(90)0.03
Land
15.0
39.2
43.8
15.1
80.7
91.5
Area
(5.8 mi2)
(15 mi2)
(17 mi2)
(5.8 mi2)
(31 mi2)
(35 mi2)
At a depth of nine meters (30 feet).
Table 3-8
Total Coal Ash Production
Growth Rate
moderate
high
(Millions of
1990
61.9
73.5
metric tons)
1995
68.1
101
2000
74.9
135
3-25
-------
Table 3-9
Water Consumed by FGD Systems
(Millions cubic meters per year)*
Scenario Ml. 2(0)0.1
Region
NE
MA
SA
EMC
ESC
WNC
WSC
NM
SM
PA
Nation
Scenario Ml. 2(90)0.03
Region
NE
MA
SA
EMC
ESC
WNC
WSC
NM
SM
PA
Nation
1990
3.99
26.5
16.8
15.3
7.07
negligible
14.1
6.26
24.7
negligible
115
1990
4.73
25.3
47.0
20.1
5.54
7.13
72.1
13.8
40.7
9.65
241
1995
4.74
28.5
13.9
15.7
6.90
negligible
14.1
6.80
23.3
negligible
114
1995
5.48
33.2
64.7
19.3
6.86
13.2
111
19.6
37.1
12.1
322
2000
5.73
31.6
13.0
15.9
5.76
negligible
14.2
6.61
21.2
negligible
114
2000
6.63
44.7
80.5
16.8
7.52
23.6
133
24.1
38.5
11.7
387
One acre-foot = 1,234 cubic meters
3-26
-------
Table 3-9 (continued)
Water Consumed by FGD Systems
Scenario HI. 2(0)0. 1
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Nation
(Millions
1990
4.65
11.5
18.0
17.0
1.13
negligible
13.9
6.65
24.6
negligible
94.5
cubic meters per year)*
1995
8.04
8.13
14.2
36.0
0.348
negligible
14.2
6.71
22.6
negligible
110
2000
14.7
5.07
15.3
59.8
0.106
negligible
14.2
6.78
20.7
negligible
137
Scenario H1.2(90)0-03
Region
NE
MA
SA
ENC
ESC
WNC
WSC
NM
SM
PA
Nation
1990
5.43
39.7
63.9
37.5
73.91
13.5
92.7
19.9
37.8
22.2
337
1995
9.40
75.0
103
82.2
13.2
35.0
174
31.8
46.4
36.6
607
2000
18.5
105
143
134
30.2
65.4
258
42.3
.57.5
71.9
927
One acre foot = 1,234 cubic meters.
3-27
-------
Table 3-9
Water Consumed by FGD Systems
(Millions cubic meters per year)
Scenario HI. 2(80)0.03
Region
ME
MA
SA
ENC
ESC
WNC
WSC
NM
WS
PA
Nation
1990
4.92
32.9
58.4
33.7
3.54
12.1
83.9
17.5
34.3
17.8
299
1995
8.53
64.7
92.8
72.9
9.37
30.1
158
27.8
39.9
32.0
534
2000
16.4
91.8
127
121
25.3
57.0
232
37.1
51.0
63.6
823
One acre foot = 1,234 cubic meters.
3-28
-------
Whether or not the water demands shown in the table would constitute a
significant impact on an area's water supplies of course depends on the region
and locale within the region. Parts of the South and North Mountain areas and
southern and central inland California are critical areas. However, it helps to
put the FGD consumption quantities in perspective by comparing them with the
other major consumptive use of water by power plants: condenser cooling. The
rate of evaporation by generating plant cooling systems under scenario
Ml.2(90)0.03 is projected to be 6.84 million acre-feet per year by 2000 - twenty-
two times the consumptive rate projected for scrubbers.
A final water use which the simulation model quantifies is the amount of highly
polluted "black water" discharged by coal preparation plants which clean coal for
sulfur removal. Based on the coal sulfur levels which were supplied to Teknekron
for this study, judgments were made as to which coals should be considered
cleaned - tonnages of cleaned coal consumed varied from 29 percent of the total
in the early years of the simulations to 11 percent in the later years with the
revised NSPS in effect. Generally, a mandatory SO 2 removal of 80 percent or
more discourages the use of cleaned coals: this effect is evident in the water
data shown in Table 3-10. These data should not be considered definitive,
however, because of the judgmental factors involved in labeling a coal cleaned or
uncleaned. (For example, ICF, Inc., the EPA contractor who supplied the coal
data for this study considers only about one percent of the coals to be "deep
cleaned" for sulfur removal with the revised standards in effect. )
Table 3-10 Water Discharged by Coal Cleaning Plants in 1995*
(Millions cubic meters per year)
Goal Supply Region0 Scenario HI.2(0)0.1 Scenario HI.2(90)0.1
Appalachia 151 90.0
Midwest 70.5 67.4
Nation 221 157
a The coal supply regions are defined in more detail in Section 3.4.
* See cautionary note in text. One acre foot = 1,234 cubic meters.
3-29
-------
ENERGY REQUIREMENTS
The energy requirements of FGD systems hove two components: (I) the
electrical power consumed in operating the system (between three and four
percent for a 500 Mw unit with full scrubbing of a high sulfur coal); (2) fuel
consumed in reheating the flue gas after scrubbing (done in cases where the gas
is scrubbed to insure adequate plume dispersion and to prevent condensation and
corrosion).'' An indirect "penalty" also is incurred because of the reduction in
net generating capability approximately five percent for full scrubbing. This
effect has been discussed in Chapter 2: data presented in this chapter address
only the "direct" energy requirements.
Assumptions about scrubber energy demands are those developed by Pedco
Environmental, Inc. Steam is used for reheat on all units subject to current and
revised new source standards. Units subject to SIP limits are assumed to require
retrofit of the scrubber, and oil is used for reheat in these cases. (Oil is also
used in operating the new mag-ox systems. The amount of energy consumed in
both ways is small compared to the energy used for reheat on the newer units.)
Table 3-11 gives the energy consumed by FGD systems in 1995 for the 80 percent
and 90 percent removal standard and the baseline cases, as well as the
percentage of total coal energy consumed.
A second energy impact which could be significant if a revised standard resulted
in large shifts in coal supplies is the change in the energy consumed by railroads
and barges in transporting the coal.* A shift away from the use of western coal
in the Midwest in favor of more local supplies, for example, would be expected to
reduce coal transport energy.
A small amount of coal is also transported over short distances by trucks
this mode is ignored in our calculations.
3-30
-------
Table 3-11
Energy Consumed by FGD Systems in 1995
Energy Capacity Fraction of Coal
Scenario Consumption for FGD Used for FGD Energy for Generation
(I(T Megajoules) (GW)
Ml.2(0)0.1 187 3..6S 0.95%
Ml.2(80)0.03 534 10.5 2.7%
Ml.2(90)0.03 588 11.6 3.0%
HI.2(0)0.I 214 4.21 0.71%
HI.2(80)0.03 944 18.6 3.1%
HI.2(90)0.03 1150 22.6 3.8%
3-31
-------
The Utility Simulation Model estimates energy consumed In coal transport by
assuming supply "nodes" (cities) in coal-supply regions and centrally located
nodes (cities) in each consuming state. Rail and barge transport distances are
then associated with each possible supply-demand nodal pair, using rail and barge
routing maps. The coal supply regions used by Teknekron and the nodal cities are
shown in Tables 3-12 and 3-13.
Calculations of fuel-energy consumed by rail and barge were made assuming the
following modal energy intensities: rail = 366 Btu per ton-mile; barge = 296 Btu
per ton-mile. Results for the 90 percent control scenarios are shown in
Table 3-14.
