-------
costs at the five Industries, below EPA's guideline threshold of five
percent. Annualized compliance costs as a percentage of sales at small
versus large plants similarly do not exceed EPA's guidelines. The
differential for small plants ranges from 0.1 to 2.7 percentage points,
below EPA's guideline level of 10 percentage points.
The debt-to-equity ratio remains below 1.0, the benchmark used in
the BID. Assuming that capital investments for S02 emissions control
are financed 100 percent by debt, the debt ratios of the controls range
from 0.12 to 0.69. This shows residual capital availability for small
plants even after compliance with the standards.
Finally, no small plants would likely close due to the recommended
standards. Net income w-ith full absorption of compliance costs would
remain positive. New income as a percent of sales ranges from 0.5 to
4.4 percent of sales.
In sum, none of EPA's guidelines for a formal Regulatory
Flexibility Act Analysis is triggered in the analysis of small plant
impacts.
4-42
-------
APPENDIX A
OVERVIEW OF IFCAM
A.I PURPOSE
The Industrial Fuel Choice Analysis Model (IFCAM) is an energy demand
model developed by Energy and Environmental Analysis, Inc. (EEA) to evaluate
fuel choice decisions in the industrial sector over a five to 15-year fore-
casting horizon. IFCAM is a highly disaggregated process engineering model*
designed to analyze factprs affecting fuel choice decisions in industrial
boiler energy applications.
IFCAM assesses the impacts of four sets of factors affecting industrial
fuel choice: fuel prices, State and Federal energy and environmental policy
proposals, the costs associated with firing alternate fuels, and other key
model parameters such as the expected size distribution of new industrial
boilers. The model i.s capable of estimating the energy, environmental, and
cost impacts of alternative air emission regulations for new industrial
boilers.
A.2 ANALYTICAL FRAMEWORK
A.2.1 Summary of Approach
IFCAM focuses on boiler fuel choice decisions between coal, oil, and
natural gas. The model determines fuel choices for boilers in each of the
10 Federal regions using projected industrial fuel prices and total fossil
*Process engineering models simulate the effects of specific policies on
new and existing technical alternatives through the application of direct
engineering information. Other types of models are: econometric
(mathematical equations solved simultaneously with coefficients estimated
statistically from historical data); optimization (derivation of "best"
solutions by means of algebraic procedures such as linear programming);
simulation or systems dynamics (mathematical equations solved recursively
with coefficients estimated from modeler's experience and intuition).
A-l
-------
fuel demand that primarily have been generated by the U.S. Department of
Energy (DOE). IFCAM does not consider feedstock energy uses such as
metallurgical coal or raw materials derived from petroleum or natural gas
in the chemical industry.
A very disaggregate representation of industrial energy uses is incor-
porated in IFCAM. Energy use is disaggregated into nine industrial subsec-
tors having different growth rates and regional dispersions. Each of these
industrial subsectors is further divided into boiler and process heat appli-
cations.
Industrial boiler energy use is disaggregated by new and existing
boilers of different sizes and capacity utilizations rates. New and
existing boilers are classified on the basis of the type of fuel they were
designed to fire and whether they can be retrofitted to fire alternative
fuels. Eight size classes are delineated for boilers. There are five
capacity utilization rate categories for boilers.
The final level of disaggregation incorporates regional detail. Indus-
trial boiler fuel use is divided among Air Quality Control Regions (AQCR's).
Since a large number of regions are considered by IFCAM, the model can por-
tray the variability in the environmental control costs of using the various
fuels to fire boilers located throughout the country.
Current modeling capabilities for pollution control systems include
only conventional technologies. The mid-term time horizon of IFCAM pre-
cludes significant market penetration of many of the advanced technologies
still in the development stage.
Based on the characteristics of each combustor (size, operating rate,
pollution control requirements, etc.), capital and nonfuel operating costs
are generated for the options of choosing oil, gas, or coal. The fuel type
associated with the lowest after-tax present value (including expected fuel
expenses) of the total cost of generating energy over the investment period
is selected.
The model generates energy, environmental, and cost impacts. Outputs
include regional industrial boiler fossil energy demands by fuel type, air
emissions, solid waste disposal requirements, energy penalties associated
A-2
-------
with the operation of pollution control equipment, demand for new pollution
control equipment and boilers by size and type, and total costs (capital,
annual operating, maintenance and fuel expenses) of using fossil energy to
generate steam.
A.2.2 Capabilities
Four classes of energy policy measures can be analyzed with IFCAM:
fuel taxes, investment incentives, energy regulatory policies, and environ-
mental regulatory policies. A variety of tax credits and changes in the
tax treatment of capital proposed to provide incentives to invest in coal-
related equipment can be analyzed using the model.
Energy regulatory policies that target specific types of industrial
energy uses to burn coal including new boilers and existing boilers designed
to fire coal are modeled. Economic feasibility of complying with the Power-
plant and Industrial Fuel Use Act (FUA) is an option in IFCAM that deter-
mines whether or not the cost of using coal substantially exceeds the cost
of burning imported oil. The provisions of FUA are not applied in this
impact analysis of New Source Performance Standards (NSPS) for industrial
boilers.
Environmental regulatory policies that could affect fuel choice deci-
sions also can be considered in IFCAM. These regulations can affect fuel
choice by altering the relative costs of burning alternative fuels. Regu-
lations relating to particulate matter (PM), sulfur dioxide (SOe), and
nitrogen oxide (NOX) emissions from fuel-burning sources include State and
local regulations and Federal NSPS.
