p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

11) M-K-(A)-24 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:48 AM Sheet 11 of 325 
ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive 

Arlington. Virginia 22209 

(703) 528-1900 
P.3 

DESCRIPTION OF THE 

INDUSTRIAL FUEL CHOICE ANALYSIS MODEL 

Prepared for: 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Prepared by: 

ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive, Suite 600 

Arlington, Virginia 22209 

May 1985 
P.4 

This report was furnished to the U.S. Environmental Protection Agency 

by Energy and Environmental Analysis, Inc., Arlington, Virginia, in fulfillment of Contract Number 68-02-4202. The contents of this report are 

reproduced herein as received from the contractor. 

The opinions, findings, and conclusions expressed are those of the 

author and not necessarily those of the U.S. Environmental Protection Agency. 

Specific parameter values and assumptions presented in this report are 

current as of the publication date. Future IFCAM runs may include model 

modifications recommended by EPA. 

This report presents the model methodology and data sources. A separate 

report, Industrial Fuel Choice Analysis Model User's Manual (November 1984), 

summarizes input file formats and units, output table features and program 

operating instructions. 
P.5 

TABLE OF CONTENTS 

Page 

1. INTRODUCTION 1-1 

1.1 Purpose and Scope of Model 1-1 

1.2 Model Capabilities 1-7 

References 1-11 

2. MODEL LOGIC 2-1 

2.1 Analytical Framework 2-1 

2.2 User Options • 2-6 

3. INDUSTRIAL BOILER POPULATION CHARACTERISTICS 3-1 

3.1 Fossil Fuel Demand Projections by Industry Group 3-1 

3.2 Categorization of Fossil Fuels by Functional Use 3-3 

3.3 Categorization of Boiler Fossil Fuel Use by New 

and Existing Facilities 3-7 

3.4 Classification of Boiler Fuel Use by Size and 

Capacity Utilization Rate 3-13 

3.5 Environmental Regulations 3-20 

3.6 Pollution Control Strategies 3-24 

References 3-41 

4. FUEL CHOICE DECISIONS 4-1 

4.1 Cost Components 4-1 

4.2 Investment Decision Approach 4-4 

References 4-16 
P.6 

LIST OF TABLES 

Page 

1-1 Industrial Pollution Control Equipment Options in IFCAM 1-9 

3-1 Projected Industrial Energy Conservation Factors 3-4 

3-2 Distribution of Fossil Fuels Between Boiler and 

Process Heat Uses 3-6 

3-3 New Industrial Boiler Size/Type Assumptions in IFCAM 3-15 

3-4 New Industrial Boiler Size/Capacity Utilization 

Rate Distribution 3-17 

3-5 Current Industrial Boiler NSPS 3-22 

3-6 Industrial Boiler Pollution Control Equipment 

Options in IFCAM 3-25 

3-7 Sulfur Dioxide Emissions Rates by Coal Type 3-27 

3-8 Average Ash Content By Region (Bituminous Coal Types) 3-28 

3-9 Average Ash Content By Region (Subbituminous Coal Types) 3-29 

3-10 Average Heat Content By Region (Bituminous Coal Types) 3-30 

3-11 Average Heat Content By Region (Subbituminous Coal Types) 3-31 

3-12 FGD Technology Constraints in IFCAM 3-32 

3-13 PM Emissions Pollution Control Technology Constraints 

in IFCAM 3-35 

3-14 N0X Emission Rate Estimates for New Industrial 

Coal-Fired Boilers 3-37 

3-15 Uncontrolled Industrial Oil/Gas Boiler SO2 and PM 

Emission Rate Estimates 3-38 

3-16 N0X Emission Rate Estimates for New Industrial 

Oil/Gas Boilers 3-39 

3-17 Pollution Control Compliance Alternatives in IFCAM 3-40 

4-1 Financial Parameter Assumptions for New Industrial 

Boiler Discounted After-Tax NPV Cost Comparisons 4-10 

4-2 Derivation of the AFter-Tax NPV Factor for Coal 

Boiler Capital Expenses 4-11 

4-3 Derivation of the After-Tax NPV Factor for Oil/Gas 

Boiler Capital Expenses 4-12 

4-4 Derivation of the After-Tax NPV Factor for Annual 

Non-Fuel O&M Expenses 4-13 

4-5 Example Calculation of the After-Tax NPV of 

Annual Fuel Expenses 4-14 
P.7 

LIST OF FIGURES 

Page 

1-1 Federal Regions of the United States 1-4 

1-2 Context of Current IFCAM Model Structure 1-5 

2-1 IFCAM Model Structure • 2-3 

2-2 IFCAM User Options 2-7 
P.8 

INTRODUCTION 

1.1 PURPOSE AND SCOPE OF MODEL 

The Industrial Fuel Choice Analysis Model (IFCAM) is a highly 

disaggregated and detailed process engineering industrial energy demand 

model covering the consumption of fossil fuels (coal, distillate fuel oil, 

residual fuel oil, and natural gas) in industrial boilers. IFCAM was 

developed to help decision makers assess a wide range of energy, environmental, and cost impacts resulting from policy alternatives. IFCAM is 

currently being used by EPA to project the impacts of alternative Federal 

air emissions regulations (New Source Performance Standards, NSPS) for new 

industrial fossil fuel-fired boilers. 

IFCAM originally was designed to provide the U.S. Department of Energy, 

Energy Information Administration's (EIA) Midterm Energy Forecasting System 

(MEFS)* with an alternative source of forecasts of industrial fossil fuel 

mix. IFCAM was structured to use MEFS projections of overall industrial 

energy demand and fuel prices and to focus on fuel choices between coal, 

distillate fuel oil, residual fuel oil, and natural gas. 

The initial version of IFCAM, which was developed for the U.S. Department of Energy's Office of Policy and Evaluation, was modified for EPA's 

industrial fossil fuel-fired boiler NSPS analysis beginning in 1979.** 

Examples of tasks include: 

• Revising industrial boiler and pollution control equipment cost 

estimates 

*The current version is now called the Intermediate Future Forecasting 

System (IFFS). 

**The EPA version of IFCAM, which is described in this report, may be 

considered IFCAM, Version 2. IFCAM, Version 2, was first documented for 

EPA in 1980.l 

1-1 
P.9 

t Increasing the number and changing the characteristics of residual 

fuel oil and coal types 

• Increasing the number of and revising the technical pollution 

control capabilities of flue gas desulfurization, particulate 

matter emissions control equipment, and N0X combustion modifications 

• Preparing new model output tables 

The initial DOE version of IFCAM included industrial fossil fuel-fired 

boilers and fossil fuel-fired process heaters (or non-boilers). The EPA 

version discussed in this report includes only projections of industrial 

fossil fuel-fired boiler energy demand, air emissions, and costs. 

The basic approach in IFCAM is to project the characteristics of the 

industrial boiler population and to make a fuel choice decision for each 

group of boilers based on the alternative with the lowest expected life 

cycle costs (including capital and annual operating, maintenance, and fuel 

expenses). The major industrial boiler characteristics include: 

• New or existing unit 

• Size (MMBtu/hr heat input) 

t Average capacity utilization rate* 

• Local and Federal sulfur dioxide (SO2), particulate matter (PM), 

and nitrogen oxide (N0X) emissions standards 

Key input assumptions include: 

• Projected fuel prices and total industrial energy demand 

• Projected industrial production growth rates by industry group 

• Boiler and pollution control equipment cost estimates 

• Local and Federal air emissions regulations 

t Expected distribution of new industrial boiler locations 

• Base year boiler population characteristics and retirement 

methodology 

• New boiler size and capacity utilization rate distribution 

• The life cycle cost comparison algorithms 

•Expected annual fuel consumption/(design firing rate times 8,760 hours per 

year). 

1-2 
P.10 

Major model outputs include: 

• Projected emissions of SO2, PM, N0X, and PMio 

t Projected industrial boiler fossil fuel demand by fuel type (coal, 

distillate fuel oil, residual fuel oil, and natural gas) 

• Projected total capital and annual operating, maintenance, and 

fuel expenses 

Model outputs are available by Federal region (see Figure 1-1). 

Figure 1-2 provides a framework to consider the role of other factors 

outside the scope of the current IFCAM model structure. The figure shows 

the relationships between: 

• Overall economic trends 

• U.S. energy markets 

t Industrial energy demand 

• Current IFCAM scope 

Starting at the top of Figure 1-2, the overall economy represents 

critical trends in "macroeconomic" variables. Several macroeconomic models 

have been developed which forecast growth in the aggregate demand and supply 

for final goods. Major model outputs include Gross National Product (GNP), 

private sector investment, government spending, production, personal consumption expenditures, and other economic parameters. These models generate 

forecasts of industrial activity (i.e., projections of the Federal Reserve 

Board Industrial Production Indices or value added data) by type of industrial 

group that affect the level of demand for energy services in the industrial 

sector. Other macroeconomic variables are used to forecast energy demand 

in other sectors (i.e., disposable income for the residential and commercial 

sectors). 

The macroeconomic models thus provide key economic "drivers" of energy 

demand, such as industrial production growth. These "drivers" then serve 

as key inputs into a model of the U.S. energy markets to determine energy 

demand in the energy-using sectors of the economy. The "Energy Markets" 

essentially involve the interplay of demand and supply for alternative sources 

of energy (e.g., oil, coal), resulting in the determination of the price 

and level of use of various energy forms. 

1-3 
FIGURE 1-1 

Federal Regions of the United States 

,o 9 

HA»AII " 

REGION NAMES 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. Midwest 

6. Southwest 

7. Central 

8. North Central 

9. West 

10. Northwest 
P.12 

FIGURE 1-2 

Context of Current IFCAM Model Structure 

ECONOMY 

MACROECONOMIC GROWTH 

INTERINDUSTRY TRANSACTIONS 

Economic 

Activity 

ll INDUSTRIAL 

PRODUCTION 

ENERGY 

DEMAND 

RESIDENTIAL 

COMMERCIAL 

TRANSPORTATION 

D 

(_ 

Q 

D 

D 

[ ELCCTWC JTJ-TIES 

(3UANT;l:TY 7 

ENERGY 

PRICES 

Industrial 

Energy 

Demand 

Fossil/Other Energy Demand 

• Econometric Forecast 

FOSSIL 

__ ENERGY 

JvJKMANjp* 

ENERGY 

MARKETS 

1-5 
P.13 

In turn, the energy market trends provide the costs of energy back to ' 

the macroeconomic framework, through such variables as the Consumer Price 

Index and costs of energy inputs to the industrial sectors. These energy 

cost impacts can, in turn, alter macroeconomic trends. For example, the 

world oil price shocks results in major cost increases which in turn affected 

industrial production growth, consumer behavior and real income. 

Industrial energy demand, depicted at the bottom of Figure 1-2, is an 

important element of the energy market. We have focused separately on 

industrial energy demand because: 

• IFCAM has not been used as a portion of a "general equilibrium" 

system which simultaneously reflects the interactions between the 

economy and energy markets 

• IFCAM is not a complete energy demand model 

Logically, an industrial demand model addresses the following issues: 

• The relationship between industrial production and the overall 

level of energy inputs required to perform various industrial 

process operations 

• Energy demand in all industrial uses (e.g., boilers, process heat, 

feedstock) 

t The mix of energy sources selected to provide the full range of 

energy services 

The major (exogenous) inputs to a complete energy demand model are industrial 

production growth trends and the prices of various forms of energy. 