These results show a significant reduction in fuel consumed with imposition of
the more stringent controls, due primarily to a shifting of demand away from
western coals delivered to states bordering and east of the Mississippi River.
Note in particular that the energy savings in 1995, 50 I09 MJ (4.7 10l3 Btu)
and 120 I09 MJ (I.I 10'* Btu), serve to offset about 10 percent of the direct
FGD energy requirements projected for that year (588 I09 MJ and 1150 I09 MJ)
for moderate and high growth respectively.
-------
CO
Co
10
Table 5-12
Teknekron Cool Supply Regions
Region
Northern Appalachia
Central Appalachia
Southern Appalachia
Interior East
Interior West
Northwest
Central West
Southwest
Texas
Coal Type
bituminous
bituminous
bituminous
bituminous
bituminous
subbituminous
lignite
bituminous
subbituminous
subbituminous
lignite
Symbol
NA/B
CA/B
SA/B
IE/B
IW/B
NW/SB
NW/L
CB/B
CB/SB
SW/SB
TX/L
States Encompassed
OH.PA
WV,VA,KY(east)
TN.AL
IL.IN.KY (west)
IA,KS,MO,OK
MT.ND
MT,ND
UT, CO
WY
AZ.NM
TX
Nodal City
Pittsburgh, PA
Charleston, WV
Chattanooga, TN
Mattown, IL
Kansas City, MO
Billings, MT
Williston, ND
Grand Junction, CO
Casper, WY
Gallup, NM
Palestine, TX
-------
Table 3-13
Coal Demand Nodes
Consuming State
AL
AR
AZ
CA
CO
CT
DL
FL
GA
IA
ID
IL
IN
KS
K.Y
LA
MA
MD/DC
ME
Ml
MN
MO
MS
MT
Enerqy Consumed in
Nodal City
Birmingham
Little Rock
Phoenix
Sacramento
Denver
Hartford
Dover
Orlando
Atlanta
Des Moines
Boise
Springfield
Indianapolis
Topeka
Frankfort
Baton Rouge
Boston
D.C.
Augusta
Lansing
Minneapolis
Jefferson City
Jackson
Billings
Table 3- 14
Transporting Coal to
Consuming State
NC
ND
NE
NM
NH
NJ
NV
NY
OH
OK
OR
PA
Rl
SC
SD
TN
TX
UT
VA
VT
WA
Wl
WV
WY
Electric Generating
Nodal City
Raleigh
Bismark
Lincoln
Concord
Trenton
Albuquerque
Carson City
New York
Columbus
Oklahoma City
Salem
Harrisburg
Providence
Columbus
Pierre
Nashville
Austin
Salt Lake City
Richmond
Montpelier
Olympic
Madison
Charleston
Casper
Plants
Q
(10 Megajoules)
Scenario
Year Ml. 2(0)0.1
1976 100
1990 250
1995 300
2000 350
Scenario
ML2(90X>.I
100
230
250
260
Scenario
HI. 2(0)0.1
100
370
560
780
Scenario
HI. 2(90)0.1
100
320
440
580
3-34
-------
REFERENCES
I. Teknekron, Inc., Berkeley, California, An Integrated Technology
Assessment of Electric Utility Energy Systems, Vol. I, The Assessment, and
Vol. II, Components of the Impact Assessment Model. Draft First Year
Report. Prepared for the Office of Energy, Minerals and Industry, Office
of Research and Development, U.S. Environmental Protection Agency.
January 1977. (See also: "Electric Utility Energy Systems Integrated
Technology Assessment," Dr. Lowell Smith, in Energy/Environment II,
Proceedings of the Second National Conference on the Interagency R&D
Program, U.S. Environmental Protection Agency, Office of Energy,
Minerals and Industry. November 1977.)
2. Communication from the President of the United States, National Energy
Act, House of Representatives, 95th Congress, Document No. 95-138, April
29, 1977.
3. U.S. Department of Commerce, Bureau of Census, February 1975.
Projections of the Population of the United States by Age and Sex, 1975 to
2000, with Extension of Total Population to 2025. Advance Report,
Series P-25, No. 541. Washington, D.C.
4. Edison Electric Institute. Statistical Year Book of the Electric Utility
Industry for 1976. October 1977.
5. ICF, Incorporated, Effects of Alternative New Source Performance
Standards for Coal-Fired Electric Utility Boilers on the Coal Markets and
on Utility Capacity Expansion Plans, Draft Executive Summary, November
23, 1977. (Full report to be submitted in January 1978.)
6. Pedco Environmental, Inc. Particulate and Sulfur Dioxide Emission Control
Costs for Large Coal-Fired Boilers. Preliminary draft report submitted to
the U.S. Environmental Protection Agency, Emission Standards, and
Engineering Division, November 1977.
7. Staff Report by the Bureau of Power, Federal Power Commission. Annual
Summary of Cost and Quality of Electric Utility Plant Fuels, 1976,
May 1977.
8. U.S. Department of the Interior, Bureau of Mines, Washington, D.C.
Mineral Industry Surveys, Coal - Bituminous and Lignite in 1975,
February 1977.
9. Radian Corporation, The Effect of Flue Gas Desulfurization Availability on
Electric Utilities, Draft Report, submitted to Environmental Protection
Agency, Industrial Environmental Research Laboratory, December 1977.
4-1
-------
10.' Aerospace Corporation, Civil Operations Division, the Solid Waste Impact
of Controlling SO- Emissions from Coal-Fired Steam Generators,
Volume II: Technical Discussion, Report submitted to U.S. Environmental
Protection Agency, Industrial Environmental Research Laboratory,
Research Triangle Park, North Carolina, October 1977.
11. Radian Corporation. An Assessment of Energy Penalties for Controlling
S02 Emissions from Coal-Fired Electric Generating Plants, Preliminary
Draft Report, submitted to U.S. Environmental Protection Agency,
Emission Standards and Engineering Division, Industrial Research Labora-
tory, Research Triangle Park, North Carolina, August 1977.
12. Private communication from Dr. Andrew Loebl, Transportation Energy
Conservation Program, Oak Ridge National Laboratory, Oak Ridge,
Tennessee, September 18, 1977. The barge figure is for inland waterways,
average for upstream and downstream traffic.
4-2
-------
APPENDIX
DESCRIPTION OF TEKNEKRONS
ELECTRIC UTILITY
SIMULATION MODEL
AND
ASSOCIATED DATA BASES
-------
APPENDIX
TEKNEKROWS ELECTRIC UTILITY SIMULATION1MODEL
AND ASSOCIATED DATA BASES
PAGE
I. MODEL DESCRIPTION , A-l
Components of Teknekron's Electric Utility
Simulation Model A-6
A. Demand Module A-7
B. System Planning Module A-9
Coal Assignment Model A-13
Coal Transportation Cost Model * A-14
SO2 Control Technology and Cost Model A-14
Particulate Control Technology and Cost Model A-15
C. Dispatch Module .; A-17
D. Financial Module , A-19
E. Residuals Module A-21
F. Regional Air Quality Analysis A-23
«
2. DATA BASE DESCRIPTION A-25
A. Demand Module A-26
B. Planning-Dispatch Module A-27
C, Financial Module A-34
D. Residuals Module A-37
E. Air Quality Models and Data Bases A-38
A-i
-------
I. MODEL DESCRIPTION
For the Environmental Protection Agency's review of New Source Performance
Standards Teknekron has applied its Electric Utility Simulation Model. This
section describes the components of that model and their integration into the
overall model framework. Teknekron's Electric Utility Simulation Model
examines the implications of investment and operating decisions made by
electric utility firms as these decisions may be influenced by energy and
environmental policies, technology choices, and economic conditions. These
implications include forecasts by county for:
Capacity expansion
Electricity generation
Fuel consumption
Pollutant generation
and forecasts by state for various measures of economic and financial costs
arising from each set of decisions.