IFCAM is capable of modeling alternative industrial boiler NSPS.
IFCAM can simulate the use of various types of flue gas desulfurization
(F60) systems (some with combined S0£/particulate matter emissions control),
various types of post-combustion particulate matter emissions control, and
two types of combustion modifications to control NOX emissions. IFCAM's
scrubber cost estimates are unique for each coal type and S02 emission
regulation.
Several types of alternative NSPS specifications of S02 emissions
control for industrial residual fuel oil and coal-fired boilers can be
analyzed. For example, the regulation can vary by boiler size and can be
specified as:
A-3
-------
A ceiling emission rate (ng of pollutant/Joule (Ib of pollutant/
MMBtu) of fuel burned)
A recommended percentage removal (e.g., 90 percent removal of
uncontrolled S02 emissions)
A recommended percentage removal and a "floor" emissions rate
(e.g., 90 percent removal but no lower than 258 ng/J (0.6
lb/MMBtu))
A minimum percentage removal to be applied if the recommended
percentage removal results in controlled emission rates lower
than the "floor"
IFCAM can simulate the impact of alternative fuel price scenarios on
industrial fuel mix. Regional fuel prices for distillate fuel oil,
residual fuel oil (four sulfur classes), natural gas, and coal (9 types)
are considered in the model.
The fuel choice decision is sensitive to non-fuel costs of burning
alternate fuels. While the best available cost data are used, the model
can evaluate the impact of any alternative cost estimates.
In addition to these three sets of factors, many other key variables
affect fuel use. The model is designed, for example, to evaluate the
effects of varying industrial production growth rates, and to alter the
distribution of size and operating characteristics of new boilers.
A.2.3 Model Logic
Figure A-l outlines the model structure and identifies key inputs,
outputs, and major analytical steps.
Inputs 1. 2, and 3 - Energy Demand and Industrial Production; The
level of industrial fossil fuel demand and nine industrial production growth
rates by region are critical inputs to IFCAM. Although such inputs can be
derived from many sources, in the past they have been taken from the Energy
Consumption Data Base (ECDB), DOE projected industrial energy use, and the
macroeconomic model that drives the DOE modeling framework.
Model Step #1 - Characterize Industrial Energy Use: This initial step
breaks down the projected fossil fuel use by industrial sector, new and
existing facilities, type of combustor (e.g., boiler versus process heater),
size of boiler, and a variety of other classifications. These factors,
discussed below, are significant because they:
A-4
-------
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A-5
-------
t Alter the costs of using alternate fuels (e.g., fuel costs vary
according to industrial location)
Determine the economics of fuel choice (considering such factors
as the boiler's capacity utilization rate)
Distinguish elements of energy use specifically targeted by
energy policy measures (e.g., new boilers above a cutoff size).
Inputs 4 and 5 - Geographic and Boiler Size/Capacity Utilization
Distributions; The geographic and boiler size/capacity utilization distri-
butions are based on historical data.
Model Step #2 - Create and Site Individual Combustors; Energy uses
from Step #1 are disaggregated into classes of individual boilers prior to
further analysis. Boilers then are sited in AQCR's according to historical
patterns of industrial location.
Input 6 - Environmental Regulations: A file of State and Federal air
emissions regulations applicable to boilers is an important input to deter-
mine baseline costs and emissions. The file contains current regulations
that vary by boiler size and fuel type on an AQCR basis.
Model Step #3 - Identify Environmental Regulations and Pollution
Control Strategies; Emission limits for S02, PM, and NOX applicable to
individual boilers are assigned based on State and Federal regulations.
Environmental regulations may increase the capital, operating, and fuel
costs of a boiler by increasing the environmental control required or quality
of fuel burned. Available pollution control technologies are identified in
Table A-l. Compliance options are identified for each fuel type.
Inputs 7, 8, and 9 - Fuel Prices. Energy Policy, and Financial
Parameters; Specifications for a particular model run and projection year
are incorporated at this step. Specifications include the fuel price
scenario, financial parameters, and energy regulatory policies.
Fuel price variations are used in IFCAM to model fuel taxes, natural
gas price deregulation, or variations in price trajectories. Fuel prices
can be varied for distillate fuel oil, residual fuel oil (four sulfur
classes), coa'l (9 coal types), and natural gas. The price of each fuel
type can differ by region.
Investment incentives considered have focused primarily on differen-
tial depreciation methods for coal-, oil-, or gas-fired units and on
A-6
-------
TABLE A-l. INDUSTRIAL BOILER POLLUTION CONTROL TECHNOLOGIES
IN IFCAM
Pollutant
Technology options
PM
NOy
Flue gas desulfurization
- dual alkali3
- lime spray drying13
- sodium
Single mechanical collector
Dual mechanical collector
Side stream separator
Electrostatic precipitator
Fabric filter
Combustion modifications
- low excess air
- staged combustion air
aTray type scrubber.
^Combined S02/PM emissions control system; includes a fabric filter.
A-7
-------
Increased investment tax credits (ITC's) for coal-derived fuel firing. The
impacts of different depreciation methods and investment incentives are
handled within the scope of the main model logic.
The coal conversion regulatory program established under the FUA targets
boilers whose rated capacity is greater than 29 MW (100 MMBtu/hr) heat input.
An economic test compares the total cost (capital, annual O&M and fuel) of
burning coal to the total cost of burning imported oil to simulate legisla-
tive provisions related to economic exemptions. This procedure projects
the level of increased coal use under the program, excluding any implementa-
tion problems. As noted earlier, the coal conversion economic test option
in IFCAM is not currently utilized in evaluating alternative NSPS's for
industrial boilers.