IFCAM is not a complete energy model because it covers only a portion 

of the scope of an industrial demand model. Specifically, it does not address 

in any detail: 

• The relationship between overall industrial production and energy 

demand (e.g., conservation, process efficiency trends) 

• The demand for energy in non-boiler industrial uses* 

• The demand for energy forms other than conventional fossil fuels 

(oil, gas, coal) 

*The initial version of IFCAM, developed for the U.S. Department of Energy, 

2 

does include a process heat sector. 

1-6 
1.2 MODEL CAPABILITIES 

IFCAM is a process engineering/simple accounting industrial boiler 

fuel choice model. This modeling technique simulates the effects of specific 

policies on technical alternatives through the application of direct engineering information at a disaggregated level. Other types of models include: 

• 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) 

t Simulation or system dynamics (mathematical equations solved 

recursively with coefficients estimated from modeler's experience 

and intuition) 

The model structure of IFCAM has been designed to evaluate alternative 

fuel price projections, government energy and environmental policy proposals, 

the costs associated with firing alternative fuels and other key model parameters. The fuel choice decision criterion in IFCAM is a comparison of 

after-tax, discounted cash flows. Therefore, a variety of tax credits and 

proposed changes in the tax treatment of capital that 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 

Powerplant and Industrial Fuel Use Act (FUA) is an option in IFCAM that 

determines whether or not the cost of using coal substantially exceeds the 

cost of burning imported oil. 

Environmental regulatory policies that could affect fuel choice 

decisions also can be considered in IFCAM. These regulations can affect 

fuel choice by altering the relative costs of burning alternative fuels. 

Regulations relating to PM, SO2, and N0X 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 (FGO) 

systems (some with combined S02/particulate matter emissions control), 

various types of post-combustion particulate matter emissions control, and 

two types of combustion modifications to control N0X emissions. 

1-7 
P.15 

Several types of alternative specifications of SO2 emissions control 

for new industrial residual fuel oil or coal-fired boilers can be analyzed. 

For example, the regulation can vary by boiler size and can be specified 

as: 

• A ceiling emission rate (lb of pollutant/MMBtu of fuel burned) 

t A recommended percentage removal (e.g., 90 percent removal of 

uncontrolled SO2 emissions) 

• A recommended percentage removal and a "floor" emissions rate 

(e.g., 90 percent removal but no lower than 258 ng/0, 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 projections on 

industrial fuel mix. Regional fuel prices for distillate fuel oil, residual 

fuel oil (four sulfur classes), natural gas, and coal (nine 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 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. 

IFCAM's fuel choice decisions are a function of technical as well as 

economic and regulatory factors. IFCAM evaluates fuel switching in existing 

boilers and fuel type selection in new boilers. IFCAM selects from a wide 

range of fuel quality options (multiple residual fuel oil and coal types) 

and alternative pollution control strategies. Table 1-1 lists alternative 

boiler pollution control technologies in IFCAM. 

Model results have been published in several reports and presented in 

3 

several briefings for EPA since 1979. Model input assumptions, methodology, 

and results have been reviewed by EPA staff and representatives from other 

1-8 
P.16 

TABLE 1-1. INDUSTRIAL POLLUTION CONTROL EQUIPMENT 

OPTIONS IN IFCAM 

Pollutant Technology 

SO2 Flue gas desulfurization 

Dual alkali 

Lime spray drying3 

Sodium once-through 

PM Single mechanical collector 

Dual mechanical collector 

Side stream separator 

Electrostatic precipitator 

Fabric filter 

NOx Combustion modification 

Low excess air 

Staged combustion air 

aCombined SO2/PM emissions control system; includes a fabric filter. 

1-9 
P.17 

Federal government agencies (i.e., the U.S. Department of Energy). In' 

addition, EEA has maintained a docket for IFCAM assumptions, results, and 

data sources (in support of the industrial fossil fuel-fired boiler NSPS 

analysis) which has been made available to the public by EPA. 

1-10 
P.18 

REFERENCES 

1. Industrial Fuel Choice Analysis Model - Model Documentation. Energy 

and Environmental Analysis, Inc. Arlington, Virginia. Prepared for 

the U.S. Environmental Protection Agency, Office of Air Quality Planning 

and Standards. June 1980. 

2. Industrial Fuel Choice Analysis Model. Volume I - Primary Model 

Documentation and Volume II - Appendices to Model Documentation. Energy 

and Environmental Analysis, Inc. Arlington, Virginia. Prepared for 

the U.S. Department of Energy, Office of Policy and Evaluation. January 

1980. Example applications: 

t Kincel, K., F. Murphy, and H. Walton. An Evaluation of Energy 

Related Tax and Tax Credit Programs. U.S. Department of Energy, 

Energy Information Administration. DOE/EIA-0102/8. July 1978. 

• Mead, D., F. Murphy, and W. Montgomery. Analysis of Proposed U.S. 

Department of Energy Regulations Implementing the Powerplant and 

Industrial Fuel Use Act. U.S. Department of Energy, Energy 

Information Administration. DOE/EIA-0102/21. November 1978. 

t Annual Report to Congress 1978. U.S. Department of Energy, Energy 

Information Administration. DOE/EIA-0173/3. p. 391. 

t Analysis of Key Economic Test Parameters in the Powerplant and 

Industrial Fuel Use Act. Energy and Environmental Analysis, Inc., 

Arlington, Virginia. Draft report prepared for the U.S. 

Department of Energy, Office of Policy and Evaluation. January 

1979. 

• Technical Staff Analysis in Response to Notice of Proposed 

Rulemaking on Phase II of Incremental Pricing. U.S. Department of 

Energy, Office of Policy and Evaluation. Prepared for the Federal 

Energy Regulatory Commission. February 1980. 

1-11 
P.19 

• Technical and Economic Feasibility of Alternative Fuel Use in' 

Process Heaters and Small Boilers. Energy and Environmental 

Analysis, Inc. Arlington, Virginia. DOE/EIA-10547-01. Prepared 

for the U.S. Department of Energy, Energy Information Administration. 

February 1980. 

• An Analysis of the Potential for Coal Use in the Industrial Sector. 

Energy and Environmental Analysis, Inc. Arlington, Virginia. 

Prepared for the President's Commission on Coal. March 1980. 

3. Recent examples: 

• Projected Impacts of Alternative Sulfur Dioxide New Source 

Performance Standards for Industrial Fossil Fuel-Fired Boilers. 

Energy and Environmental Analysis, Inc. Arlington, Virginia. 

Prepared for the U.S. Environmental Protection Agency, Office of 

Air Quality Planning and Standards. March 1985. 

• Projected Environmental, Cost and Energy Impacts of Alternative 

SO2 NSPS for Industrial Fossil Fuel-Fired Boilers. Energy and 

Environmental Analysis, Inc. Arlington, Virginia. Prepared for 

the U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards. October 10, 1983; January 6, 1984; July 

27, 1984. 

• Projected Environmental, Cost and Energy Impacts of the Recommended 

Particulate Matter and Nitrogen Oxide New Source Performance 

Standards for Industrial Fossil Fuel-Fired Boilers. Energy and 

Environmental Analysis, Inc. Arlington, Virginia. Prepared for 

the U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards. January 1984. 

1-12 
P.20 

2. MODEL LOGIC 

The analytical approach in IFCAM is summarized in Section 2.1. Major 

model steps are presented and key model input requirements are identified. 

Model methodology and data sources are described in further detail in Sections 

3 and 4. 

User options are identified in Section 2.2. This section focuses on 

model input requirements related to several exogenous assumptions: 

• Alternative NSPS 

t Total projected industrial fossil fuel demand 

§ Industrial production growth by industry group 

• Forecasts of industrial fuel prices 

2.1 ANALYTICAL FRAMEWORK 

2.1.1 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 

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 (used in the iron and steel industry to produce coke) or 

raw materials derived from petroleum or natural gas in the chemical industry. 

A very disaggregate representation of industrial energy uses is 

incorporated in IFCAM. Energy use is disaggregated into nine industrial 

subsectors having different growth rates and regional dispersions. Each of 

these industrial subsectors is further divided into boiler and process heat 

applications. 

Industrial boiler energy use is disaggregated to fuel type utilized by 

new and existing boilers of different sizes and annual capacity utilization 

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. 

2-1 
P.21 

The final level of disaggregation incorporates regional detail. 

Industrial boiler fuel use is divided among Air Quality Control Regions 

(AQCR's). Since such a large number of regions are considered by IFCAM, 

the model can portray 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 

precludes significant market penetration of many of the advanced technologies 

still in the developmental stage. 

Based on the characteristics of each boiler (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 net present value (including expected 

fuel expenses) of the total cost of generating steam 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 and liquid waste treatment requirements, 

energy consumption associated 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. 

2.1.2 Model Logic 

Figure 2-1 outlines the model structure and identifies key inputs 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 DOE 

projected regional 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: 

2-2 
ro 

i 

co 

Input 2 

Industrial Production^ 

Growth Rates 

Input 1 

Industrial Fossil 

Fuel Use in 1974 

CHARACTERIZE 

FUEL 

CONSUMPTION 

Input 3 

Input 6 

Environmental 

Regulations 

Input 8 

Energy Policy 

Input 4 

Geographic 

Distribution of Boilers 

X 

CREATE AND 

SITE 

INDIVIDUAL 

COMBUSTORS 

Input 7 

Regional 

Fuel Prices 

IDENTIFY 

ENVIRONMENTAL 

REQUIREMENTS 

EVALUATE 

ECONOMICS 

OF FUEL 

CHOICE 

AGGREGATE 

MODEL 

RESULTS 

Input 5 

Input 9 

Boiler Size/Capacity 

Utilization Distribution 

Financial 

Parameters 

Input 10 

Capital and 

O&M Cost Data 

Projected Industrial 

Fossil Fuel Demand 

Legend 

^Inputs} Model 

Step 

FIGURE 2-1 

IFCAM Model Structure 

ro 
P.23 

• 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) 

t 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 

distributions 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 

determine baseline costs and emissions. The file contains current 

regulations that vary by boiler size, fuel type, and AQCR. 

Model Step #3 - Identify Environmental Regulations and Pollution Control 

Strategies: Emission limits for SO2, PM, and N0X 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. 

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 wellhead price deregulation, or variations in price trajectories. Fuel 

prices can be varied for distillate fuel oil, residual fuel oil (four sulfur 

classes), coal (nine coal types), and natural gas. The price of each fuel 

type can vary by region. 

Investment incentives considered have focused primarily on differential 

depreciation methods for coal-, oil-, or gas-fired units and on 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 fuel choice decision logic in IFCAM. 

2-4 
P.24 

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 legislative 

provisions related to economic exemptions. This procedure projects the 

level of increased coal use under the program, excluding any implementation 

problems. The coal conversion economic test option in IFCAM is not currently 

utilized in evaluating alternative NSPS's for industrial boilers for EPA. 

Input 10 - Capital and O&M Cost Data: Capital and O&M cost data relative 

to the range of boiler and pollution control equipment modeled in IFCAM are 

derived from numerous sources. Engineering cost data are revised on an asneeded basis when current estimates are refined or new estimates become 

available. 

Model Step #4 - Evaluate Economics of Fuel Choice: Based on the 

characteristics of each boiler (size, operating rate, pollution control 

requirements, 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 net present value (including capital and annual O&M 

and fuel expenses) of the cost of generating steam over the investment period 

then is selected. 