This highly flexible model developed and reviewed by experts in electric utility
technology, operations, and regulation makes it possible to investigate the
impacts of numerous alternative policies while coherently and consistently
accounting for the many technical, economic, energy, and environmental factors
that directly influence decisions made by utility companies.
Teknekron's Electric Utility Simulation Model consists of a number of intercon-
necting computer modules and data bases that simulate decisions for system
planning and operation, utility finance, and the operation of individual technical
processes. The model is driven by a set of exogenous scenario elements that
include electricity demand levels, financial market conditions, fuel prices and
availabilities, advanced technology deployment, and environmental regulations.
For each scenario, the model calculates the following by geographical region
(county or state) for future years up to 2010:
A-1
-------
Factor demands, including
fuel use, by type and by region of origin
electricity generated
capital requirements, by source (e.g., debt, common
equity, preferred equity)
plant and equipment requirements
releases of air and water pollutants and generation
of solid wastes
Financial statistics for utility firms
Average electricity prices
In order to produce these calculations at the required level of detail, the model
considers generating unit sites located in each county where electricity is pro-
duced, fuel and water are consumed, and pollutants are released. Since utilities
operate as integrated systems, the model presently simulates joint operation
(i.e., dispatching) of all generating units within a state. Finally, the responses of
utility firms to the external environment in which they function may be changed
by the model user by modifying present data bases or specifying alternate
choices for future system planning and system operation. For example, the
particular scenarios evaluated in the New Source Performance Standards Review
encompass a range of futures for electricity demand, fuel selection, choices of
technology, and pollution control regulations as specified by the U.S. Environ-
*F*
mental Protection Agency.
Figure I is a simplified diagram of Teknekron's Electric Utility Simulation Model.
The model includes the following major components:
Demand projection, including
- retail and wholesale sales and purchases
energy generation, i.e., average load growth
peak load growth
A-2
-------
Figure I
TEKNEKRON'S ELECTRIC UTILITY SIMULATION MODEL
>
DEMAND
. %.Mv»
T
PLANNING
\ DISPATCH
" * ":>. "-. -. ^
;- RESIDUALS
V * N A
1JI,
J
MM^fcWj fcM *»!***«
FINANCIAL
REGIONAL AIR
QUALITY ANALYSIS
-------
System planning, including
choice of generating unit type
choice of fuel type, quality, and region of origin
choice of pollution control technology
expansion of transmission and distribution networks
siting of generating units
Dispatch, including
calculation of unit capacity factors for each typical
day of operation, by class of unit
calculation of total fuel, operation, and maintenance
expenses for electricity generation
projection of fuel consumption, by type and region of
origin
pollution control costs and operating characteristics
for the various types of pollution control devices
Financial, including
integration of projected production expenses with
construction expenditures
projection of the firm's balance sheet, income state-
ment, sources and uses of funds, and other financial
statistics
calculation of revenue requirements and electricity
prices
Residuals, including
projection of release rates at the generating unit site
for numerous air and water pollutants and for solid
wastes
projection of consumption of water and other re-
sources
A-4
-------
Regional Air Quality Analysis, including
forecasts of counties having high emissions from
utility and industrial boilers
analysis of historical meteorological data to yield
preferred paths for downwind transport of emissions
from source locations
analysis of emissions, air quality, and meteorological
data to develop source-receptor relationships for S0~
emissions and sulfate concentrations
application of air quality models to determine ambi-
ent concentrations of S09, NO , particulates, and
sulfates - L *
The following sections briefly describe the major components of the model and
their associated data bases. Use of the model requires that a set of scenario
elements be defined. These characterize the issues the user may wish to address,
such as choice of fuel, pollution controls, siting, or the economic viability of
alternative generation technologies.
A-5
-------
COMPONENTS OF TEKNEKRON-S ELECTRIC UTILITY SIMULATION MODEL
This section provides a summary description of each component of Teknekron's
Electric Utility Simulation Model. The current version of the model operates on
a geographical region equivalent to a state by treating all investor-owned firms
and all non-investor-owned firms as two individual firms that own the assets
owned by the actual companies in that state. System planning, dispatching, and
financial simulations are carried out on a state basis separately for the two
classes of firms. Simulations of residuals generation and resource consumption
are carried out for generating units located at the county level. Thus, it is
possible to forecast fuel consumption and pollutant release rates by county and
economic impacts by state. Impacts are then aggregated to state, regional, and
national levels.
A-6
-------
A. DEMAND MODULE
The Demand module, depicted in Figure 2, projects the future electricity
demands that must be met by utility firms. The module now uses 1975 base-year
information, net generation, purchases, net interchanges, and retail and
wholesale sales for each utility company. These data are aggregated to obtain
state-by-state demands for both investor-owned and non-investor-owned utilities.
Alternative growth rates may be specified to develop different demand
projections for analysis. The module uses base-year data for load factors and
monthly generation characteristics to construct seasonal load curves that can be
varied in future years. A variety of data sources are used to determine each
projection. These sources include Regional Electric Reliability Council fore-
casts, FPC Electric Power Statistics, and OBERS population projections.
A-7
-------
Figure 2
DEMAND MODULE
>
00
NET GENERATION
PURCHASES
INTERCHANGES
SALES BY UTILITY
SEASONAL
LOAD CURVES
>.
1
1
FUTURE
ELECTRICITY
DEMANDS
I^MM
" 1
1
1
1
, J
ALTERNATIVES
GROWTH RATES IN PEAK AND AVERAGE DEMAND
LOAD FACTORS
MONTHLY GENERATION
CHARACTERISTICS
-------
B. SYSTEM PLANNING MODULE
The System Planning module, depicted in Figure 3, projects the composition of
the state system; estimates construction requirements for generation, transmis-
sion, and distribution facilities; simulates fuel choice; and determines pollution-
control needs in response to environmental regulation and the costs for alternate
compliance strategies. Steam-generating facilities (both nuclear and fossil) are
treated on a unit-by-unit basis. Nonsteam facilities are treated on an aggregated
basis. Each utility system must be able to meet its peak demands with an
adequate reserve margin, and the availabilities for its classes of generating units
must allow the seasonal loads to be met.
In simulating the composition of the state systems, the System Planning module
uses announced plans of the individual utilities, aggregated to form the state-
firms, on a unit-by-unit basis through 1985, the last year for which reliable data
are available. For subsequent years it uses the utilities' projections of the
composition of new additions, or it may vary additions by scenario. Announced
units are treated as subject to modification in line with scenario specifications
(higher or lower demand levels, higher or lower additions of nuclear capacity, of
oil-fueled capacity, etc.). Units' fuel conversion, retirements, and reratings are
also included. Future units beyond 1986 are sited according to county-specific
siting weights developed by Teknekron for each county in the contiguous
48 states.
Since there is uncertainty about the relative growth rates of peak and average
demand and about the impact of load management policies on hourly and seasonal
loads, the System Planning module is able to change the shape of load curves by
specifying separate growth rates for both peak and average demand.