Input 10 - Capital and O&M Cost Data: Capital and O&M cost data rela-
tive to the range of boiler and pollution control equipment modeled in IFCAM
are derived from numerous sources. Engineering cost data is revised on an
as-needed basis when current estimates are refined or new estimates become
available.
Model Step #4 - Evaluate Economics of Fuel Choice: Based on the charac-
teristics of each boiler (size, operating rate, pollution control require-
ments, etc.), capital and non-fuel operating costs are estimated for the
options of choosing oil, gas, or coal. The fuel type associated with the
lowest after-tax present value (including capital and annual O&M and fuel
expenses) of the cost of generating energy over the investment period then
is selected.
The components of Net Present Value (NPV) can be divided into three
major subsets: policy inputs, standard model assumptions, and key model
variables. Policy inputs are depreciation life and method, ITC, and fuel
prices. Standard model assumptions are construction period and corporate
tax rate. These elements do not vary by boiler characteristics and repre-
sent standard investment assumptions. Key model variables capital costs,
investment period, discount rate, annual fuel consumption by capacity utili-
zation rate and size, and operation and maintenance (O&M) costs all vary
with factors considered in the model (e.g., new or existing classification
or environmental regulation).
A-8
-------
A.3 KEY DATA INPUTS
This section summarizes key assumptions used in this analysis. These
estimates may be revised in future model runs.
A.3.1 Cost Algorithms
The capital and operating costs of new boilers and associated pollu-
tion control equipment have been developed by several contractors. These
costs were generalized to be expressed as algorithms. The algorithms are
functions of a number of significant parameters.
The capital cost estimates include all installation costs (which are
assumed not to vary by region) and indirect charges such as contingencies,
land, and working capital. The boiler costs include auxiliary equipment
such as the powerhouse and fuel and ash handling facilities. The annual
non-fuel O&M cost estimates include labor, materials, parts, solid waste
disposal and utility and commodity costs. The capital and annual non-fuel
O&M cost estimates are assumed not to increase in real terms over time.
A.3.2 Financial Parameters
The fuel choice decision framework in IFCAM is based on the premise
that industry will try to minimize the total costs of generating energy
over the useful life of the facility. Specifically, industrial managers
will select the fuel type with the lowest after-tax NPV of cash outflows
for operating, fuel, and capital costs.
IFCAM models the key elements of the Energy Tax Act of 1978 (ETA) and
the Economic Recovery Tax Act of 1981 (ERTA). The ETA influences after-tax
NPV calculations by permitting investments in coal facilities to be depre-
ciated using accelerated methods while requiring investments in new gas or
oil boilers to be depreciated using a straight line method. Both new coal
and oil/gas boilers are depreciated over 5 years. New coal-fired boilers
qualify for the regular 10 percent investment tax credit (ITC), but new
oil/gas boilers are excluded from the regular ITC. Special energy tax
credits are not incorporated because they expired on December 31, 1982 for
conventional coal systems.
IFCAM assumes an investment period of 15 years for new boilers. The
corporate income tax rate is assumed to be 50 percent and includes Federal
and local tax liabilities.
A-9
-------
The discount rate in IFCAM represents the average real (not nominal)
after-tax cost of capital. The real, after-tax discount rate is eight per-
cent for new units.
A.3.3 Boiler Characteristics
IFCAM uses eight standard boiler sizes. Table A-2 summarizes key
assumptions in each boiler size class. Costs and emission rates vary
significantly with the boiler type and firing method. All new firetube
boilers are single-fuel fired. All new watertube oil and gas boilers are
dual-fuel fired.
A.3.4 Technology Limits
There are limits on the capability of control technology to remove air
pollutants. The estimates used in this analysis for new coal-fired indus-
trial boilers are listed in Tables A-3 and A-4.
A.3.5 Air Emissions Calculations
IFCAM projects air emissions for three pollutants: S02, PM, NOX. The
level of air emissions is a function of fuel type, boiler type, and the
emission regulation. If the applicable regulation requires no emission
reductions, the uncontrolled emission rates are the level of air emissions.
If the applicable regulation requires emission reductions in coal-
fired boilers for S02, then the level of emissions is the following:
Controlled S02 emissions = (R x S x (1-Sc)) + ((1-R) x A)
where: S = uncontrolled annual average S02 emissions from
coal combustion, ng/J (Ib/MMBtu)
Sc = reduction required to meet standard (fraction)
R = 0.90 for lime spray drying F6D
- 0.95 for dual alkali and sodium FGD
A = uncontrolled S02 emissions from natural gas
combustion (backup fuel)
This calculation assumes a reliability factor (R) for scrubbers and a
low sulfur fuel standby option in the event of pollution control equipment
malfunction.