The cost components 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 represent standard investment 

assumptions. Key model variables -- capital costs, investment period, 

discount rate, annual fuel consumption by capacity utilization 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). 

2.1.3 Model Output Features 

A significant amount of output detail is stored in a computer file 

from each IFCAM run. This file contains information for each industrial 

fossil fuel-fired boiler in the population, including: 

2-5 
P.25 

• 

• 

• 

• 

• 

• 

• 

• 

• 

• 

t 

each 

resu 

2.2 

• 

• 

Size (design firing rate) ' ' 1 

Annual capacity utilization rate 

Federal region • 

Industry group • 

SIP _ 

Projected annual fuel consumption by fuel type | 

Average annual controlled air emission rates (SO2, PM, N0X) 

Pollution control equipment (see Table 1-1) I 

Capital, O&M, and fuel costs 

Liquid and solid waste disposal volumes M 

Annual energy requirements to operate pollution control equipment 

The model output tables span about 120 pages of computer print-out for • 

IFCAM run. A computer program is also available which compares model 

Its side-by-side from different IFCAM runs. • 

USER OPTIONS 

The IFCAM user options can be classified in two groups: • 

Alternative New Source Performance Standards (NSPS) and 

"Energy scenario" specifications. fl 

Alternative NSPS refers to alternative Federal air emissions standards for 

so2, 

oil, 

PM, and N0X emissions from the combustion of coal, distillate fuel 8 

residual fuel oil and natural gas in new industrial boilers. Energy 

scenario specifications are exogenous regional projections of: • 

§ 

• 

• 

are 

Industrial fossil fuel prices 

Total industrial fossil fuel demand • 

Industrial production activity. 

Figure 2-2 summarizes the major IFCAM user options. "User options" 1 

defined to be frequent user modifications to a subset of the model input 

files.

 v • 

2.2. 

• 

t 

• 

• 

1 Alternative NSPS 

There are eight industrial boiler size classes in IFCAM: • 

3-9 MW (10-30 MMBtu/hr), 

9-15 MW (30-50 MMBtu/hr), • 

15-22 MW (50-75 MMBtu/hr), • 

22-29 MW (75-100 MMBtu/hr), • 

2-6 | 
P.26 

FIGURE 2-2 

IFCAM User Options 

Industrial .Production 

Forecast 

NSPS 

Industrial Energy 

Demand Forecast 

IFCAM Industrial Fuel 

Price Forecast 

OUTPUT 

• Fuel Mix 

• Emissions 

• Costs 

2-7 
P.27 

• 29-44 MW (100-150 MMBtu/hr), 

• 44-58 MW (150-200 MMBtu/hr), 

• 58-73 MW (200-250 MMBtu/hr), 

• Greater than 73 MW (greater than 250 MMBtu/hr). 

Model users may specify emissions ceilings by boiler size category, annual 

capacity utilization rate (less than or greater than 30 percent), pollutant 

(SO2, PM, and N0X) and fuel type (natural gas, distillate fuel oil, residual 

fuel oil, and coal) in terms of pounds of emissions per million Btu of fuel 

consumption. 

Mandatory scrubbing can also be required for new residual fuel oil and 

coal boilers by size class. The SO2 emissions percentage removal requirement 

can be fixed (constant for all fuel types regardless of sulfur content) or 

variable (function of the sulfur content of the fuel, such as the current 

electric utility NSPS). 

The emissions standards, when expressed as an emissions ceiling 

(lb/MMBtu), limit compliance alternatives. For example, a mechanical 

collector is assumed not to be able to comply with a very low (i.e., 0.05 

lb/MMBtu) coal PM emission regulation. A very low (i.e., 0.2 lb/MMBtu) 

coal SO2 emissions ceiling will restrict coal compliance options to scrubbing 

low sulfur coals. 

The alternative NSPS assumptions apply only to new industrial boilers. 

They do not apply to existing industrial boilers. "New" industrial boilers 

are defined to be units installed after 1985. 

2.2.2 Industrial Fossil Fuel Price Forecast 

Projected delivered industrial fuel prices are required for the 

following fuel types: 

• Natural gas 

• Distillate fuel oil 

• Residual fuel oil 

- 3.0 percent sulfur 

- 1.6 percent sulfur 

- 0.8 percent sulfur 

- 0.3 percent sulfur 

2-8 
P.28 

1 • Coal (lb S02/MMBtu) 

- bituminous less than 1.08 

- bituminous 1.08-1.67 

- bituminous 1.67-2.50 

- bituminous 2.50-3.33 

- bituminous 3.33-5.00 

- bituminous greater than 5.00 

- subbituminous less than 1.08 

- subbituminous 1.08-1.67 

- subbituminous 1.67-2.50 

Fuel prices are required year-by-year (1985-2005 at a minimum) and by 

Federal region in constant 1978 $/MMBtu. 

2.2.3 Industrial Fossil Fuel Demand Forecast 

Total projected industrial fossil fuel demand is an exogenous parameter. 

IFCAM is a fuel choice model calibrated to an exogenous forecast of total 

industrial fossil fuel demand. IFCAM has not been used as a portion of a 

"general equilibrium" system which simultaneously reflects the interactions 

between the economy and energy markets. IFCAM does not address the relationship between overall industrial production and energy demand. 

"Total industrial fossil fuel demand" is defined to include only the 

sum of: 

• Natural gas (excluding lease and plant gas and transmission and 

distribution losses), 

• Distillate and residual fuel oil, and 

• Coal (excluding metallurgical coal). 

Projections are required by Federal region for the beginning and end of the 

simulation period (e.g., 1985 and 1990). The units are trillion Btu. This 

file includes projected industrial fossil fuel combustion in process heaters 

as well as in boilers. 

This file provides IFCAM with an expectation of the total net increase 

in total industrial fossil fuel demand during the simulation period. IFCAM 

estimates how much of this net increase will be burned by boilers and how 

much will be consumed in process heaters by region. 

2-9 
P.29 

2.2.4 Industrial Production Forecast 

Projections of industrial production activity are required by Federal 

region and industry group. There are nine industry groups in IFCAM: 

• Food 

• Textiles 

• Paper 

• Chemicals 

• Petroleum refining 

• Stone, clay and glass 

• Steel 

• Aluminum 

• Other (miscellaneous manufacturing, agriculture, construction, 

and mining). 

This forecast is used to disaggregate the projections of total 

industrial energy demand by industry group. The industrial production 

forecast should be consistent with the macroeconomic assumptions used to 

derive the forecast of total industrial energy demand. 

The industrial production forecast serves to allow model users to 

assume that the distribution of total fossil fuel demand by industry group 

within a region will not necessarily remain constant in the future. It 

also permits the model user to assume that, for a specific industry group, 

expected industrial production activity will increase or decline at different 

rates by region. 

This allocation by industry group in IFCAM is important. It is assumed 

that the boiler/process heater distribution of total industrial fossil fuel 

demand is unique for each industry. Since the industry mix is permitted to 

change over time, total projected boiler fossil fuel demand may increase at 

a different rate than total projected process heater fossil fuel demand. 

In addition, it is also assumed that the distribution of new industrial 

boiler sizes and annual capacity utilization rates is unique for each industry 

group. 

2-10 
P.30 

3. INDUSTRIAL BOILER POPULATION CHARACTERISTICS 

There are two major parts to IFCAM: 

• Project the distribution of industrial fossil fuel-fired boiler 

characteristics 

• Select the lowest-cost fuel type for each unique set of 

characteristics 

The major industrial boiler population characteristics are discussed 

in this section. The fuel choice decision criteria are summarized in 

Section 4. 

The characteristics discussed in this section include: 

Industry group 

Functional use (boilers versus process heaters) 

New or existing status 

Size (design firing rate) and annual capacity utilization rate 

Fuel-firing capability 

Local air emissions regulations 

Pollution control compliance alternatives 

3.1 FOSSIL FUEL DEMAND PROJECTIONS BY INDUSTRY GROUP 

3.1.1 Significance for Modeling 

IFCAM projects the mix of fossil fuels given exogenous forecasts of 

total industrial fossil fuel demand, fuel prices and industrial production 

activity. The projected net increase in total industrial fossil fuel demand 

is an important input parameter because it directly affects the projected 

number of new combustors in IFCAM. If there is no projected net increase 

in total industrial fossil fuel demand (due to expected conservation), new 

units will be created only to replace expected retirements (not to expand 

production capacity). If the expected net increase is significant, IFCAM 

will estimate how much of this net increase will be burned by boilers versus 

3-1 
P.31 

process heaters. Therefore, the number of new industrial boilers is a 

function of the expected retirements and replacements of existing boilers 

and the estimated increase in total industrial boiler fossil fuel demand. 

Industrial energy consumption characteristics vary by industry group. 

Therefore, the first step is to allocate the industrial fossil fuel demand 

forecast by industry group. 

3.1.2 Allocation of Projected Industrial Fossil Fuel Demand By Industry 

Group 

Energy demand projections depend on rates of production growth, the 

introduction of new technologies (such as continuous casting in steel which 

reduces energy consumption per ton of steel processed), shifts in the product 

mix within any specific industry (as toward more highly processed, more 

energy-intensive frozen foods), fuel costs, opportunities to install energy 

recovery equipment, and capital available for energy saving measures. 

Business cycle fluctuations also affect energy consumption per unit of product. 

In DOE's Intermediate Future Forecasting System (IFFS), industrial 

energy demand is driven by industrial output growth rates and prices for 

energy, labor, capital, and raw materials which are input into econometric 

equations based on historical relationships. IFCAM was specified to be 

consistent with the regional total industrial fossil fuel demand projections 

generated by IFFS. In order to classify regional fossil fuel use by the 

nine industrial sectors used in IFCAM, the following steps were taken: 

• Regional industrial production growth rates for the nine sectors 

were taken from the same macroeconomic model output used in the 

IFFS run 

• The industrial production growth rates were adjusted for an 

expected reduction in energy use per unit of output by industry 

(conservation effect) 

• Baseline fossil fuel consumption data is multiplied by the 

adjusted industry/region production growth rates to derive 

preliminary total projected fossil fuel consumption by region and 

industry 

• The preliminary fossil fuel consumption estimates in each region 

are then normalized to be consistent with the IFFS regional 

projections of total industrial fossil fuel demand 

3-2 
P.32 

It is possible for total expected fossil fuel consumption in some 

industry and region to decrease. Examples: 1) if the conservation factor 

(reduction in energy use per unit of production) is larger than the 

industrial production growth rate, 2) if the industrial production growth 

rate is negative, or 3) if the sum (across industry groups within a region) 

of the preliminary projected fossil fuel demand estimates are substantially 

higher than the IFFS regional total projected fossil fuel demand and the 

preliminary industry estimates must be reduced (normalized). 

Table 3-1 presents the industrial energy conservation factors used in 

IFCAM. 

3.2 CATEGORIZATION OF FOSSIL FUELS BY FUNCTIONAL USE 

3.2.1 Significance for Modeling 

Classifying fossil fuels by functional use is critical because the 

technical and economic issues of fuel substitution vary according to 

specific process applications. To categorize fossil fuels by functional 

use, projected energy consumption for each region and industry is split 

into two functional use classes: boilers and process heaters. Boilers use 

fossil fuels to produce process steam, hot water, and internally generated 

electricity. Boilers consume more oil and gas than any other single 

industrial consumption process. Process heat applications include furnaces, 

ovens, kilns, and heaters and exclude all boiler and feedstock uses. 