Environmental regulations for air and water pollution represent both existing
regulations and proposed levels of control for example, thermal and chemical
controls for discharges to water, State Implementation Plans, New Source
Performance Standards (NSPS), and Best Available Control Technology (BACT)
A-9
-------
Figure 3
SYSTEM PLANNING MODULE
TECHNOLOGICAL ELEMENTS:
FUEL TYPE AND SUPPLY SOURCES
POLLUTION CONTROL DEVICES
TRANSMISSION &
DISTRIBUTION
sss-ass^^ss::^^
WATER IN
SCENARIO ENERGY POLICY
ELEMENTS: ENVIRONMENTAL POLICY
ECONOMIC CONDITIONS
PLANNING FOR COST-EFFECTIVE OPERATION
FUEL CHOICES AND SUPPLY SOURCE
GENERATING TECHNOLOGIES
REGULATIONS
PLANT CHARACTERISTICS
COSTS
A-10
-------
air-emission limits. In accordance with scenario specifications, compliance
schedules can be adjusted and various optional new levels of control may or may
not be imposed. Fuels are selected from the available alternatives by
considering a trade-off between premium-priced clean fuels, the costs of pre-
combustion cleaning, and the costs of the different types of pollution controls
necessary to utilize cheaper fuels and still comply with regulations. Pollution
control costs are determined in detail on a unit-by-unit basis and include capital
outlays, increased operating costs, and losses of capacity that make new
construction necessary in order to maintain system performance. Detailed
engineering process models and data bases are utilized. All costs are calculated
as functions of fuel composition, plant characteristics, and the required level of
pollution control.
To make these projections, the System Planning module requires a number of
data bases. Some of these are:
Existing Steam Units. Description of steam units in
operation in the base year including ownership, county of
location, capacity, age, fuel type, etc.
Announced Units. Steam and nonsteam units announced
as under construction, with their projected dates for
coming on line. Also includes announced retirements and
reratings.
Conversion Plans. A number, of alternative files of unit-
by-unit conversion plans in response to possible modes of
natural gas curtailment and conversion from oil.
System Data. Extracts from FPC Form I and Form 1M
and other sources for utility systems, merged to describe
the aggregated state-firms. Included are data on existing
non steam generating capacity; data on the operation and
maintenance costs experienced for various classes of
equipment; data on expenditures for transmission and
distribution systems, matching energy and capacity
growth; and data on general and administrative costs.
A-ll
-------
Construction Costs. Costs for various types of capacity
and schedules of expenditures.
Fuels Data Base. Prices, sources, and physical and chemi-
cal properties of fuels used for electricity production in
each state.
Thermal Controls Data Base. For existing units and those
under construction, estimates are given of the likelihood
of exemption from forced conversion to closed-cycle cool-
ing under thermal pollution-control regulations. For
future units, estimates are also provided of the likely
choices among cooling alternatives.
Unit Parameters, Technical parameters to be used for
steam units when data on a unit's specific technical char-
acteristics are not available. These parameters are based
on the most common characteristics for age and fuel
class.
Future Capacity Mix. Fractions representing the ratios of
new coal, oil, nuclear, and combustion turbine capacity,
etc., after 1985 in each state.
Siting Weights. Weights for each county reflecting the
relative likelihood of siting coal, mine-mouth cool, oil,
gas, or nuclear steam units in the future in each county.
Emission Regulations. Regulations and their year of ap-
plication for air pollutants (primarily SO-, NO , and
particulates), including State Implementation Plan?, New
Source Performance Standards, and proposed Best Avail-
able Control Technology standards.
A number of sophisticated codes and computer subroutines contribute to the
System Planning module. As examples, we describe briefly the Coal Assignment
Model and three of its subroutines: the coal transportation cost model, the
particulate control cost model, and the SO- control cost model. These are
related primarily to the selection of coal supply and appropriate pollution control
devices.
A-12
-------
COAL ASSIGNMENT MODEL (ASSIGN)
ASSIGN is an interactive program that finds the least-cost coal delivered
to utility or industrial boilers in every state, subject to applicable sulfur
dioxide and particulate emission limitations. The basic data are the
properties and mine-mouth prices of coals from 11 major producing regions
of the country; the costs and efficiency of physical coal cleaning; premiums
associated with very low sulfur eastern coals; transportation routes, and
cost algorithms for transportation of coal by barge, rail, and slurry
pipeline. A "default" data base may be modified to incorporate user
judgment or to examine the sensitivity of assumptions about such key data
as coal prices, transport costs, pollution control costs, and coal character-
istics.
The product is a list of coals, by state or point of end-use, that can be
burned at least cost, including the cost of any emission controls required to
comply with federal and state emission limitations. For example, results
for power plants located near Harrisburgh, Pennsylvania, might show for
one set of conditions that (a) the older generating units would burn local
(Northern Appalachian) uncleaned coal costing 90 cents per million Btu
delivered to the plant, (b) the newer units subject to New Source Per-
formance Standards would burn Appalachian cleaned coal costing 140 cents
per million Btu, and (c) the future units subject to BACT requirements
would also use the local coals with flue gas scrubbing. Each coal is
v
characterized by region of origin, delivered cost (in cents per million Btu
and dollars per ton), and effective cost, which is the actual cost of burning
the coal, including the annualized costs of pollution controls. Penalties
associated with derating boilers designed for higher-rank coals are also
included in the effective cost. In addition, the output indicates the
emission limit that each category of boiler has to meet, the boiler's actual
emissions, and, where scrubbing is the chosen option, the fraction of flue
gas scrubbed iri order to meet the limit. Other results of ASSIGN show how
each selected coal would move from the mine or source region to the
A-13
-------
consumer. These results for a specific set of assumptions, i.e., for a
scenario, may be fed into the System Planning module for evaluation in our
dynamic simulation model.
COAL TRANSPORTATION COST MODEL
Teknekron's coal transportation cost model is structured to calculate coal
transport costs from the 11 major U.S. coal-producing regions to each of
the 48 contiguous states. The model can easily be modified to calculate
coal transport costs from specific coal mines to specific boiler locations if
that level of accuracy is required.
Witnin the model, coal can be transported by railroad, river bprge, Great
Lakes steamer, slurry pipelines, or any combination of the four modes of
transport. Four railroad, ten water, and three pipeline tariffs are used in
calculating transportation costs depending, for instance, on the river used
for transport and whether or not coal* is being carried upstream or
downstream.
The coal transportation cost model is used in conjunction with our SO-
Control Cost Model and our Particulate Control Cost Model to determine
the most economic source of coal assuming compliance with emission
control regulations.
SO2 CONTROL TECHNOLOGY AND COST MODEL
Teknekron's SO- Control Cost Model is structured to calculate capital
costs, fixed operating costs, variable operating costs, and capacity pen-
alties for limestone, lime, and magnesium oxide flue gas desulfurization
(FGD) systems installed on new boilers or retrofitted onto existing boilers.
The FGD systems are modular, with module sizes of between 100 and 150
MW each, except for systems of less than 100 MW. The model is able to
calculate costs for FGD systems from 25 MW to over 1,000 MW in size. All
systems of 100 MW or more include a spare module for added reliability.
A-14
-------
Inputs required by the model include unit size and heat ratej coal properties
(C, H, 0, N, S, H20, ash, heating value); SCL emission limit (Ib/MBtu or
percentage removal); and year the FGD system is to be built. Model
outputs include capacity penalties and costs escalated (in constant 1975
dollars) to the year the FGD system is to be built.
In calculating FGD system costs and penalties, the model considers both
the gas flow rate and the quantity of SCL to be removed. This level of
sophistication makes it possible, for instance, to compare FGD costs for
the same coal at various emission limits, or to compare FGD costs for
various coals with the same sulfur content but different heating values.