A-10
-------
TABLE A-2. IFCAM INDUSTRIAL BOILER SIZE/TYPE ASSUMPTIONS
Boiler size category,
MW (MMBtu/hr) heat input
Representative
Range size
3-9
(10-30)
9-15
(30-50)
15-22
(50-75)
22-29
(75-100)
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
Greater than 73
(greater than
250)
6
(20)
12
(40)
18
(62)
26
(87)
37
(125)
51
(175)
66
(225)
95
(325)
Coal
Package, water -
tube, underfeed
stoker
Package, water-
tube, underfeed
stoker
Field-erected,
watertube,
spreader stoker
Field-erected,
watertube,
spreader stoker
Field-erected,
watertube,
spreader stoker
or pulverized
coalb
Field-erected,
watertube,
spreader stoker
or pulverized
coalb
Field-erected,
watertube,
spreader stoker
or pulverized
coalb
Field-erected,
watertube,
pulverized coal
Type
Residual oil/
natural gasa
Package,
firetube
Package,
watertube
Package,
watertube
Package,
watertube
Package,
watertube
Package,
watertube
Two package,
watertube0
Two package,
watertube0
Distillate oil/
natural gasa
Package,
firetube
Package,
watertube
Package,
watertube
Package,
watertube
Package,
watertube
Package,
watertube
Two package,
watertube0
Two package,
watertube0
aFiretubes are single-fuel fired. Watertubes are dual-fuel fired.
A mix is assumed in this size class.
cEach one-half of the "representative size" in the second column.
A-ll
-------
TABLE A-3. FGD TECHNOLOGY CONSTRAINTS IN IFCAM^
Technology
Limits
Dual alkali
Lime spray drying
Sodium
90 percent13 removal of uncontrolled
S02 emissions for all coal types
90 percent13 removal of uncontrolled
S02 emissions for low sulfur coal
types (less than 1.67 Ib S02/MMBtu
annual average); not applicable to
higher sulfur coal types regardless
of the required sulfur removal rate
90 percent13 removal of uncontrolled
S02 emissions for all coal types
aU.S. Environmental Protection Agency.
30-day, rolling average basis.
A-12
-------
TABLE A-4. PM EMISSIONS POLLUTION CONTROL
TECHNOLOGY CONSTRAINTS IN IFCAM*
Technology
Minimum PM
emission standard
Single mechanical collector
stoker/bituminous
stoker/subb i tumi nous
pulverized/all
Dual mechanical collector
stoker/bituminous
stoker/subb i tumi nous
pulverized/all
Side stream separator
stoker/bituminous
stoker/subbituminous
pulverized/all
Electrostatic precipitator
Fabric filter
Lime spray drying F60b
Dual alkali FGD/single
mechanical collector
high sulfur coal (greater
than 3.5 Ib SO£/MMBtu)
other coal types (less
than 3.5 Ib S02/MMBtu)
172 ng/J (0.40 Ib/MMBtu)
344 ng/J (0.80 Ib/MMBtu)
430 ng/J (1.00 Ib/MMBtu)
129 ng/J (0.30 Ib/MMBtu)
258 ng/J (0.60 Ib/MMBtu)
344 ng/J (0.80 Ib/MMBtu)
64 ng/J (0.15 Ib/MMBtu)
129 ng/J (0.30 Ib/MMBtu)
172 ng/J (0.40 Ib/MMBtu)
21 ng/J (0.05 Ib/MMBtu)
21 ng/J (0.05 Ib/MMBtu)
21 ng/J (0.05 Ib/MMBtu)
129 ng/J (0.30 Ib/MMBtu)
42 ng/J (0.10 Ib/MMBtu)
aU.S. Environmental Protection Agency.
Includes a fabric filter.
A-13
-------
-------
APPENDIX B. PROJECTED FUEL PRICES:
REFERENCE PRICE SCENARIO
B-l
-------
TABLE B-l. WORLD OIL PRICE FORECAST:
REFERENCE PRICE SCENARIO3
(1982 $/bbl)
Year
Average refiner acquisition
cost of imported crude oil
1985
1990
1995
2000
25
28
32
37
Energy and Environmental Analysis, Inc.
B-2
-------
TABLE B-2. PROJECTIONS OF INDUSTRIAL
3.0 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
3.94
3.93
3.93
3.91
4.08
3.93
4.05
3.74
3.55
3.50
1990
4.43
4.42
4.42
4.40
4.57
4.42
4.54
4.23
4.03
3.99
1995
4.99
4.98
4.98
4.96
5.12
4.98
5.09
4.79
4.57
4.53
2000
5.66
5.65
5.65
5.62
5.79
5.65
5.75
5.47
5.23
5.19
Energy and Environmental Analysis, Inc. Reference price scenario.
B-3
-------
TABLE B-3. PROJECTIONS OF INDUSTRIAL
1.6 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.21
4.20
4.20
4.17
4.34
4.19
4.31
4.00
3.82
3.77
1990
4.73
4.72
4.72
4.70
4.86
4.72
4.83
4.53
4.33
4.29
1995
5.32
5.31
5.31
5.29
5.45
5.31
5.42
5.13
4.91
4.87
2000
6.04
6.03
6.03
6.01
6.17
6.03
6.14
5.85
5.61
5.57
Energy and Environmental Analysis, Inc. Reference price scenario.
B-4
-------
TABLE B-4. PROJECTIONS OF INDUSTRIAL
0.8 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.51
4.50
4.50
4.48
4.65
4.50
4.61
4.31
4.15
4.11
1990
5.07
5.06
5.06
5.03
5.20
5.06
5.17
4.87
4.70
4.65
1995
5.71
5.70
5.70
5.68
5.84
5.70
5.81
5.51
5.33
5.29
2000
6.49
6.48
6.48
6.46
6.63
6.48
6.59
6.30
6.09
6.05
^Energy and Environmental Analysis, Inc. Reference price scenario.
B-5
-------
TABLE B-5. PROJECTIONS OF INDUSTRIAL
0.3 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3
(1982 $/MMBtu)
1.