3.2.2 Allocation of Projected Fossil Fuel Use Among Boiler and Nonboiler 

Categories By Industry 

For each region and industry, projected total fossil fuel consumption 

is split between two classes: boilers and process heaters. The breakdown 

is based on 1974 data from the ECDB. Currently, coal is used primarily in 

boilers; cement kilns are the exception. For most of the industries shown, 

the difference in boiler/nonboiler splits between oil and gas use is slight. 

When differences exist, there are no obvious technical or economic reasons 

for a particular industry to prefer oil to gas, or vice versa. The 

discrepancies between the functional use splits for each fuel are smaller 

than the level of probable error associated with ECDB functional use data. 

Consequently, the split between the two major functional uses is based on 

the sum of historical coal, oil, and gas consumption in each industry. The 

focus on total fossil fuels (rather than on coal, oil, and gas separately) 

3-3 
P.33 

TABLE 3-1. PROJECTED INDUSTRIAL ENERGY CONSERVATION FACTORS3 " 

Industry IS8~5" 1990, 1995 

0.959 

0.759 

0.788 

0.765 

0.914 

0.789 

0.758 

0.759 

Food 

Textiles 

Paper 

Chemicals 

Petroleum 

SCG 

Refining 

Primary Metals 

Other Indu stry 

0.949 

0.844 

0.871 

0.842 

0.924 

0.827 

0.825 

0.844 

a Energy Conservation in the Manufacturing Sector, 1954-1990. Energy and 

Environmental Analysis, Inc. Arlington, Virginia. November 1974. 

Prepared for the Council on Environmental Quality. Published by the 

Federal Energy Administration Project Independence Blueprint Interagency 

Task Force on Conservation. Energy consumption per unit of output: 

1975 = 1.0. 

All industry estimate. 

3-4 
P.34 

seems warranted since the ratio of coal to oil to gas in the future is 

expected to differ substantially from historical patterns. Consequently, 

the classification by functional use and new/existing combustors is made 

first only for total fossil fuels, leaving the specific allocation of fossil 

fuel demands by fuel type to a later step in the classification process. 

National functional use shares for fossil fuels by industry are shown 

in Table 3-2. Based on fuel use, major industry groups generally can be 

disaggregated into predominantly boiler or nonboiler industries. The 

industries predominantly using boilers are Food, Textiles, and Paper, while 

nonboiler industries are Petroleum Refining, SCG, and Steel. Aluminum, 

Chemicals, and "Other" industries use approximately an equal mix of boiler 

and process heat fuel. 

The boiler industries can be classified further as industries using 

small boilers (e.g., Food and Textiles) or industries using large boilers 

(e.g., Paper and Chemical Manufacturing). In the Food industry, process 

steam is used primarily for washing and sterilizing containers, cooking, 

evaporating, space heating, and electricity generation. The Textile 

industry relies heavily on purchased electricity to drive the machinery in 

the plants; fuel oil and natural gas are used predominantly in this industry 

in boilers. In this industry, process steam also is used for fabric 

preparation, dyeing, and finishing operations as well as space heating. 

Very little electricity is generated in textile mills. 

The larger-boiler industries, Paper and Chemical Manufacturing, use a 

significant portion of total steam demand to generate electricity. In 

Chemical Manufacturing, process steam demand is used to strip away unreacted 

feed, as dilution steam, and to drive steam compressors. The process fuel 

uses are primarily in cracking furnaces. Process steam in the Paper industry 

is used to generate electricity and in the pulping and bleaching processes. 

Some systems also use steam in debarking. 

Process uses of scarce fuels in the Petroleum Refining industry are in 

tubestill heaters or furnaces. In Steel manufacture, blast furnaces, soaking 

pits, reheat furnaces, and heat treating applications are the primary process 

uses. SCG fuel use is dominated by cement production which uses process 

heat in cement kilns. Glass production comprises the other significant 

portion of SCG, with glass furnaces as the primary energy user. 

3-5 
P.35 

TABLE 3-2. DISTRIBUTION OF FOSSIL FUELS BETWEEN BOILER 

AND PROCESS HEAT USES3 

(percentage of total fossil fuel demand) 

Industry Boiler Process heat 

Food 

Textiles 

Paper 

Chemicals 

Petroleum Refining 

Stone, Clay, and Glass 

Steel 

Aluminum 

Other 

74 

80 

-81 

65 

25 

33 

55 

44 

26 

20 

19 

35 

75 

99 

67 

45 

56 

aEEA estimates based on the End-Use Energy Consumption Data Base (1974 

data). Includes coal, natural gas, and fuel oil. 

b, Less than 1 percent. 

3-6 
P.36 

Aluminum is a large electricity producer and the bulk of the boiler 

use in that industry is consumed to self-generate electricity. The rest of 

the fuel, roughly half, is consumed in direct heat applications. 

3.3 CATEGORIZATION OF BOILER FOSSIL FUEL USE BY NEW AND EXISTING FACILITIES 

3.3.1 Significance for Modeling 

The new/existing distinction is important in any process engineering 

analysis of fuel choice decisions since the technical capability, the nature 

of the investment decision, energy and environmental policies, and the costs 

of using alternate fuels differ for existing units and new facilities. 

Existing boilers can be retrofitted to burn oil or gas; they can be 

converted to coal either by reconverting units originally designed to fire 

coal or by accelerating replacement of existing units that never fired coal 

with new coal-fired boilers; conversion to any other fuel involves 

retrofitting the bo'iler. Retrofitting, for coal use, oil/natural gas boilers 

that never were designed to burn coal is impractical for two reasons. First, 

boiler capacity must be downrated substantially (20 to 60 percent less than 

original design capacity) and second, necessary modifications to existing 

2 

equipment may be physically impossible. 

The primary constraint to boiler modification is combustion volume. 

Significantly more combustion volume is required for burning coal than for 

burning oil or gas to insure that the flue gas temperature at the entrance 

to the boiler convective section is below coal's ash-softening point. Coal 

firing also requires additional burnout time to permit more heat absorption 

in the radiant (waterwall) section. If it is physically impossible or 

economically impractical to enlarge the furnace area, boiler capacity must 

be downrated substantially. 

Other boiler constraints to coal conversion are convective section and 

air preheater redesign and the addition of sootblowers and fans. Due to 

these technical problems, converting existing units not originally designed 

to burn coal to coal firing is assumed to be infeasible unless the boiler 

is replaced. 

The purpose of the Powerplant and Industrial Fuel Use Act (FUA) is to 

reduce oil and natural gas consumption in American industries and utilities 

by promoting the use of coal and other "alternative" fuels. FUA gives DOE 

the authority to prohibit or limit the use of oil and natural gas in certain 

3-7 
P.37 

new and existing industrial boilers. FUA provisions are different for new 

and existing boilers and this is an example of the significance of the new/ 

existing distinction with respect to energy regulations. 

An obvious example related to environmental regulations is the Federal 

NSPS which governs emissions from new or modified stationary sources. The 

NSPS are designed to reflect the degree of emission control achievable through 

the application of the best system of emission reduction which EPA, having 

taken into account the cost of control, determines to be demonstrated 

adequately. The Federal NSPS is the same throughout the country. The 

national impacts of NSPS are a function of the projected mix of new and 

existing facilities. 

Due to varying technical problems associated with converting existing 

combustors to fire coal, the investment decisions and associated costs of 

fuel substitution differ among combustors. The following four classes of 

combustors each involve different technical problems, costs, and investment 

decisions: 

• Existing coal-capable units: These combustors currently are 

firing oil or gas but originally were designed to use coal. 

Minor capital investment is needed to refurbish coal-related 

equipment already available in order to return to coal use. 

Pollution control equipment may be needed as well, depending on 

environmental regulations. 

• Existing units designed to fire only oil and/or gas that can be 

retrofitted: For these combustors, it is cheaper to retrofit an 

existing unit to fire coal rather than to entirely replace the 

combustor with a new coal-fired unit. The elements of the investment decision for conversion to oil or gas are similar to those 

for the existing coal-capable combustor. 

• Existing units designed to fire only oil and/or gas that cannot 

be retrofitted economically: For this class of combustors, it is 

more economic to replace an existing unit with a new coal-fired 

unit than to retrofit the facility to fire coal. 

• New facilities: For new combustors, the costs of new units for 

each fuel type are compared, including total capital investments 

and operating and fuel costs. 

3-8 
P.38 

i 

3.3.2 Approach to Allocation of Fuel Use Among New/Existing Facilities 

Because projected fossil energy demand in any future year is an 

exogenous input to the IFCAM model, the split between energy use in new 

facilities and existing facilities will be determined by the exogenous growth 

rate in total fossil fuel demand plus the retirement rate of existing 

facilities. 

Retirement of energy use in existing combustors can occur through 

reduced capacity utilization or actions that reduce fuel use to essentially 

zero, such as actual scrappage or a shift to standby status. The decision 

to retire a combustor is determined by many parameters. Over time, equipment 

will deteriorate and require replacement. Maintenance costs tend to increase 

and, depending on the type of combustor, fuel use efficiency (e.g., for a 

boiler, fuel input in Btu per pound of steam generated) may decline. 

Essentially random factors, such as the phaseout of an uneconomic plant or 

part of an old plant's production, also can cause a combustor to retire. 

In addition, the technical fuel use efficiency and cost of new combustors 

will affect retirement rates. Fuel costs, conservation potential, the 

availability of capital, and other investment demands all influence retirement rates. Logically, the decision to replace combustors depends on the 

economics of plant- and corporate-specific situations. 

In a previous study, EEA used the concept of vintaging plus decay 

3 

factors to estimate retirement or capital turnover rates. This approach 

indicated retirement rates (percent of annual energy use retired) for boilers 

ranging from two to three percent. 

The current boiler retirement methodology in IFCAM is to estimate an 

annual capital turnover rate. The current annual retirement rate estimate 

is 0.62 percent of projected industrial boiler fuel demand. This estimate 

is based on an ABMA representative's subjective estimate that 15 percent of 

ABMA data on new industrial watertube boiler sales capacity represents 

replacement boilers. No estimate for boiler retirements without replacements 

is available. 

Fifteen percent of the 1965-1976 average annual ABMA new industrial 

watertube boiler capacity sales data* is 8,028 MMBtu/hr.** Assuming that 

•Domestic orders for manufacturing industries only. 

**Assuming 1,250 Btu/lb steam. 

3-9 
P.39 

the average industrial boiler capacity utilization rate is 55 percent,

 fthe * 

level of retirement and replacement of annual watertube boiler fuel demand 

is 8,028 MMBtu/hr x 0.55 x 8,760 hours/year = 38.68 trillion Btu/year. This 

level of retirements represents 0.62 percent of the EEA estimate of fossil 

fuel consumption in industrial boilers in 1976 (6.25 quadrillion Btu). This 

retirement rate is applied to total industrial boiler fossil fuel demand --

small firetube boilers as well as watertube boilers -- in IFCAM. 

This analysis assumes that a constant percentage of the current capital 

stock is retired every period. As a result, total retirement is a function 

not only of the retirement rate selected, but also of the rate of growth of 

the capital stock. This approach may overstate retirements during periods 

of high growth and understate retirements during periods of low growth. 