PARTICULATE CONTROL TECHNOLOGY AND COST MODEL
Teknekron's Particulate Cost Model is structured to calculate capital costs,
fixed operating costs, variable operating costs, and capacity penalties for
hot-side electrostatic precipitators, cold-side electrostatic precipitators,
and fabric filters installed on new boilers or retrofitted onto existing
boilers. The model calculates the costs for each of three particulate
control devices and selects the device having the lowest annual cost. The
model is able to calculate costs for particulate control devices of between
25 MW and 1,000 MW in size.
Inputs required by the model include plant size; capacity factor; heat rate;
coal properties (C, H, O, N, S, HLO, ash, heating value); particulate
emission limit; economic factors (capital recovery factor, electricity cost);
and year the device is to be built. Model outputs include capacity penalties
and costs escalated (in constant 1975 dollars) to the year the device is to be
built.
In calculating electrostatic precipitator costs, the model considers the coal
sulfur content, ash resistivity, and gas flow rate through the precipitator.
Fabric filter costs are based primarily on gas flow rate alone. This level of
sophistication, along with the ability to compare total annual costs and
A-15
-------
select the most economical device, makes it possible, for instance, to
select the most economic pTticulate control device for coals with
differing sulfur contents.
A-16
-------
C. DISPATCH MODULE
The function of the Dispatch module, depicted in Figure 4, is to allocate
electricity production among the various generating facilities available. The
allocation is performed on the basis of least cost, considering hourly loads for
typical days, limitations on unit availability, and total energy output for the
various types of facilities. In order to project hourly loads for future years, it is
necessary to modify current load shapes to conform to projected load factors,
and our dispatching algorithm allows this flexibility. For example, suppose the
user wants to simulate the supply of electricity under a load management
scenario in which peak demand grows more slowly than average demand. In this
case, the daily load curve would become progressively flatter, and the
dispatching algorithm would allocate an increasing portion of the energy
production to the more efficient baseload units. For the New Source
Performance Standards Review both peak and average demand were assumed to
grow at the same growth rate.
As a result of the allocation of electricity production, capacity factors are
calculated for each class of unit. Using unit heat rates, the Dispatch Module
calculates fuel consumption, operation and maintenance costs, and production
expenses and forwards these to the Financial Module. Although it is possible to
treat the unit heat rate as a function of capacity factor, data requirements make
it desirable to assign a single heat rate to each unit, varying the heat rate only
with the age of the facility and the presence or absence of pollution control
devices.
Two data bases are utilized by DISPATCH:
Typical daily load curves for both week days and weekend
days in each of two seasons for each public or private
state firm.
Generating unit availability, production limits, heat rates,
and fuel and operation and maintenance costs.
A-17
-------
Figure 4
DISPATCH MODULE
>
00
PEAK
AVAILABILITY OF
GENERATING PLANTS
INTER-
MEDIATE
BASE
LOAD
COMBUSTION
TURBINES
NUCLEAR
GEOTHERMAL
COAL
COAL-FIRED STEAM
- »*
OIL-FIRED STEAM
i
_r
t
V-r
UTILITY LOAD
DISPATCH
FUNCTION
J
L
CAPACITY
FACTORS
_L
PROD.
COSTS
JL
FUEL
CONSUMED
-------
D. FINANCIAL MODULE
The Financial module, shown in Figure 5, simulates the financial performance ot
firms that are operating to meet consumer demands and incurring the operating
expenses and costs of expansion and pollution control estimated by the Dispatch
and System Planning modules. The data base required for FINANCIAL consists
of the financial parameters for all the corporate entities being modeled. These
parameters define initial financial conditions for the simulation, which proceeds
by determining for each future year new prices, new needs for capital from
external sources, new earnings levels, and the like, under projected regulatory
constraints and tax policies. The term corporate entity refers to a single utility
firm or group of firms whose assets and production facilities have been merged
to, the state level for the purpose of the simulation. Investor-owned and non-
investor-owned firms are treated separately in the Financial module because of
the fundamentally different financial structure of these two classes of firms and
the dominant influence of financing costs and tax considerations in utility
decision making.
A-19
-------
Figures
FINANCIAL MODULE
PLANNING
DISPATCH
COSTS:
INVESTMENT
PRODUCTION
BASE
YEAR
STATISTICS
FINANCIAL
MODEL
I
ELECTRICITY
PRICES
SOURCES AND USES
OF FUNDS
EXOGENOUS
ELEMENTS
1
INCOME
STATEMENT
AND
BALANCE SHEET
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E. RESIDUALS MODULE
The Residuals module, shown in'Figure 6, receives the production levels from
DISPATCH and associates them with individual units whose fuel choices and
pollution control methods are projected by PLANNING. RESIDUALS then
utilizes this association and its own data base in order to:
Aggregate usage levels for fuels, water, and other re-
sources.
Determine production levels for air and water pollutants
and for solid wastes, estimating seasonal emissions on a
unit-by-unit basis.
The Residuals module employs two principal data bases. One is the same Fuels
Data Base used in System Planning. The other is the file of generating units,
sited by county. Fuel choice, capacity factor, and pollution controls then
determine the level of residuals. Over 20 individual residuals, including trace
metals and scrubber sludge, may be calculated.
The component modules described above provide a consistent framework for the
examination of specific questions. Certain subroutines and submodels may be
used independently of the entire simulation model. Changes to input parameters
or assumptions can easily be made.
A-21
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Figure 6
RESIDUALS MODULE
ELECTRICITY
GENERATED
DISPATCH
N)
NJ
RESOURCE
CONSUMPTION
"1 T
FUEL WATER
I
GENERATING PLANT
I
POLLUTANT
RELEASES
AIR
LAND
WATER
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F. REGIONAL AIR QUALITY ANALYSIS
Teknekron's Integrated Assessment capabilities extend to air quality analysis.
Our general approach is shown schematically in Figure 7. Emission forecasts
provided by the Electric Utility Simulation Model determine those counties with
high emission densities now and in the future. Meteorological analysis, using
data gathered from many sources, allows us to determine the preferred paths for
the downwind transport of the projected emissions. Teknekron's meteorological
analyses have also identified the weather conditions likely to give rise to the
long-range transport of pollutants and to high concentrations of sulfates.
Local and regional-scale air quality models predict the dispersion of airborne
emissions and identify simple source-receptor relationships for specific pollu-
tants. Previously a number of data bases and model capabilities have been
applied to examine specific questions of air quality. Air quality impacts assessed
so far include ambient air concentrations for SO2, NO , TSP, trace metals,
sulfates, nitrates, and oxidants; visibility degradation; and acid precipitation.
For the New Source Performance Standards Review Volume III will discuss the
air quality implications.
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Figure 7
REGIONAL AIR QUALITY ANALYSIS
EMISSION FORECASTS
POWER PLANT EMISSIONS
/INDUSTRIAL EMISSIONS
OTHER EMISSIONS
EMISSION CONTROL REGULATIONS
AND SITING RESTRICTIONS
PLANNED GROWTH
EXISTING AIR QUALITY DATA
i
LOCAL AND
REGIONAL SCALE
METEOROLOGICAL
DATA
LOCAL AND
REGIONAL
SCALE
AIR QUALITY
MODELS
FORECASTS OF LOCAL AND REGIONAL
AIR QUALITY IMPACTS
AMBIENT AIR CONCENTRATIONS
SO2, N0x, TSP, TRACE METALS
SULFATES, NITRATES, OXlDANTS
VISIBILITY DEGRADATION
ACID PRECIPITATION
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2. DATA BASE DESCRIPTION
This section describes many of the data bases used by the Electric Utility
Simulation Model. Where desirable, these data bases may be modified to
accommodate new or more specific information. Drawing from many sources,
Teknekron continually refines and updates the data.