2.*
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.81
4.80
4.80
4.78
4.95
4.80
4.92
4.61
4.43
4.38
1990
5.41
5.40
5.40
5.37
5.55
5.40
5.51
5.21
'5.00
4.96
1995
6.10
6.09
6.09
6.07
6.24
6.09
6.20
5.90
5.68
5.64
2000
6.94
6.93
6.93
6.91
7.08
6.93
7.04
6.75
6.50
6.45
Energy and Environmental Analysis, Inc. Reference price scenario.
B-6
-------
TABLE B-6. PROJECTIONS OF INDUSTRIAL
NATURAL GAS PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.38
4.29
4.16
4.57
4.32
4.02
3.86
3.68
4.02
4.44
1990
5.21
5.21
5.17
5.46
5.34
4.95
4.91
4.47
4.94
5.23
1995
6.25 .
6.27
6.22
6.47
6.38
5.75
5.92
5.27
5.96
5.85
2000
7.49
7.30
7.25
7.40
7.27
6.75
6.81
6.12
6.56
6.63
Energy and Environmental Analysis, Inc. Reference price scenario.
B-7
-------
-------
APPENDIX C. PROJECTED FUEL PRICES:
HIGHER OIL AND GAS PRICES SCENARIO
C-l
-------
TABLE C-l. WORLD OIL PRICE FORECAST:
HIGHER OIL AND GAS PRICES SCENARIO3
(1982 $/bbl)
Year
Average refiner acquisition
cost of imported crude oil
1985
1990
1995
2000
25.90
31.90
46.50
57.40
B* *ESer?y Pr°J'ect1ons to the Year 2010. U.S. Department of Energy,
Office of Policy, Planning and Analysis. DOE/PE-0029/2. October 1983.
C-2
-------
TABLE C-2. PROJECTIONS OF INDUSTRIAL
3.0 PERCENT SULFUR RESIDUAL FUEL OIL PRICESe
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.07
4.05
4.05
4.03
4.18
4.05
4.15
3.89
3.72
3.68
1990
5.05
5.04
5.04
5.02
5.17
5.04
5.14
4.87
4.68
4.64
1995
6.93
6.91
6.91
6.90
7.05
6.91
7.02
6.75
6.47
6.44
2000
8.40
8.38
8.38
8.37
8.51
8.39
8.52
8.24
7.90
7.87
Energy and Environmental Analysis, Inc. Higher oil and gas prices
scenario.
C-3
-------
TABLE C-3. PROJECTIONS OF INDUSTRIAL
1.6 PERCENT SULFUR RESIDUAL FUEL OIL PRICES*
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.34
4.33
4.33
4.30
4.46
4.33
4.42
4.16
3.99
3.96
1990
5.40
5.39
5.39
5.37
5.52
5.39
5.48
5.22
5,03
5.00
1995
7.41
7.40
7.40
7.39
7.53
7.40
. 7.50
7.24
6.96
6.93
2000
9.00
8.99
8.99
8.98
9.14
8.99
9.10
8.83
8.51
8.48
Energy and Environmental Analysis, Inc. Higher oil and gas prices
scenario.
C-4
-------
TABLE C-4. PROJECTIONS OF INDUSTRIAL
0.8 PERCENT SULFUR RESIDUAL FUEL OIL PRICES9
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.65
4.64
4.64
4.63
4.77
4.64
4.74
4.47
4.33
4.29
1990
5.79
5.79
5.79
5.77
5.91
5.79
5.89
5.63
5.45
5.42
1995
7.98
7.98
7.98
7.96
8.09
7.98
8.07
7.80
7.58
7.54
2000
9.70
9.69
9.69
9.67
9.82
9.69
9.80
9.52
9.29
9.25
Energy and Environmental Analysis, Inc. Higher oil and gas prices
scenario.
C-5
-------
TABLE C-5. PROJECTIONS OF INDUSTRIAL
0.3 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
19S5
4.96
4.96
4.96
4.94
5.09
4.96
5.05
4.79
4.63
4.58
1990
6.19
6.18
6.18
6.17
6.31
6.18
6.28
6.01
5.81
5.77
1995
8.55
8.54
8.54
8.52
8.67
8.54
8.63
8.37
8.09
8.06
2000
10.41
10.40
10.40
10.38
10.54
10.40
10.50
10.24
9.91
9.87
Energy and Environmental Analysis, Inc. Higher oil and gas prices
scenario.
C-6
-------
TABLE C-6. PROJECTIONS OF INDUSTRIAL
NATURAL GAS PRICES3
(1982 $/MMBtu)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Region
New England
NeW York/New Jers.ey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
1985
4.43
4.35
4.29
4.63
4.42
4.08
3.92
3.72
4.05
4.45
1990
5.56
5.54
5.52
5.85
5.69
5.41
5.27
4.73
5.23
5.45
1995
7.37
7.36
7.36
7.69
7.55
6.96
7.08
6.19
6.91
7.03
2000
9.29
9.01
9.00
9.19
8.95
8.57
8.54
7.52
8.19
8.15
Energy and Environmental Analysis, Inc. Higher oil and gas prices
scenario.
C-7
-------
-------
APPENDIX D. CHARACTERISTICS OF
INDUSTRIAL COAL TYPES IN IFCAM
D-l
-------
TABLE D-l. SULFUR DIOXIDE EMISSION RATES BY COAL TYPE*
Coal Type
Bituminous
Subbituminous
Range
ng/J
<464
464-718
718-1,075
1,075-1,432
1,432-2,150
>2,150
<464
464-718
718-1,075
(lb/MMBtu)
(1
11
(3
a
(<1.08)
.08-1.67)
.67-2.50)'
.50-3.33)
.33-5.00)
(>5.00)
(<1.08)
.08-1.67)
.67-2.50)
Average
ng/d llb/MMBtu)
408
593
894
1,225
1,784
2,382
(0.95)
11.38)
2.08)
2.85)
4.15)
5.54)
408 (0.95)
593 (1.38)
894 (2.08)
a
ICF Incorporated. Average annual (not 30-day, rolling-average) values.