The calculation procedure of the total retirement of existing boilers 

between 1985 and 1990 is as follows. First, total boiler fossil fuel demand 

in 1985 and in 1990 is estimated. Second, total boiler fossil fuel demand 

in every year between 1985 and 1990 is estimated by calculating the compound 

average annual growth rate. Third, the retirement rate is applied to the 

total estimated boiler fossil fuel consumption in 1986, 1987, ..., 1990 in 

order to determine the total amount of boiler fossil fuel demand to be 

retired in the 1985-1990 period. 

The "boiler records" or inventory in IFCAM are not individual units 

but groups or classes of boilers. Each group is defined by location (10 

Federal regions), fuel type, size class (8), capacity utilization class 

(5), industry group (9), new/existing status, and air emission regulation. 

IFCAM projects total boiler fuel demand in a future year, multiplies this 

value by (1.0062)a - 1 (where a = forecast year - base year), and subtracts 

this fuel demand proportionally from each group of boilers which existed in 

the base year (currently 1974). Boilers installed after 1974 are not 

retired. 

It is assumed in IFCAM that the load factor is constant over the life 

of the unit on an annual basis. That is, changing steam requirements are 

met by retiring existing units and adding enough new units to meet the total 

projected steam demand requirements. 

IFCAM models each boiler fuel choice decision independently. Costs at 

a plant (as a whole) are not minimized. Fuel choice decisions are made as 

if each boiler is the only boiler at each plant. IFCAM is not a steam plant 

planning optimization model. Therefore, the current boiler inventory in 

3-10 
P.40 

IFCAM is not characterized by plant size or type of plant. IFCAM does not 

have the capability to predict future steam requirements at specific plants, 

and IFCAM does not make an integrated decision to minimize total steam plant 

costs. 

The current retirement methodology in IFCAM does not explicitly take 

into account the age of equipment or the economics of continuing to use old 

equipment versus replacing it with new equipment. In addition, the IFCAM 

approach does not model retirements without replacements, and, as a result, 

may understate the retirement rate. Furthermore, the IFCAM approach assumes 

that boiler capacity utilization rates are constant and that annual increases 

or decreases in steam demand cannot be met to some extent by changing the 

capacity utilization rate of the existing inventory. 

One factor worth emphasizing is that EEA's approach to estimating 

retirement rates does not consider the effect of rising fuel costs or energy 

policy on the overall efficiency of energy use in existing combustors. For 

example, taxes on fuel use affecting existing combustors will conserve energy 

because higher fuel costs will promote efforts to increase the efficiency 

of existing units; this energy conservation, however, will not be captured 

by retirement rates based on historical trends. The failure of IFCAM to 

consider the impact of energy policy or fuel prices on overall energy 

efficiency in existing units will tend to bias fuel mix results away from 

coal. This bias occurs because the projected year fossil energy demand 

(exogenous to IFCAM) does include the effect of higher fuel prices, for 

example, on overall fuel use efficiency. Since IFCAM ignores this conservation effect in determining normal retirement rates, conservation benefits 

come entirely out of fuel use in new combustors. 

3.3.3 Alternatives 

The age of the unit may be significant if it can be established that a 

maximum expected useful life can be determined (e.g., 30 or 40 years). All 

units then would be retired once their "age" exceeded the appropriate maximum 

useful life estimate. However, low usage rates, conscientious O&M practices, 

and refurbishment opportunities may extend the useful life. In addition, 

this approach does not address the situation where the unit is retired 

prematurely (and not resold) due to a plant closing, energy conservation, 

or reduced production rates. 

3-11 
P.41 

It is feasible that an economic framework could be developed which 

would compare the increasing O&M costs of existing boilers with the cost of 

a new boiler (levelized capital plus O&M). O&M costs of existing equipment 

may be expected to increase because of declining efficiency, parts replacement, 

and increased maintenance expenses. The unit could be replaced when the 

average cost of a new unit is less than the average future O&M costs of the 

existing unit. 

However, it is difficult to collect data on O&M costs for a single 

combustor. Plant managers are usually unable to allocate or track all labor 

and materials costs combustor by combustor. As a result, long-term time 

series data for an individual unit are not available, and estimates of 

increasing O&M costs over time for old units cannot be made. 

If it is assumed that O&M costs do not increase in real terms over 

time, an economic framework still could be developed. An existing unit 

would never be replaced with a new unit that has the same fuel type in this 

analysis because the O&M costs would be identical and the levelized capital 

costs of the new unit would preclude the new unit from being the low cost 

alternative. Therefore, this approach does not focus on retirement but on 

"early replacement" with a new fuel type. In fact, the new fuel type would 

always be coal. It is unlikely that a plant manager would replace a coal 

boiler with a new gas/oil boiler; the lower non-fuel O&M costs associated 

with burning gas or oil would not likely offset the capital cost of a new 

gas/oil boiler and the higher fuel bills. 

"Early replacements" (or accelerated retirements) are not normal 

retirements. They are a relatively expensive fuel-switching, retrofit option 

for coal firing. They depend to a large extent in capital availability — 

capital invested to earn a return by reducing future total O&M and fuel 

costs. They can be considered as discretionary investments because they do 

not necessarily (or primarily) improve or expand production capacity. Early 

replacements may benefit the company by saving premium (and expensive) fuels 

for premium uses and switching a portion of energy purchases to fuels with 

a relatively better supply and price outlook (i.e., coal). In addition, an 

economic framework for early replacements does not address the situation 

where boilers are scrapped or placed on stand-by. 

Plant managers match boiler capacity with seasonal and daily steam 

load curves. They may provide for some measure of redundant boiler capacity 

3-12 
P.42 

so that the plant can operate at partial or full production capacity in the 

event of an unexpected boiler shutdown. It is not possible to optimize 

boiler configurations at a specific plant without data on future steam load 

curves. However, it may be possible to develop a few generic plant types 

and simulate the retirement strategy for each. The problem then would be 

how to assign the existing boiler population to one of the generic plant 

types. 

Ideally, the retirement methodology would be a dynamic function of the 

boiler age, efficiency, expectation of fuel costs over the remaining life 

of the unit, non-fuel O&M costs, pollution control requirements for existing 

and new units, capital availability, expectations of future plant increasing 

or decreasing steam requirements, and possibly cogeneration with a new unit. 

However, data on industrial boiler retirements and associated parameter 

values do not exist. The ABMA and DOE collect data on new boiler orders, 

but the data do not distinguish between replacements of retired units, 

increased steam capacity at existing plants, and new plants. This data 

base also does not include data on existing boilers which are scrapped, 

load reduced and placed on stand-by, or load factor increased to meet new 

steam demand requirements. 

Boiler owners could be interviewed to discuss this issue. Specifically, 

boiler owners could be asked how they make retirement decisions and how 

many boilers have been retired. The reasons for retirement may be numerous, 

somewhat subjective or plant-specific, and difficult to quantify in economic 

or financial terms. It may also be difficult for a current plant manager 

to document activities (i.e., retirement decisions) which happened years 

ago. The information collected may be anecdotal with no basis for assigning 

existing plants to one of these "case studies" or predicting how these 

retirement variables will vary in the future. 

3.4 CLASSIFICATION OF BOILER FUEL USE BY SIZE AND CAPACITY UTILIZATION 

RATE 

3.4.1 Significance for Modeling 

The size and capacity utilization rate of a boiler greatly affect fuel 

choice decisions. Boiler size is important for several reasons. First, 

boiler costs are characterized by economies of scale and these directly 

affect the economics of fuel choice decisions. Second, pollution control 

3-13 
P.43 

strategies, often involving substantial capital and operating costs, vary 

by size. Third, environmental regulations, both State and Federal, often 

specify levels of air pollution control by boiler size. Fourth, recent 

Federal energy tax policies, investment incentives, and regulatory proposals 

have targeted industrial boilers of specific size ranges. To capture these 

implications of boiler size on fuel choice decisions, IFCAM disaggregates 

boiler fuel demand into several size categories. 

The capacity utilization rate of a boiler is also a critical parameter 

in the economics of fuel choice decisions. A capacity utilization rate 

represents the total Btu actually burned in a boiler during a year divided 

by the maximum Btu that could be burned, assuming a fixed design firing 

rate of the boiler and 8,760 hours of operation per year. A high capacity 

utilization rate gives certain capital intensive technologies (with large 

economies of scale) a competitive edge. 

As shown in Table 3-3, it is assumed that new non-coal industrial 

watertube boilers have dual-fuel (oil/gas) firing capability, residual fuel 

oil/natural gas or distillate fuel oil/natural gas. All new coal-fired 

boilers larger than 73 MW (250 MMBtu/hr) are assumed to be pulverized coal 

units. New industrial coal-fired boilers between 29 MW (100 MMBtu/hr) and 

73 MW (250 MMBtu/hr) are assumed to be a mix of pulverized coal and spreader 

stoker units. These two methods of coal combustion have different costs, 

flue gas flow rates and uncontrolled PM and N0X emission rates. New 

industrial coal boilers between 15 MW (50 MMBtu/hr) and 29 MW (100 MMBtu/hr) 

are assumed to be spreader stoker units. New industrial coal-fired boilers 

smaller than 15 MW (50 MMBtu/hr) are assumed to be underfeed stokers. 

There are eight boiler sizes (see Table 3-3) and five boiler capacity 

utilization rate classes (25, 45, 55, 65, and 75 percent) in IFCAM. 

3.4.2 New Industrial Boilers 

The specific boiler size/capacity utilization rate combination for 

individual new industrial boilers is derived by applying a frequency 

distribution to the total projected level of fossil fuel demand in new 

boilers. This distribution is based on historical data and is assumed to 

remain constant over time and not to vary by region. 

The current distribution in IFCAM has been derived from three sources: 

4 

ABMA industrial watertube boiler sales data, a PEDCo report, and NEDS. 

The NEDS data were used to develop a preliminary distribution of boiler 

3-14 
P.44 

TABLE 3-3. NEW INDUSTRIAL BOILER SIZE/TYPE ASSUMPTIONS IN IFCAM 

Boiler size category, 

MW (MMBtu/hr) heat input 

Representative 

Range 

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) 

>73 

(>250) 

size 

6 

(20) 

12 

(40) 

18 

(62) 

26 

(87) 

37 

(125) 

51 

(175) 

66 

(225) 

95 

(325) 

Coal 

Package, watertube, underfeed 

stoker 

Package, watertube, underfeed 

stoker 

Field-erected, 

watertube, 

spreader stoker 

Field-erected, 

watertube, 

spreader stoker 

Field-erected, 

watertube, 

spreader stoker 

or pulverized 

coal 

Field-erected, 

watertube, 

spreader stoker 

or pulverized 

coal 

Field-erected, 

watertube, 

spreader stoker 

or pulverized 

coal 

Field-erected, 

watertube, 

pulverized coal 

Type 

Residual oil/ 

natural gas 

Package, 

firetube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Two package, 

watertube0 

Two package, 

watertube 

Distillate oil/ 

natural gas 

Package, 

firetube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Two package, 

watertube0 

Two package, 

watertube0 

Firetubes are single-fuel fired. Watertubes are dual-fuel fired. 

3 A mix is assumed in this size class. 

'Each one-half of the "representative size" in the second column. 