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A. DEMAND MODULE
DEMAND DATA a file specifying net generation, purchases, net interchanges,
retail and wholesale sales, pumped storage energy, and size (MW) of existing
generating capacity, by individual utility company. These data are merged to
describe the aggregated state firms.
Data Sources: "Statistics of Privately Owned Electric Utilities in the United
States," and "Statistics of Publicly Owned Electric Utilities in the United
States," for the year ending December 31, 1975, based on FPC Form I and
Form IM magnetic tapes.
ANNUAL AVERAGE TO PEAK RATIOS for each state firm, aggregate annual
load factors derived from combined utility data submitted to the FPC. These
load factors are used in calculating capacity needed and load duration curves for
dispatching.
MONTHLY FRACTIONS monthly peak loads as a fraction of the annual peak
and the percentage of yearly energy generated in each month, by state. These
data are used for seasonal load curves and dispatching.
Data Source: 1975 FPC Monthly Electric Power Statistics.
YEARLY GROWTH RATES peak and average electricity demand growth rates
in percent by year, either nationally, by Electric Reliability Council, or by state.
These rates are specified by the user.
U.S. POPULATION PROJECTIONS - OBERS projections by state, by year.
CONTRACTS interstate purchases or sales in future years in addition to those
projected by DEMAND.
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B. PLANNING-DISPATCH MODULE
EXISTING UNITS a file of individual steam electric generating units as of
December 31, 1975. Variables include name of the unit; state and county code?
size (capability in MW); type of cooling; alternative fuel type capability; primary
fuel type; date the unit came on line; and joint ownership data.
Principal Data Sources: "Steam Electric Air and Water Quality Control Data for
the year ending December 31, 1975; Regional Reliability Council Reports;
Electrical World Directories.
ANNOUNCED UNITS (Form 383-3) a file of individual units (all generating
types) for the period from 1976 to 1986 ("announced"). Variables include name of
the unit; fuel type; size (MW); state and county of location; state of primary
owner and percentage of ownership; year the unit will come on line; primary fuel
type; and type of cooling.
Principal Data Sources: FPC published reports pursuant to FPC order 383-4
(Docket R-362), April I, 1977; Regional Reliability Council Reports; and Elec-
trical World Directories.
EXISTING UNITS (Forms I, IM) a file containing the size (MW) of existing
steam and nonsteam generating capacity. Includes operating and maintenance
costs, asset value of transmission and distribution and general and administrative
expenses (including intangibles), by individual utility firm. These data are
merged to describe the aggregated state firms.
RERATES a file of announced uprates, derates, and retirements as per J-PC
order 383-4 (Docket R-362), April I, 1977.
CONVERSION a file of orders to gas and oil burners to convert to coal as per
FEA data (June 1977). The file also contains a schedule for curtailment of
natural gas and substitute fuel planned on a unit-by-unit basis.
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FUTURE MIX a file containing the generation mix, by state, of new unit*
(coal, oil, nuclear, combined cycle, hydro, pumped storage, geothermal, com-
bustion turbines, etc.) to be built after 1986. These may be varied by scenarios.
RESERVES a specified reserve margin is maintained throughout the
simulation for each state.
PLANT MODEL PARAMETERS a file of the typical heat rate for each type of
unit. The efficiency, heat rate, and type of particulate control mechanisms are
defined as follows:
Year Unit Came
on Line
Heat
Rate
Particulatw
Type
Efficiency
before 1950
1950-1966
1966 onwards
12,500
10,600
9,200
Cyclone
Cyclone
Precip.
50%
85%
As Required
FUEL COMPOSITION a file defining the composition of 19 kinds of coal from
11 supply regions, 4 kinds of residual oil, and I kind of gas. Each fuel is
described as follows: by heating value, higher heating value, fractional
enhancement of heating value (cleaned coals only), fractional'weight yield from
cleaning, ash content, sulfur content cleaned, sulfur content uncleaned, nitrogen
content, carbon content, hydrogen content, moisture content, oxygen content. In
addition trace element composition is provided for the following: Na, N, Ni, Sb,
As, Ba, Be, B, Cd, Ca, Cl, Cr, Cu, F, Fe, Pb, Mg, Mn, Mo, Hg, Zn, Se, Ag, Ti, Tl.
This file can be updated from the ASSIGN program.
FUEL USED a file of fossil fuels used, sulfur content, and prices, containing
6 kinds of coal and 4 kinds of oil available to each state. For this data set, 4
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least-cost coals must be specified: a MET-SIP coal, a NON-MET-SIP coal, an
NSPS-complying coal, and a BACT-complying coal. The coal (oil) sulfur content
need not be sufficiently low to meet the applicable emission limit. If it is not,
the PLANNING module will build a scrubber to reduce the emissions.
FUEL PRICES a file specifying the delivered price of every fuel used
(including coal, residual oil, distillate oil, natural gas, etc.), by state, in 1975
dollars. The file is updated from the ASSIGN program.
PRICE TRENDS a file of price trends, excluding inflation, for coal, oil, gas,
and nuclear fuels and for various types of construction for all years of the simu-
lation.
CONSTRUCTION COSTS typical construction costs for each type of elec-
trical energy source.
COST SPREADS a file specifying the spread of capital expenditures for each
construction element (energy source, transmission, distribution).
WATER POLLUTION CONTROL REGULATIONS chemical and thermal
regulation parameters for water pollution control.
CUTOFF a date by which retrofitting is determined. Plants operating before
the date require retrofitting; plants operating after the date require no
retrofitting.
DUE date by which everyone must comply.
COMPLY an integer defining the number of years before the date by which
plants will begin to comply. The plants that comply are distributed evenly among
the number of comply years.
OPDATE similar to CUTOFF. This is an operational date to determine if a
regulation will apply to a pcu rtcular plant.
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CHEMICAL CONTROL REGULATIONS
CHEM-CUTOFF: 1980
CHEM-DUE: 1977
CHEM-COMPLY: 2
MSCHEM REGS: MSCHEM is a more stringent chemical control scenario.
Options are "T" (true) or "F" (false).
MSCHEM DUE: 1985
MSCHEM COMPLY: 5
THERMAL CONTROL REGULATIONS
THERM: Thermal controls
THERM-CUTOFF: 1980
THERM-DUE: 1981
THERM-COMPLY: 3
SIZES simulated units derived from FUTURE after 1985 may be built
according to the following sizes:
Nuclear = I200MW
Coal = 600 MW
Oil = 600 MW
These may also be modified by the user.
HEAT BREAK this parameter is used to determine whether the coal assigned
to a unit is of high or low heating value, for the purpose of choosing a construc-
tion cost. HEATBRK = 9,600 Btu/lb.
SIP REGS a file containing parameters pertaining to regulations for air
pollution control scenarios.
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SIP: State Implementation Plan
SIP-OPDATE: 1977
SIP-DUB 1980
SIP-COMPLY: 4
NSPS LIMITS an array containing New Source Performance Standards for
SOX, NOX, and particulates on a national basis, measured in #/IO Btu. These
limits affect plant units coming on line on or after SIP-OPDATE above.
NSPS-SOX-COAL 1.2
NSPS-SOX-OIL 0.8
NSPS-SOX-GAS O.I
NSPS-NOX-COAL 0.7
NSPS-NOX-OIL 0.3
NSPS-NOX-GAS 0.2
NSPS-PART-COAL (Default is O.I)
NSPS-PART-OIL O.I
NSPS-PART-GAS O.I
SIP-COAL by state, current SIP emission rates allowed for SO , NO , and
particulates, expressed in #/IO Btu. Each pollutant has a stringent and less
stringent limit depending on the location of the generating unit. Available are a
list of current SIPs and a list of more stringent SIPs.