D-2
-------
10
CO
UJ
D_
r
«J
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ra
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H- 1
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LU
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> 0)
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CO CO CSJ r-l
O ^" **O CO
rr> ? * CM CM
^l QT^ »Cj* CO
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r-* r-l CM «M
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CT> CT* CO f^>
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(O ^^^ *4" ^^
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D-3
-------
TABLE D-3. AVERAGE ASH CONTENT BY REGION
(SUBBITUMINOUS COAL TYPES)3
(percentage, moist)
Ib $02/MMBtu
Kegion <1.08 1.08-1.67
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
aICF
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest 6.9 6.9
Southwest 7.3 7.3
Central 6.0 6.0
North Central 8.4 6.9
West 7.3 7.3
Northwest 10.0 10.0
Incorporated.
1.67-2.50
-
-
-
-
6.9
7.3
6.0
6.9
7.3
10.0
D-4
-------
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Q.
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H- 1
0 4->
LU S-
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>- 10
1 -^
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LU SI
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CM CM
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**
^1 »
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en o
r-- «3-
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co co
CO «*
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in vo
r-. co
P^» CO
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**% ^"K ^"x
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en in co vo «^ co
co o CM en in t i
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^^ ^i * * *
co vo en o m co
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id
s_
-i->
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cu
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3
g~ f"
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03
D-5
-------
TABLE D-5. AVERAGE HEAT CONTENT BY REGION
(SUBBITUMINOUS COAL TYPES)3
J/g (MMBtu/short ton)
Region
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
New England
New York/New Jersey
Middle Atlantic
South Atlantic
Midwest
Southwest
Central
North Central
West
Northwest
Ib S02/MMBtu
<1.08
-
-
-
-
20.53
(17.65)
19.93
(17.14)
19.77
(17.00)
20.40
(17.54)
21.52
(18.50)
22.10
(19.00)
1.08-1.67
-
-
-
-
20.53
(17.65)
19.93
(17.14)
19.77
(17.00)
20.05
(17.24)
21.52
(18.50)
22.10
(19.00)
1.67-2.50
-
-
-
-
20.53
(17.65)
19.93
(17.14)
19.77
(17.00)
20.05
(17.24)
21.52
(18.50)
22.10
(19.00)
ICF Incorporated.
D-6
-------
APPENDIX E. DELIVERED INDUSTRIAL
COAL PRICE FORECAST
Reference: Memorandum from C. Ebert (ICF Incorporated) to J.
Greenwald (EPA). Revised Industrial Coal Prices for
Industrial NSPS Analyses. May 31, 1984. Attach-
ment A.
« Converted from January 1983 dollars to 1982 dollars using the average
annual 1982 and fourth quarter 1982 GNP implicit price deflators.
E-l
-------
DELIVERED INDUSTRIAL COAL PRICE FORECAST2
(1982 $/MMBtu)
Sulfur content
Region Coal type (lb S02/MMBtu)
1. New England Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
2. New York/
New Jersey Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
3. Middle Atlantic Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
4. South Atlantic Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
1985
3.35
3.21
3.19
3.09
2.67
2.84
3.18
3.03
2.90
2.77
2.34
2.43
2.75
2.49
2.42
2.37
1.99
1.99
2.66
2.47
2.45
2.40
2.44
2.32
1990
3.62
3.58
3.52
3.33
2.96
3.11
3.39
3.31
3.17
3.01
2.63
2.69
3.01
2.82
2.74
2.66
2.27
2.25
3.07
2.83
2.82
2.73
2.67
2.48
1995
3.75
3.71
3.65
3.44
3.23
3.25
3.48
3.45
3.28
3.12
2.91
2.89
3.14
2.96
2.88
2.77
2.45
2.43
3.23
3.05
3.03
2.93
2.81
2.62
2000
3.87
3.86
3.75
3.54
3.46
3.48
3.60
3.57
3.41
3.21
3.10
3.05
3.26
3.10
2.98
2.86
2.68
2.62
3.35
3.21
3.17
3.08
2.93
2.79
ICF Incorporated.
E-2
-------
DELIVERED INDUSTRIAL COAL PRICE FORECAST3
(1982 $/MMBtu)
(Continued)
Sulfur content
Region Coal type (Ib S02/MMBtu)
5. Midwest Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
Subbituminous <1.08
1.08 - 1.67
1.67 - 2.50
6. Southwest Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
Subbituminous <1.08
1.08 - 1.67
1.67 - 2.50
7. Central Bituminous <1.08
1.08 - 1.67
1.67 - 2.50
2.50 - 3.33
3.33 - 5.00
>5.00
Subbi tumi nous < 1 . 08
1.08 - 1.67
1.67 - 2.50
1985
2.91
2.69
2.67
2.53
2.30
2.19
3.19
3.15
3.13
2.85
2.75
2.75
2.85
2.77
2.68
3.21
3.09
3.04
2.81
2.77
2.78
2.55
2.44
2.25
2.59
2.53
2.63
1990
3.18
3.04
2.97
2.82
2.56
2.39
3.26
3.22
3.19
3.18
3.05
3.05
3.05
2.96
2.84
3.35
3.26
3.20
3.01
2.95
2.94
2.78
2.52
2.35
2.62
2.58
2.62
1995
3.33
3.21
3.08
2.94
2.69
2.50
3.32
3.27
3.26
3.38
3.26
3.25
3.19
3.10
2.93
3.46
3.34
3.29
3.14
3.04
3.01
2.93
2.58
2.44
2.71
2.66
2.68
2000
3.44
3.37
3.18
3.04
2.80
2.63
3.38
3.32
3.27
3.56
3.42
3.35
3.33
3.18
3.05
3.57
3.46
3.39
3.22
3.15
3.05
3.07
2.63
2.57
2.78
2.72
2.67
ICF Incorporated.