3-15 
P.45 

fuel consumption by size category, capacity utilization class, and industry ' 

group. This preliminary distribution was normalized to correspond to PEDCo 

estimates of the national distribution of industrial firetube versus watertube 

boiler capacity in 1977. This distribution was further normalized to 1965-

1980 ABMA industrial watertube boiler sales data. Therefore, the watertube 

boiler size distribution is based primarily on ABMA data. The mix of new 

firetube and watertube industrial boilers is based primarily on PEDCo 

estimates. The capacity utilization distribution for each size class in 

each industry group is based primarily on NEDS data. 

This procedure was followed because of the data limitations of each 

data source. NEDS includes industry group, size, and capacity utilization 

rate information for the existing boiler inventory but does not have complete 

coverage for small boilers. The PEDCo estimates do not include data on 

industry group or capacity utilization rate. The ABMA data do not include 

information on capacity utilization rate. 

A unique distribution has been developed for each industry group. This 

distribution is presented in Table 3-4. 

3..4.3 Existing Industrial Boilers 

Aggregate data on large existing units have been collected from the 

MFBI file. Coal, oil, and gas consumption in boilers greater than 29 MW 

(99 MMBtu/hr) and existing in 1974 have been identified by location (AQCR), 

firing capability by fuel type, industry, size class, and capacity utilization rate class. Fossil fuel consumption in smaller existing units is not 

covered by the MFBI file, and NEDS data does not include 1974 data for all 

combustors. Therefore, fuel consumption in smaller units was estimated by 

fuel type, region, and industry as a residual -- aggregate ECDB fuel consumption in industrial boilers less aggregate MFBI fuel consumption in large 

industrial boilers. The size and capacity utilization rate classes for 

these small existing industrial boilers are based on NEDS data. 

The capacity utilization rate is assumed to remain constant over time. 

Increasing demand for boiler fuel over time is assumed to be met by building 

new units, not increasing the capacity utilization rates of the existing 

inventory. 

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P.47 

TABLE 3-4. NEW INDUSTRIAL BOILER SIZE/CAPACITY 

UTILIZATION RATE DISTRIBUTION3 (cont'd) 

Industry 

group 

Chemicals (cont'd) 

Textiles 

Petroleum Refining 

Boil er size Capacity 

MW (MMBtu/hr) utilization 

18 

18 

18 

26 

26 

37 

37 

51 

51 

66 

66 

95 

95 

95 

95 

6 

6 

12 

12 

12 

18 

18 

26 

37 

37 

51 

6 

12 

12 

18 

18 

26 

37 

51 

51 

95 

95 

(62 

(621 

(62 

(87 

(87; 

(125 

(125 

(175, 

(175 

(225; 

(225 

(3251 

(325 

(325 

(3251 

(20; 

(20 

(401 

(40; 

(40; 

(62; 

(62^ 

(87; 

(125; 

(125; 

(175; 

(20; 

(40] 

(40; 

(62; 

(62; 

(87; 

(125; 

(175; 

(175; 

(325) 

(325; 

.25 

.65 

.75 

.25 

.65 

.45 

) .75 

.45 

.75 

.45 

.75 

.25 

.45 

.65 

.75 

.25 

.75 

.25 

.45 

.75 

.25 

.75 

.25 

.25 

.65 

.45 

.25 

.65 

.75 

.45 

.75 

.75 

.75 

.45 

.75 

.25 

.75 

Frequency 

.0294 

.0214 

.0334 

.0160 

.0488 

.0654 

.0872 

.0684 

.0872 

.0625 

.0640 

.0370 

.0370 

.0753 

.1507 

.1031 

.0513 

.0955 

.0424 

.0702 

.0792 

.1044 

.1018 

.1074 

.1285 

.1162 

.0375 

.0416 

.1000 

.0427 

.0716 

.0972 

.0598 

.0855 

.1655 

.0844 

.2142 

Energy and Environmental Analysis, Inc. 

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P.49 

3.5 ENVIRONMENTAL REGULATIONS 

3.5.1 Significance for Modeling 

Environmental regulations play an important role in determining 

industrial fuel choice. For example, air emission regulations alter 

relative capital and fuel costs and may preclude the use of certain fuels 

in boilers. Specific environmental regulations can vary according to 

geographic location, boiler size and type, and fuel type. Both Federal and 

State environmental regulations influence fuel choice. 

The impact of environmental regulations is modeled in IFCAM in a 

three-step process. First, each boiler is assigned to an Air Quality 

Control Region (AQCR) based on historical location patterns of industrial 

energy consumption. Second, the specific air emission limits applicable to 

each boiler are identified. Next, the pollution control equipment and the 

fuel quality required to meet emission limits are specified. 

3.5.2 Assignment of Boilers to AQCR's 

The environmental regulations that apply, to any type of boiler can 

vary significantly from one AQCR to the next. While NSPS provisions apply 

equally in all parts of all regions, SIP provisions often vary among AQCR's 

and, in some cases, among areas within AQCR's. 

Within each region, new boilers are located randomly by AQCR according 

to historical patterns. Within each region and fuel type, a cumulative 

distribution function was developed for the level of fuel use in each AQCR. 

The distribution of fuel use among AQCR's is based on a 1975 working paper 

that used EPA emission inventory data (including fuel use). If AQCR #1 

consumed three times as much fuel as AQCR #2 consumed, then each new boiler 

(in each industry, size/capacity utilization class) is three times more 

likely to site in AQCR #1 than in AQCR #2. 

Within a Federal region, no attempt was made to model changes in 

industrial location patterns. Such trends are extremely difficult to 

identify and project and certainly were beyond the scope of this effort. 

Consequently, State and local environmental regulations implicitly are 

assumed not to influence industrial location patterns. 

3.5.3 Assignment of Environmental Regulations to Individual Boilers 

The fuel used to fire a boiler is influenced by environmental regulations governing air pollution emissions, among other factors. A variety of 

3-20 
P.50 

Environmental regulations may apply to any boiler depending upon type, size, 

location, and the fuel fired by the unit. The environmental regulations to 

which a boiler is subject help determine the applicable pollution control 

equipment as well as its fuel choice. 

The regulations used in IFCAM are Federal and State air pollution control 

standards resulting from the 1970 and 1977 Clean Air Act (CAA) Amendments. 

This act gave the EPA the authority to establish National Ambient Air Quality 

Standards (NAAQS) that would protect the health and welfare of the population. 

Industrial sources are subject to State Implementation Plan (SIP) environmental 

regulations adopted to insure compliance with ambient standards. SIP's are 

developed by each State to implement and maintain NAAQS within its geographical 

area. 

The CAA also gave EPA the authority to promulgate NSPS, national 

standards governing the air emissions from specific categories of newly 

constructed sources. NSPS are technology-defined Federal standards; 

combustors subject to NSPS must use the best available emission control 

technologies (BACT). Current NSPS provisions apply to boilers commencing 

on-line status after 1971 that have firing rates above 73 MW (250 MMBtu/hr 

heat input). For any unit of this type, the current NSPS is the binding 

regulation unless the applicable SIP for any given unit is more stringent 

-- hence binding -- than the NSPS. The current NSPS for industrial fossil 

fuel-fired boilers is under scrutiny by EPA to determine the need for, and 

extent of, revisions to the regulation. 

State and Federal regulations can vary by fuel type. Regulations 

applicable to boilers that fire one of the following fuels are considered 

in IFCAM: coal, residual fuel oil, distillate fuel oil, and natural gas. 

Regulations limiting SO2, PM, and N0X emissions are assumed to apply to 

coal- and residual oil-fired boilers. In IFCAM, distillate oil- and natural 

gas-fired boilers are subject only to N0X emissions regulations since units 

firing these fuels emit insignificant levels of SO2 and PM. 

New Boilers Subject to NSPS 

All boilers installed after 1974 with firing rates greater than 73 MW 

(250 MMBtu/hr heat1input) currently are subject to NSPS provisions. Coal-, 

oil-, and natural gas-fired units are subject to the NSPS air emissions 

limitations presented in Table 3-5. IFCAM applies these limitations to new 

units that are not subject to more stringent SIP's. 

3-21 
P.51 

TABLE 3-5. CURRENT INDUSTRIAL BOILER NSPS3 

Boiler size 

Fuel type MW (MMBtu/hr) SO2 PM NOx 

Natural gas > 73 (> 250) - - 86 ng/J 

(0.2 lb/MMBtu) 

Fuel oil > 73 (> 250) 340 ng/J 43 ng/J 86 ng/J 

(0.8 lb/MMBtu) (0.1 lb/MMBtu) (0.2 lb/MMBtu) 

Coal > 73 (» 250) 520 ng/J 43 ng/J 300 ng/J 

(1.2 lb/MMBtu) (0.1 lb/MMBtu) (0.7 lb/MMBtu) 

340 CFR 60, Subpart D. 

3-22 
P.52 

For new units that come on-line after 1985, IFCAM can evaluate several 

regulatory alternatives. For example, IFCAM can evaluate the effect of 

expanding the size applicability of the regulation to include new units 

smaller than 73 MW (250 MMBtu/hr heat input). IFCAM can also evaluate the 

effects of a pollutant percentage reduction requirement or a change in 

stringency from the current NSPS. For example, the regulation for controlling 

SO2 emissions from residual fuel oil or coal-fired boilers can vary by boiler 

size and can be specified as the following: 

• A ceiling emission rate (pound of pollutant/MMBtu of fuel burned) 

• A recommended percentage removal (e.g., 90 percent removal of 

uncontrolled SO2 emissions) 

• A recommended percentage removal and a "floor" emission 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 less than 

the "floor" 

Boilers Subject to SIP's 

All existing boilers and new boilers with firing rates lower than 73 

MW (250 MMBtu/hr heat input) are subject to SIP's.* Larger new boilers 

subject to SIP's more stringent than the current NSPS also must abide with 

SIP regulations. SIP limits on SO2, PM, and N0X emissions vary substantially 

within and among States, both in the severity of the standards and in the 

way they are expressed. Some States specify standards only in terms of 

ambient conditions. Most States, however, specify standards in a variety 

of forms including pounds of pollutant per energy release of the fuel (lb/ 

MMBtu), pounds of pollutant emitted per 1,000 pounds of steam, or pollutant 

content of the fuel, by weight, in percentage terms. In many States, SIP 

requirements also vary by fuel type and boiler size. 

A set of regulations reflecting the diversity of SIP requirements has 

been compiled for use in IFCAM. These SIP's are identified by AQCR and 

boiler fuel type (coal or residual fuel oil) and are specified as pounds of 

pollutant emitted per million Btu of fuel burned. Since a number of AQCR's 

*Small new boilers may be subject to an alternative NSPS which is more 

stringent than the applicable SIP standard. 

3-23 
P.53 

contain portions of two, three, or four States, average SIP's are calculated' 

for interstate AQCR's. Each State's SIP regulation is weighted by the fuel 

consumption within the State's geographical portion of the AQCR, and these 

weighted SIP's are averaged to estimate one interstate regulation. SIP 

values also are approximated for states in which SIP regulations vary by 

city or county, averaging period, form of specification, or boiler size 

class applicability. 

SIP's in IFCAM are classified among three boiler size categories: less 

than 100 MMBtu/hr, 100-250 MMBtu/hr, and greater than 250 MMBtu/hr. For 

each size class, the regulation in the SIP file is expressed as: 

E = a(X ) + c, where X is the boiler firing rate (MMBtu/hr heat input) and 

E is expressed in terms of lb/MMBtu. This form permits estimating the 

applicable regulation for a specific boiler size instead of using an average 

value. The SIP file in IFCAM is current as of July 1980 for PM and N0X 

emissions and is current as of March 1983 for SO2 emissions. 