SIP-OIL similar to coal.
BACT-SOX Best Available Control Technology for SO control. Two plans are
available.
PLAN O: No regulations.
PLAN I: Regulations as specified by BACT-SOX-MIN, BACT-SOX-
LID below.
BACT-OPOATB 1983
BACT-TSP-LIM: A particulate limit if Plan I is chosen. Specified by scenario.
Currently 0.03///106 Btu.
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BACT-SOX-LID: Emission limit (#/!06Btu) not to be exceeded, even if SOX-
MIN efficiency must be increased. Currently I.2///IO Btu.
MS NOX: A more stringent NO control scenario. Used if MS-NOX-FLAG = T;
not used if MS-NOX FLAG = F.
MSNOX-ANNDATE: Announced date of this scenario. Currently 1980.
MSNOX-OPDATE: 1985
MSNOX-DUB 1990
MSNOX-COMPLY: 4
MSNOX-BEFORE: #/106 Btu allowable before limits are imposed.
MSNOX-AFTER: ///106 Btu allowable after limits are imposed.
CONVERT $ $/kW to convert oil and gas units to coal and oil ($65 and $5,
respectively)..
THERMAL EXEMPTIONS - a file containing:
3I6A-RETRO: Percentages of existing plants that will not qualify for the
compliance under 3l6(a), by state. These plants will need retrofitting.
EXEMPT: Number of plants that will qualify for exemption under 3l6(a).
ECON: Number of plants that will add cooling towers for economic and tech-
nical reasons.
POLL: Number of plants that will add cooling towers for pollution control
reasons.
3I6A-NEW: A file containing percentages of new plants that will qualify for
compliance under 3l£(a), by state. These plants will not need retrofitting.
Data Source: Appendix D of "Water Pollution Control for the Steam Electric
Power Industry," for NCWQ, December 15, 1975, by Teknekron, Inc.
\
COUNTY a file containing jand-use data and EPA classification on a county-
by-county basis for each of the 48 contiguous states. The following data are
included:
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I. County name and UTM coordinates.
2. Siting weights: site-specific economic and engineering
assessment of the suitability of siting a new power plant
in that county. Separate weights are provided for the
following plant types: coal, mine-mouth coal, residual oil,
nuclear.
3. The county's environmental status code vis-a-vis preven-
tion of significant deterioration and attainment of am-
bient air quality standards.
DISPATCH STATE POINTERS an array defining region of dispatch order for
a state.
DISPATCH ORDER the Dispatch Module utilizes its generation mix accord-
ing to the Dispatch Order, a vector of ranks for N capacity classes. A least-cost
dispatch order may be recalculated each year for each state.
DAILY MAXIMUM CAPACITY FACTORS - for each unit type, the capacity
factor limits (i.e., the capacity factor that cannot be exceeded).
AVAILABILITY the availability limit for each unit type. This limit constrains
the capacity factor assignable for any hour of a typical day.
DAYSHAPES a block data set containing normalized hour-by-hour dayshape
curves, by state. Contains data for two seasons (summer and winter) and for all
hours of the day. Monthly or seasonal peak and average are supplied by the
Demand module. Weekends and weekdays are separately dispatched in both
summer and winter seasons from load duration curves.
DEMAND-PLAN DATA processed data passed from DEMAND. Includes
peak demand and electrical energy to be generated, determined from retail sales,
purchases, and wholesale sales. From monthly fractions, seasonal peak and
average generation demands are passed through.
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C. FINANCIAL MODULE
DEMAND-FINANCIAL DATA includes DEM-TO-FIN, a file containing pro-
jections of Kwh sales (retail and wholesale) as generated by DEMAND, and PLJM-
TO-FIN, a file generated by PLANNING containing simulation values for:
I. Schedule of expenditures for plants coming on line in each
year, by asset class
2. New additions to the construction work in progress ac-
count, by asset class
3. Expenses for nuclear fuel, fossil fuel, operation, mainte-
nance, and pollution control O&M, by year
FINDATA ~ extracts from FPC Forms I and IM detailing data for the, individual
utility systems, merged to describe the aggregated state firms. Included are
data on the operation and maintenance costs experienced for various classes of
equipment; data on expenditures for transmission and distribution systems; and
data on general and administrative costs.
BOOK DEPRECIATION
a. Steam Plant and Equipment, not including pollution control equipment: 35-
year life; rate = .028571.
b. Nuclear Plant and Equipment, not including pollution control equipment:
30-year life; rate = .033333.
c. Hydro Plan and Equipment, not including pollution control equipment: 65-
year life; rate = .015385.
d. Other Depreciable Assets: 30-year life; rate = .033333.
e. Transmission: 35-year life; rate = .028571.
f. Distribution: 25-year life; rate = .040000.
g. Pollution Control Equipment: 5-year life; rate = .200000.
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TAX DEPRECIATION All assets except pollution control equipment are
depreciated using the Double Declining Balance Method. Pollution Control
equipment is depreciated using the Straight Line Method over a 5-year life for
both tax and book purposes.
a. Steam Plant and Equipment, not including pollution control equipment: 28-
year life; rate= .035714.
b. Nuclear Plant and Equipment, not including pollution control equipment:
20-year life; rate = .0.50000.
c. Hydro Plant and Equipment, not including pollution control equipment: 50-
year life; rate = .020000.
d. Other Depreciable Assets: 20-year life; rate = .050000.
e. Transmission: 30-year life; rate = .033333.
f. Distribution: 30-year life; rate = .033333.
g. Pollution Control Equipment: 5-year life; rate = .200000.
TAX RATES
a. Federal = .48
b. State = Varies by state, about .05
STOCK/DEBT FINANCING MIX
a. 50% Long-Term Debt
b. 15% Preferred Stock
c. 35% Common Stock
Common Stock "risk" factor over the bond rate = .04
Preferred Stock "risk" factor over the bond rate = .01
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BOND RATES
1976 1977 1978 1979 1 980 on
.0867 .0856 .0886 .0849 .0884
Utilities '°566 -0529 '°546 *°522 *°544
Inflation Rate (all years) = .055
Interest coverage ratio limit in public financing = 2.00
Debt service limit in public financing = 1.75
Rate of repayment of long-term debt = 0.04
Investment Tax Credit tax rate = 1 0%
Amortization rate = .033333
Coefficients of costs in rate base formula = .125
Construction work in progress interest rate (calculated endogenously)
100% of firms are assumed to "normalize" for tax depreciation and tax credit
Return on common equity = .13
Coefficient of operating expenses in formula for rate base = 0.125
Coefficient of income tax in formula for rate base = 0.06
Debt/Equity ratio limit = 0.65
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D. RESIDUALS MODULE
PROJECTED SYSTEM - a file of steam units resulting from simulation ordered
by state-year with dispatched capacity factors for 16 classes.
UNIT INFORMATION - year on line; size; FPC ID; owner state; location state;
county; fuel; controlled SO , particulate, and NOV emissions; control device and
*v X
efficiency; applicable air pollution regulation limit; how unit entered system
(EXISTING, ANNOUNCED, FUTURE); how sited; and other physical quantities
related to pollution control.
FUEL fuel composition data for coal, oil, and gas. Includes heating value;
sulfur, moisture, and ash content, plus trace and radioactive elements, if any.
REGIONAL METEOROLOGICAL AND COOLING SYSTEM - region-specific
coefficients used to calculate water consumed in evaporative cooling.
NONSTEAM HEAT RATES - heat rates for combustion turbines, combined
cycle, and geothermal units.