E-3
-------
DELIVERED INDUSTRIAL COAL PRICE FORECAST8
(1982 $/MMBtu)
(Continued)
Sulfur
Region Coal type (Ib SOp
8. North Central Bituminous
1.08 -
1.67 -
Subbituminous
1.08 -
1.67 -
9. West Bituminous
1.08 -
1.67 -
Subbituminous
1.08 -
1.67 -
10. Northwest Bituminous
1.08 -
1.67 -
Subbituminous
1.08 -
1.67 -
content
/MMBtu)
<1.08
1.67
2.50
<1.08
1.67
2.50
<1.08
1.67
2.50
<1.08
1.67
2.50
<1.08
1.67
2.50
<1.08
1.67
2.50
1985
1.76
1.61
1.70
1.22
1.17
1.19
2.54
2.39
2.40
2.62
2.52
2.48
2.92
2.63
2.59
2.38
2.40
1.93
1990
1.90
1.74
1.81
1.32
1.32
1.21
2.69
2.64
2.64
2.71
2.61
2.56
3.06
2.80
2.72
2.59
2.48
1.99
1995
1.98
1.90
1.88
1.41
1.42
1.28
2.75
2.90
2.81
2.83
2.72
2.60
3.13
2.99
2.83
2.62
2.59
2.08
2000
2.07
2.01
1.86
1.52
1.45
1.33
2.91
3.05
2.92
2.92
2.84
2.69
3.27
3.18
2.88
2.71
2.67
2.19
ICF Incorporated.
E-4
-------
APPENDIX F
IFCAM PROJECTIONS FOR 1990 BY BOILER SIZE CLASS
This appendix summarizes IFCAM forecasts of total S0£ emissions,
annualized costs, and fossil fuel demand in 1990 from new industrial fossil
fuel-fired boilers installed between 1985 and 1990 and each larger than 29
MW (100 MMBtu/hr) heat input capacity. Results are presented for both fuel
price scenarios (reference Section 2.2.3) and for each alternative SOg NSPS
emissions standard (reference Section 3.1).
In these tables, "gas"
is natural gas and "oil" is residual fuel oil.
F-l
-------
TABLE F-l. COMPARISON OF IFCAM PROJECTIONS FOR 1990*
Fuel price
scenario
Alternative control level
Baseline I II III IV V VI
Reference
S0j> emissions
1§3
(103 Short tons)
Annualized costs**
(10° 1982 $)
Fuel (10*2 Btu)
coal
oil
gas
Higher oil and
gas prices
SOg emissions
(103 short tons)
Annualized costsb
(106 1982 $)
Fuel (10*2 Btu)
coal
oil
gas
279
3,349
23
323
152
326
3,725
284
7
207
204 106 102 39 47
17
329
153
17
257
225
148 114
46
16
3,357 3,406 3,408 3,476 3,474 3,482
9 26 26 26
257 206 205 178
232 267 267 294
34 30 16
3,735 3,743 3,754 3,757 3,758 3,757
261 248 153 153 153 147
0 0 0000
237 250 345 345 345 351
New industrial fossil fuel-fired boilers installed between 1985 and 1990
and each larger than 29 MW (100 MMBtu/hr) heat input capacity.
'includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-2
-------
TABLE F-2. REGULATORY BASELINE PROJECTIONS FOR 1990
BY BOILER SIZE CLASS*
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
S02 emissions
(103 short tons)
Annualized costsb
(106 1982 $)
Fuel (1012 Btu)
coal
oil
gas
Higher oil and gas prices
SOg.emissions
(103 short tons)
Annuali zed costs'3
(106 1982 $)
Fuel (1012 Btu)
105
901
4
99
26
74
1,008
82
729
1
86
24
108
838
52
445
6
46
15
86
493
41 279
1,275 3,349
13
92
87
59
23
323
152
326
1,386 3,725
coal
oil
gas
40
7
82
70
0
41
48
0
19
126
0
65
284
7
207
aNew industrial fossil fuel-fired boilers installed between 1986 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-3
-------
TABLE F-3. ALTERNATIVE CONTROL LEVEL I PROJECTIONS
FOR 1990 BY BOILER SIZE CLASS*
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
S02 emissions 69
(103 short tons)
Annualized costsb . 906
(100 1982 $)
59
733
35
444
40
204
1,275 3,357
Fuel (1012 Btu)
coal
oil
gas
Higher oil and gas prices
SOg emissions
(103 short tons)
Annual ized costsb 1
(106 1982 $)
Fuel (1012 Btu)
coal
oil
gas
3
100
26
24
,013
37
0
92
1
86
24
37
836
55
0
56
0
51
16
29
500
43
0
24
13
92
87
58
1,387
126
0
65
17
329
153
148
3,735
261
0
237
New industrial fossil fuel-fired boilers installed between 1985 and 1990.
'includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-4
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TABLE F-4. ALTERNATIVE CONTROL LEVEL II PROJECTIONS
FOR 1990 BY BOILER SIZE CLASS*
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
SOg emissions
(103 short tons)
Annual i zed costsb
(106 1982 $)
Fuel
coal
oil
gas
Btu)
28
926
3
70
56
Higher oil and gas prices
S02 emissions
(103 short tons)
Annualized costsb
(106 1982 $)
Fuel (1012 Btu)
11
1,009
24
749
1
60
50
25
844
14
456
0
34
33
20
504
40 106
1,275 3,406
13
92
87
17
257
225
58 114
1,387 3,743
coal
oil
gas
23
0
105
55
0
56
43
0
24
126
0
65
248
0
250
aNew industrial fossil fuel-fired boilers installed between 1985 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-5
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TABLE F-5. ALTERNATIVE CONTROL LEVEL III PROJECTIONS
FOR 1990 BY BOILER SIZE CLASSa
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
emissions
(103 short tons)
Annual ized costs^
(100 1982 $)
Fuel (1012 Btu)
27
. 927
23
749
14
456
38
102
1,276 3,408
coal
oil
gas
Higher oil and gas prices
SOp-emissions
(103 short tons)
Annual ized costs'5 1
(106 1982 $)
Fuel (1012 Btu)
coal
oil
gas
1
70
58
4
,011
12
0
117
0
60
51
7
832
23
0
88
0
34
33
5
500
17
0
50
9
92
91
30
1,411
101
0
90
9
257
232
46
3,754
153
0
345
New industrial fossil fuel-fired boilers installed between 1985 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-6
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TABLE F-6. ALTERNATIVE CONTROL LEVEL IV PROJECTIONS
FOR 1990 BY BOILER SIZE CLASS^
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
SOg emissions
(103 short tons)
Annual i zed costsb
(106 1982 $)
Fuel
coal
oil
gas
Btu)
943
0
57
72
Higher oil and gas prices
S02 emissions
(103 short tons)
Annualized costsb
(106 1982 $)
Fuel (1012 Btu)
1,011
9
762
0
57
54
5
833
5
461
0
33
34
4
501
15 39
1,310 3,476
26
59
107
26
206
267
22 34
1,412 3,757
coal
oil
gas
12
0
117
23
0
88
17
0
50
101
0
90
153
0
345
aNew industrial fossil fuel-fired boilers installed between 1985 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-7
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TABLE F-7. ALTERNATIVE CONTROL LEVEL V PROJECTIONS
FOR 1990 BY BOILER SIZE CLASS*
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
S02 emissions
(103 short tons)
Annualized costs'3
(106 1982 $)
Fuel (1012 Btu)
13
. 942
13
761
8
460
13
47
1,311 3,474
coal
oil
gas
Higher oil and gas prices
S02 emissions
(103 short tons)
Annual ized costs^ 1
(IQo 1982 $)
Fuel (1012 Btu)
coal
oil
gas
0
57
72
3
,011
12
0
117
0
57
54
5
833
23
.0
88
0
33
34
3
501
17
0
50
26
59
107
19
1,414
101
0
90
26
206
267
30
3,758
153
0
345
aNew industrial fossil fuel-fired boilers installed between 1985 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-8
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TABLE F-8. ALTERNATIVE CONTROL LEVEL VI PROJECTIONS
FOR 1990 BY BOILER SIZE CLASS*
Boiler size class, MW (MMBtu/hr)
Fuel price
scenario
29-44
(100-150)
44-58
(150-200)
58-73
(200-250)
>73
(>250)
Total
Reference
S02oemissions 4
(103 short tons)
Annualized costsb 945
(106 1982 $)
Fuel (1012 Btu)
coal 0
oil 44
gas 85
Higher, oil and gas prices
SO? emissions
(103 short tons)
Annual ized costs'3
(106 1982 $)
Fuel (1012 Btu)
1,011
4
763
0
51
60
2
829
3
461
0
32
35
2
501
6 16
1,313 3,482
26 26
52 178
113 294
10
16
1,415 3,757
coal
oil
gas
12
0
117
17
0
94 .
17
0
50
101
0
90
147
0
351
aNew industrial fossil fuel-fired boilers installed between 1985 and 1990.
Includes capital, operating, maintenance and fuel costs for the boiler
and pollution control equipment.
F-9
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA 450/3-86-007
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE Projected Impacts of Alternative Sulfur
Dioxide New Source Performance Standards for Industrial
Fossil-Fuel-Fired Boilers
5. REPORT DATE
March 1Q85
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Energy and Environmental Analysis, Inc.
Arlington. VA 22209
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report presents projected environmental, cost, and energy impacts of alternative
sulfur dioxide (S0») air emission standards for new industrial fossil-fuel-fired steam
generating units. These impacts are measured in terms of the projected change under
current versus alternative air emission regulations. The analysis of environmental
impacts focuses on changes in levels of air emissions. Cost impacts are evaluated in
terms of incremental changes in the total annualized costs for boiler and pollution
control equipment capital, operating, and fuel costs. Energy impacts are evaluated
in terms of shifts in the demand between fuel types (e.g., coal or residual fuel oil
versus natural gas).
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air pollution
Standards of performance
Steam generating units
Environmental impacts analysis
Impacts analysis
Air pollution control
13 B
18. DISTRIBUTION STATEMENT
Release unlimited
19. SECURITY CLASS (ThisReport}
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page/
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
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