3.6 POLLUTION CONTROL STRATEGIES 

To comply with air emission regulations, boiler owners assess control 

strategies based upon available fuels and pollution control equipment. The 

control strategy employed by boiler owners depends upon the amount of emission 

reduction required to meet applicable regulations. Boiler owners can choose 

to burn a fuel grade whose uncontrolled emissions rates are within the limits 

established by the standards or a particular fuel grade in combination with 

pollution control equipment as their control strategy. 

Many air emission control standards necessitate the use of pollution 

control technologies. Several options are available in IFCAM (see Table 3-6). 

3.6.1 Coal-Fired Boilers 

Control strategies in IFCAM for industrial coal-fired boilers include 

the use of one of nine coals, three types of FGD equipment, five types of 

particulate matter emissions collection equipment, and two types of N0X 

combustion modification. 

Combustion of a boiler's compliance coal type represents a control 

strategy when the coal-fired uncontrolled pollutant emissions are lower 

than the level allowed by emission regulations. Fuels associated with 

allowable emission rates without the application of pollution control 

equipment are referred to as compliance fuels. 

3-24 
TABLE 3-6. INDUSTRIAL BOILER POLLUTION CONTROL EQUIPMENT 

OPTIONS IN IFCAM 

Pollutant Technology 

SO2 Flue gas desulfurization 

Dual alkali 

Lime spray drying3 

Sodium once-through 

PM Single mechanical collector 

Dual mechanical collector 

Side stream separator 

Electrostatic precipitator 

Fabric filter 

N0X Combustion modification 

Low excess air 

Staged combustion air 

Combined SO2/PM emissions control system; includes a fabric filter. 

3-25 
P.55 

Tables 3-7 to 3-11 summarize the key characteristics of industrial' 

coal types in IFCAM. This wide array of coal grades has been included in 

IFCAM for two reasons. First, the range of coal grades in IFCAM reflects 

the wide range of grades available. Second, since SIP regulations for SO2 

emissions control vary significantly in stringency from one area to the 

next, the availability of numerous potential compliance coals in IFCAM should 

lead to a reasonable portrayal of compliance costs. 

Variability in SO2 emission rates exists when burning coal without a 

scrubber. This variability is due to many factors, including the lack of 

uniformity in coal seams (geological or natural factors), as well as coal 

mining, processing, cleaning, tranportation and storage practices which may 

result in some degree of "blending" or mixing. 

EPA has adopted a 30-day averaging period for determining compliance 

with SO2 NSPS from coal combustion. EPA believes that this is long enough 

to minimize variability (variability declines as the averaging period 

increases), in order to yield results that are representative of real 

performance, but which is also short enough to permit timely enforcement of 

compliance with standards after a source begins operation. 

EPA has estimated a ratio of about 1.20 between the once in a 10-year 

maximum expected 30-day rolling average SO2 NSPS emission ceiling and the 

p 

long-term (i.e., annual) average emission rate. This ratio is used in 

IFCAM to determine compliance coal types. If the annual average emission 

rate (see Table 3-7) times 1.20 is less than the 30-day rolling average SO2 

NSPS emission ceiling, then the coal type is a compliance coal type. 

One type of available equipment to control SO2 emissions is flue gas 

desulfurization (FGD), or scrubbers. The types of FGD systems in IFCAM are 

dual alkali, sodium once-through, and lime spray drying (including a fabric 

filter). The scrubber cost estimates are unique for each coal type and SO2 

emission regulation. Limits on SO2 emissions control efficiency for each 

FGD system are presented in Table 3-12. 

Variability in SO2 emissions also exists when burning coal with a 

scrubber. It has also been asserted that the variability of FGD outlet 

Q 

emissions can be higher than the variability of the inlet emissions. EPA 

has estimated that this variability factor is 1.30. 

If scrubbing is required on all new coal-fired boilers or if a coal 

type is not in compliance (and, therefore, a scrubber is required) with a 

3-26 
P.56 

TABLE 3-7. SULFUR DIOXIDE EMISSION RATES BY COAL TYPE3 

Coal Type 

Bituminous 

Subbituminous 

Ran 

ng/J 

<464 

464-718 

718-1,075 

1,075-1,432 

1,432-2,150 

>2,150 

<464 

464-718 

718-1,075 

ge 

(lb/MMBtu) 

(<1 

(1.08-

(1.67-

(2.50-

(3.33-

" (>5 

(<1 

(1.08-

(1.67-

08) 

-1.67) 

-2.50) 

-3.33) 

-5.00) 

00) 

08) 

-1.67) 

-2.50) 

ng/J 

408 

593 

894 

1,225 

1,784 

2,382 

408 

593 

894 

Average 

(lb/MMBtu) 

(0.95) 

(1.38) 

(2.08) 

(2.85) 

(4.15) 

(5.54) 

(0.95) 

(1.38) 

(2.08) 

ICF Incorporated. Average annual (not 30-day, rolling-average) values. 

3-27 
TABLE 3-8. AVERAGE ASH CONTENT BY REGION (BITUMINOUS COAL TYPES)' 

(percentage, moist) 

CO 

I 

ro 

CO 

Regi 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

on 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

<1.08 

11.9 

11.9 

11.8 

11.7 

11.0 

12.1 

10.0 

10.0 

11.3 

10.0 

1.08-1.67 

11.9 

11.9 

12.4 

12.3 

11.0 

11.8 

12.4 

10.0 

11.3 

10.0 

lb S0< 

1.67-2.50 

13.0 

11.4 

12.6 

12.3 

10.5 

15.0 

12.4 

10.0 

16.3 

10.0 

?/MMBtu 

2.50-3.33 

13.0 

13.0 

12.2 

11.9 

10.9 

11.8 

11.1 

-

-

-

3.33-5.00 

13.0 

13.0 

13.0 

11.9 

12.2 

12.2 

11.1 

-

-

-

>5.00 

13.0 

13.0 

13.0 

11.8 

12.0 

12.3 

11.1 

-

-

-

ICF Incorporated. 
P.58 

TABLE 3-9. AVERAGE ASH CONTENT BY REGION 

(SUBBITUMINOUS COAL TYPES)3 

(percentage, moist) 

Regi 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

on 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

<1.08 

-

-

-

6.9 

7.3 

6.0 

8.4 

7.3 

10.0 

lb S02/MMBtu 

1.08-1.67 

-

-

-

-

6.9 

7.3 

6.0 

6.9 

7.3 

10.0 

1.67-2.50 

-

-

-

-

6.9 

7.3 

6.0 

6.9 

7.3 

10.0 

ICF Incorporated. 

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TABLE 3-11. AVERAGE HEAT CONTENT BY REGION 

(SUBBITUMINOUS COAL TYPES)3 

J/g (MMBtu/short ton) 

P.60 

Region <1.08 

lb S02/MMBtu 

1.08-1.67 1.67-2.50 

1. New England 

2. New York/New Jersey 

3. Middle Atlantic 

4. South Atlantic 

5. 

6. 

7. 

8. 

9. 

0. 

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Southwest 

Central 

North Central 

West 

Northwest 

20.53 

(17.65) 

19.93 

(17.14) 

19.77 

(17.00) 

20.40 

(17.54) 

21.52 

(18.50) 

22.10 

(19.00) 

20.53 

(17.65) 

19.93 

(17.14) 

19.77 

(17.00) 

20.05 

(17.24) 

21.52 

(18.50) 

22.10 

(19.00) 

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. 

3-31 
P.61 

TABLE 3-12. FGD TECHNOLOGY CONSTRAINTS IN IFCAM3 

Technology Limits 

Dual alkali 

Lime spray drying 

Sodium once-through 

90 percent removal of uncontrolled 

SO2 emissions for all coal types 

90 percent removal of uncontrolled 

SO2 emissions for low sulfur coal 

types (less than 1.67 lb S02/MMBtu 

annual average); not applicable to 

higher sulfur coal types regardless 

of the required sulfur removal rate 

90 percent removal of uncontrolled 

SO2 emissions for all coal types 

U.S. Environmental Protection Agency. 

'30-day, rolling-average basis. 

3-32 
P.62 

SIP or an alternative Federal SO2 emissions standard, the annual average 

controlled SO2 emissions rate is calculated as follows: 

• Example 1 

- Uncontrolled annual average emission rate is 5.54 lb SO2/ 

MMBtu 

- Ninety percent SO2 emissions removal required (30-day, 

rolling-average) 

5.54 x (l-0.9)/1.3 = 0.426 lb S02/MMBtu (annual average) 

controlled emission rate 

• Example 2 

- Uncontrolled annual average emission rate is 2.85 lb SO2/ 

MMBtu 

- Seventy to ninety percent SO2 emissions removal required 

with a 0.6 lb S02/MMBtu (30-day, rolling-average) emissions 

"floor." 2.85 x (1-0.9) = 0.285. Since 0.285 is less than 

0.6, percentage removal rate will be less than 90 percent. 

(2.85 - 0.6)/2.85 = 0.789, or 78.9 percent. Since 78.9 

percent is greater than 70 percent, 0.6/1.3 = 0.4615 lb SO2/ 

MMBtu (annual average) controlled emission rate. 

• Example 3: 

- Uncontrolled annual average emission rate is 0.95 lb SO2/ 

MMBtu 

- Seventy to ninety percent SO2 emissions removal required 

with a 0.6 lb S02/MMBtu (30-day, rolling-average) emissions 

"floor." 0.95 x (1-0.9) = 0.095. Since 0.095 is less than 

0.6, percentage removal rate will be less than 90 percent. 

(0.95 - 0.6)/0.95 = 0.368, or 36.8 percent. Minimum SO2 

removal rate is 70 percent. 0.95 (1 - 0.7) = 0.285. 

0.285/1.3 = 0.219 lb S02/MMBtu (annual average) controlled 

emission rate. 

If the applicable regulation requires SO2 emission reductions in coalfired boilers (as in the three examples shown above), then the level of SO2 

emissions is adjusted as follows: 

3-33 
P.63 

Adjusted SO2 emissions rate = (R x S) + (1-R) x A 

where S = estimated controlled annual average SO2 emission rate 

R = scrubber reliability factor (fraction)* 

A = uncontrolled SO2 emissions rate from natural gas 

combustion (backup fuel) 

This calculation assumes a reliability factor for scrubbers and a low sulfur 

fuel standby option in the event of pollution control equipment malfunction. 

Uncontrolled PM emission rate estimates are a function of the ash content 

and heating value of the coal and the type of combustion: 

• Underfeed stoker, flyash = 25 percent of the total ash content of 

the coal 

• Spreader stoker, flyash = 65 percent of the total ash content of 

the coal 

• Pulverized coal, flyash = 80 percent of the total ash content of 

the coal 

The balance is bottom ash. 

Seven PM emissions control technologies are available in IFCAM for 

industrial coal-fired boilers. Technical limits on pollution control 

efficiency for each are listed in Table 3-13. 

The controlled PM emission rate estimates for new industrial coalfired boilers are estimated to be equal to "B" times the applicable PM 

emission regulation. The factor, B, varies by control technology: 

• Single mechanical collector: B = 1.5 

• Dual mechanical collector: B = 1.2 

• Side stream separator: B = 0.8 

• Electrostatic precipitator: B = 0.6 

For a fabric filter, the controlled PM emission rate estimate is a constant, 

0.6 x 21 ng/J (0.05 lb/MMBtu) = 13 ng/J (0.03 lb/MMBtu). 