TRANSPORT - coal transportation route miles for water, rail, slurry pipeline.
Used in computing transportation energy consumed and in evaluating coal choices
in ASSIGN.
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E. AIR QUALITY MODELS AND DATA BASES
Teknekron's Meteorology Group uses a number of data bases and air quality
models that together provide a powerful tool for integrated assessment. Outputs
of the Electric Utility Simulation Model can be used in conjunction with these
resources, which are listed below. The air quality data bases are categorized in
terms of emissions, meteorology, air quality, and effects. The models are
categorized as models of simple source-receptor relationships, as simple
phenomenological models, and as advanced dispersion models.
EMISSIONS DATA BASES
I. National Emissions Data System (NEDS)-EPA
a. 1972, by state and Air Quality Control Region
b. 1973, by county, state, and Air Quality Control Region
c. 1975, by county and source category. (This is the state of the art for
NEDS. Teknekron assisted EPA in building this data base over the
past summer.)
d. State and local agencies
i. Six Ohio River Basin states
ii. Eight Rocky Mountain states
iii. Ohio used in EPA revision of SIP (August 1977)
e. Special NO emissions tests results
2. Emissions Projections from Teknekron's Electric Utility'Simulation Model
a. Emissions by county and state, projected from 1976 to 2000.
3. Strategic Environmental Assessment System (SEAS) DOE/EPA
a. National Energy Plan Scenarios
b. NSPS Review scenarios
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4. Master Industrial County Data Base DOE/EPA
a. Existing Major Fuel-Burning Installations (MFBI)
b. Planned Industrial Boilers - American Boiler Manufacturers Associa-
tion (ABMA)
c. County Siting Weights for Future Steam Electric Plants
d. Class I and Nonattainment Status for Individual Counties
e. Regional Coal Assessment Siting Weights
f. Various Geographic Location Codes
METEOROLOGICAL DATA BASES
I. Inversion and Mixing Height Files - EPA (Holzworth)
a. 1960-1964
b. 1972-1976
c. 1977-1978 selected periods on order
2. TDF 14 Data for National Weather Service Stations
a. 1948-1974 hourly and 3-hourly observations at more than ISO stations
b. Stability Array (STAR) outputs from more than 150 stations
c. Generalized Persistence (GPER) outputs from more than ISO stations
i. Extreme-persistence cases for 22.5° sectors
i i. Extreme-persistence cases for 45° sectors
3. Number/Format Data for Canadian Environment Service Stations
a. 1966-1976 hourly observations at ten stations
b. Stability Array (STAR) outputs from ten stations
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c. Generalized Persistence (GPER) outputs from ten stations
i. Extreme-persistence cases for 22.5° sectors
i i. Extreme-persistence cases for 45° sectors
4. Special Data from Towers
a. Ten Sulfate Regional Experiment Locations, 4/74-3/75
b. Three TVA locations, 1974-1976
c. Fifteen locations in the Commonwealth of Pennsylvania, 1975
d. Thirteen locations in the Rocky Mountain Region (EPA Region VIII)
AIR QUALITY DATA BASES
I. National Air Sampling Network (NASN), I960 present, at more than 100
selected locations
a. Sulfur Dioxide
b. Su I fates
c. Total Suspended Part jculates
2. TVA Regional Trends Network, 5 stations, 1973-1976
3. Annual Monitoring and Trends Analysis Reports, EPA, 1970-1975
4. Trace Metals, EPA, 1965-1974
5. Sulfate Regional Experiment, EPRI
a. 4/74-3/75
b. 1977-1978 on order
6. Canadian Atmospheric Environment Service Intensive Sulfate Study, August
1976
7. American Electric Power, 10 networks, 1974-1976, on order
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EFFECTS DATA BASES
I. Atmospheric Turbidity, EPA (Flowers), 1960-1975
2. Visibility (visual range), 1948-1976; for ISO locations, noontime visual range
and relative humidities
3. Precipitation chemistry (acid rain)
a. World Meteorological Organization, 1972-1975
b. Canadian Atmospheric Environment Service Intensive Sulfate Study,
August 1976
AIR QUALITY MODELS
I. Simple source-receptor relationships developed and applied to areas
where:
a. emission data are plentiful and emissions can be ascribed to a pre-
dominant source category (e.g., power plants or industrial facilities)
b. air quality data are plentiful for primary (i.e., SO~) and/or secondary
(i.e., SOJ pollutants and are relatively free from local source in-
fluences
c. meteorological data are plentiful and the results of analysis provide a
convincing link between (a) and (b) above in terms of prevailing winds,
most frequent extreme-persistence sectors, etc.
d. the time periods and areas satisfying (a)-(c) above are, respectively,
long (i.e., annual) and large (i.e., several air quality control regions)
2. Simple phenomonological models
a. EPA Users Network for Applied Modeling of Air Pollution (UNAMP)
interactive computer terminal
b. Teknekron Sector Box Model with Source Intensification (SBSI)
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3. Advanced dispersion models
a. EPA Single Source (CRSTER) and Valley Models
b. Teknekron Pseudo Spectral Three-dimensional Grid Model for
Regional Su I fates (in preparation)
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TECHNICAL REPORT DATA
(I lease read Inatnictions on the reverse before completing)
REPORT NO.
2.
3. RECIPIENT'S ACCESSION NO.
.TITLE AND SUBTITLE
Review of New Source Performance Standards for Coal-
Fired Utility Boilers, Volume 1: Emissions and Non-
Air Quality Environmental Impacts
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Energy and Environmental Engineering Division
Teknekron, Inc.
2118 Milvia Street
Berkely, California 94704
10 PROGRAM ELEMENT NO.
1NE 624
11. CONTRACT/GRANT NO.
68-01-1921
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Office of Energy, Minerals, and Industry
Office of Research and Development
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA-ORD
15, SUPPLEMENTARY NOTES
This project is part of the EPA-planned and coordinated Federal Interagency
Energy/Environment R&D Program.
16. ABSTRACT
two volume report summarizes a study of the projected effects of several
different revisions to the~-eurrent New Source Performance Standard (NSPS) for sulfur
dioxide (S02) emissions from coal-fired utility power boilers. The revision is as-
sumed to apply to all coal-fired units of 25 megawatts or greater generating capacity
beginning operation after 1982. I The revised standards which are considered are: (1)
mandatory 90 percent S02 removal with an upper limit on emissions of 1.2 Ib S02 per
million Btu; (2) mandatory 80 percent S02 removal with the same upper limit; (3) no
mandatory percentage removal with an upper limit of 0.5 Ib S02 per million Btu. In
addition, effects of revising the NSPS for particulate emissions from the current
value of 0.1 Ib per million Btu down to 0.03 Ib are quantified. Projections of the
structure of the electric utility industry both with and without the NSPS revisions
are given out to the year 2000. Volume 1 discusses air emissions, solid wastes,
water consumption, and energy requirements. Volume 11 discusses economic and
financial effects, including projections of pollution controlrcosts and changes in
electricity prices.
(Circle One or More)
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Earth Atmosphere
Combustion
Energy Conversion
b.lDENTIFIERS/OPEN ENDED TERMS
Energy Cycle: 'Energy
Conversion
Fuel: Coal
COSATI Field/Group
6F
8F
10A 10B
7B 13B
97A 97F 97G
3. DISTRIBUTION STATEMEN1
Release to public
unclassified
(This Report)
130
20. SECLLHITY CLASSj'TViijpage!
unclassified
22. PRICE
EPA Form 2220-1 (9-73)
4 U.S. 60VBWMEHTPRINTIK6 OFFICE: 1978260-880/97
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