*0.95 for dual alkali and sodium once-through FGD systems; 0.90 for lime 

spray drying scrubbers. 

3-34 
P.64 

TABLE 3-13. PM EMISSIONS POLLUTION CONTROL TECHNOLOGY 

CONSTRAINTS IN IFCAM3 

Technology 

Minimum PM 

emission standard 

Single mechanical collector 

Stoker/bituminous 

Stoker/subbituminous 

Pulverized/all 

Dual mechanical collector 

Stoker/bituminous 

Stoker/subbituminous 

Pulverized/all 

Side stream separator 

Stoker/bituminous 

Stoker/subbituminous 

Pulverized/all 

Electrostatic precipitator 

Fabric filter 

Lime spray drying FGD 

Dual alkali FGD/single 

mechanical collector 

High sulfur coal (>3.5 lb S02/MMBtu) 

Other coal types (<3.5 lb S02/MMBtu) 

172 ng/J (0.40 lb/MMBtu) 

344 ng/J (0.80 lb/MMBtu) 

430 ng/J (1.00 lb/MMBtu) 

129 ng/J (0.30 lb/MMBtu) 

258 ng/J (0.60 lb/MMBtu) 

344 ng/J (0.80 lb/MMBtu) 

64 ng/J (0.15 lb/MMBtu) 

129 ng/J (0.30 lb/MMBtu) 

172 ng/J (0.40 lb/MMBtu) 

21 ng/J (0.05 lb/MMBtu) 

21 ng/J (0.05 lb/MMBtu) 

21 ng/J (0.05 lb/MMBtu) 

129 ng/J (0.30 lb/MMBtu) 

42 ng/J (0.10 lb/MMBtu) 

U.S. Environmental Protection Agency, 

'includes a fabric filter. 

3-35 
P.65 

N0X emissions control strategies in IFCAM include two types of 

combustion modifications: low excess air and staged combustion air. Table 

3-14 summarizes the expected N0X emission reductions. 

3.6.2 Oil/Gas Boilers 

Control strategies in IFCAM for industrial residual fuel oil-fired 

boilers include the use of a compliance oil type, a dual alkali or sodium 

once-through FGD system, an electrostatic precipitator for particulate 

emissions control, and low excess air and staged combustion air for N0X 

emissions control. Low excess air is the only pollution control technology 

in IFCAM for control of natural gas and distillate fuel oil emissions since 

boilers firing these fuels emit insignificant levels of SO2 and PM (see 

Table 3-15). Table 3-16 summarizes the potential N0X emission reduction 

estimates in IFCAM for new industrial boilers burning natural gas or fuel 

oil. 

3.6.3 Summary 

Table 3-17 presents an example of the number of pollution control 

compliance alternatives in IFCAM. Uncontrolled air emission rates (see 

Tables 3-7, 3-14, 3-15, and 3-16), SIP's, applicable NSPS (see Table 3-5), 

and pollution control equipment technical capabilities (see Tables 3-12, 

3-13, 3-14, and 3-16) are compared and feasible alternatives are identified. 

Table 3-17 shows that as many as five pollution control strategies are 

available for a single fuel type. Consider medium sulfur bituminous coal 

in this example. Pollution control alternatives include: 

• DA/SMC and SCA 

• DA FGD, ESP, and SCA 

• DA FGD, FF, and SCA 

• NaTH FGD, ESP, and SCA 

• NaTH FGD, FF, and SCA 

The number of pollution control alternatives is not constant. It varies 

with the boiler size, fuel type, and environmental regulations. 

The example shown in Table 3-17 indicates that IFCAM compares costs 

for a large number of fuel type/pollution control equipment configurations. 

3-36 
P.66 

TABLE 3-14. NO EMISSION RATE ESTIMATES FOR 

NEW INDUSTRIAL COAL-FIRED BOILERS6 

Uncontrolled 

emission rate 

Controlled 

emission rate 

Control 

ng/J (lb/MMBtu) ng/J (lb/MMBtu) technology 

Underfeed stoker 172 

Spreader stoker 275 

Pulverized coal 387 

(0.40) 

(0.64) 

(0.90) 

138 

215 

249 

(0.32) 

(0.50) 

(0.58) 

Low excess air 

Low excess air 

Staged combustion 

air 

U.S. Environmental Protection Agency. 

3-37 
P.67 

TABLE 3-15. UNCONTROLLED INDUSTRIAL OIL/GAS BOILER SO- AND PM 

EMISSION RATE ESTIMATES

 L 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

3.0 percent S 

1.6 percent S 

0.8 percent S 

0.3 percent S 

ng/J (lb/MMBtu) 

so2 

0.26 (0.0006) 

219 (0.51) 

1380 (3.21) 

735 (1.71) 

344 (0.80) 

138 (0.32) 

PM 

4 (0.01) 

6 (0.0144) 

99 (0.23) 

56 (0.13) 

34 (0.08) 

17 (0.04) 

3-38 
TABLE 3-16. NOv EMISSION RATE ESTIMATES FOR NEW INDUSTRIAL OIL/GAS BOILERS' 

A 

Fuel type 

Natural 

gas 

Boiler 

» MW 

<44 

44-73 

>73 

<44 

44-73 

Distillate <44 

co fuel oil 44-73 

co >73 

<44 

44-73 

Residual 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

fuel oil 

(0.44% N) 

(0.23% N) 

(0.12% N) 

(0.04% N) 

size class 

(MMBtu/hr) 

(<150) 

(150-250) 

(>250) 

(<150) 

(150-250) 

(<150) 

(150-250) 

(>250) 

(<150) 

(150-250) 

all 

all 

all 

all 

Annual 

capacity 

utilization rate 

(percent) 

>65 

>45 

all 

<65 

<45 

>65 

>45 

all 

<65 

<45 

all 

all 

all 

all 

Preheat 

temperatures 

400°F 

400°F 

400°F 

100°F 

100°F 

400°F 

400°F 

400°F 

100°F 

100°F 

400°F 

400°F 

400 °F 

400°F 

Uncontrolled 

annual 

average NO 

emission 

rate ng/J 

(lb/MMBtu) 

112 

112 

112 

64 

64 

107 

107 

107 

77 

77 

196 

131 

97 

75 

(0.26) 

(0.26) 

(0.26) 

(0.15) 

(0.15) 

(0.25) 

(0.25) 

(0.25) 

(0.18) 

(0.18) 

(0.455) 

(0.305) 

(0.225) 

(0.175) 

Controlled 

annual 

average NO 

emission

 x 

rate ng/J 

(lb/MMBtu) 

82 

82 

82 

52 

52 

75 

75 

75 

52 

52 

105 

95 

84 

62 

(0.19) 

(0.19) 

(0.19) 

(0.12) 

(0.12) 

(0.175) 

(0.175) 

(0.175) 

(0.12) 

(0.12) 

(0.245) 

(0.22) 

(0.195) 

(0.145) 

NO control 

A 

technology 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Low excess air 

Staged combustion 

a 1 r 

Staged combustion 

a I r 

Low excess air 

Low excess air 

U.S. Environmental Protection Agency. 
P.69 

TABLE 3-17. POLLUTION CONTROL COMPLIANCE ALTERNATIVES IN IFCAM a t 

Fuel type Pollution control equipment 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

3.0% S 

1.6% S 

0.8% S 

0.3% S 

Coal, bituminous 

(lb S02/MMBtu) 

< 1.08 

1.08-1.67° 

1.67-2.50 

2.50-3.33 

3.33-5.00 

> 5.00 

Coal, subbituminous 

(lb S02/MMBtu) 

< 1.08 

1.08-1.67° 

1.67-2.50 

Low excess air 

Low excess air 

N.A.k 

N.A.b 

Low excess air 

None required 

ESP or FF; SCA 

LSD FGD; DA or NaTH FGD with FF or ESP; DA/SMC; SCA 

DA or NaTH FGD with FF or ESP; DA/SMC; SCA 

DA or NaTH FGD with FF or ESP; DA/SMC; SCA 

DA or NaTH FGD with FF or ESP; SCA 

DA or NaTH FGD with FF or ESP; SCA 

ESP or FF* SCA 

LSD FGD; DA or NaTH FGD with FF or ESP; DA/SMC; SCA 

DA or NaTH FDG with FF or ESP; DA/SMC; SCA 

ESP - electrostatic 

precipitator 

FF - fabric filter 

SMC - single mechanical 

collector 

SCA - staged combustion 

air 

LSD - lime spray drying 

DA - dual alkali 

NaTH - sodium once-through 

Assumes a new boiler larger than 73 MW (250 MMBtu/hr) subject to the current 

NSPS (see Table 3-5). 

5Not applicable. Not in compliance with the current N0X NSPS, 86 ng/J 

(0.2 lb/MMBtu). See Tables 3-5 and 3-16. 

'See Table 3-7. The annual average SO2 emission rate for this coal type, 

593 ng/J (1.38 lb/MMBtu), exceeds the current NSPS and scrubbers are required. 

3-40 
P.70 

REFERENCES 

1. Energy Consumption Data Base. Energy and Environmental Analysis, Inc. 

Arlington, Virginia. Prepared for the Federal Energy Administration. 

June 1977. 

End-Use Energy Consumption Data Base: Series 1 Tables. U.S. Department 

of Energy, Energy Information Administration. DOE/EIA-0014. June 1978. 

2. Bell, A.W., and B.P. Breen. Converting Gas Boilers to Oil and Coal. 

Chemical Engineering. 83(9):93-101. April 26, 1976. 

Burke, J.M., and M.D. Matson. Industrial Boilers Fuel Switching Methods, 

Costs, and Environmental Impacts. Radian Corp. Austin, Texas. EPA450/3-78-123. Prepared for the Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency. December 1978. 

Bogot, A., and R.C. Sherrill. Principal Aspects of Converting Steam 

Generators Back to Coal Firing. Combustion Engineering, Inc. Windsor, 

Connecticut. Publication No. TIS-4588. Presented at the NCA/BCR Coal 

Conference and Expo II. Louisville. October 21-23, 1975. 

Cross, F.L. Pragmatic Approach to Industrial Boiler Conversion to Coal. 

Presented at the Fifth Energy Technology Conference. Washington, D.C. 

February 27-March 1, 1978. 

Feeley, F.G. Energy Conversion Problems from the Industrial Users 

Viewpoint. 01 in Corp. Presented at the Fourth Energy Technology 

Conference. Washington, D.C. March 14-16, 1977. 

Llinares, V. Using Coal for Steam and Power Generation in Industrial 

Boilers. Combustion Engineering, Inc. Publication No. TIS-5405. 

Presented at the Manufacturing Chemists Association Energy Seminar. 

Washington, D.C. September 28-29, 1977. 

3-41 
P.71 

Marshall, R.W. Boiler Conversion - An Effective Pollution Control.' ' 

Iron and Steel Engineer. 50:59-64. January 1973. 

Schweiger, R.G. Should You Convert to Coal? Power. 120:38-41. July 

1976. 

Siebold, P.F., and R.D. Bessette. Latest Equipment and Design for New 

Coal-Fired Plants and the Conversion of Existing Plants to Coal Firing. 

Riley Stoker Corp. Worchester, Massachusetts. Presented at the 

Industrial Fuel Conference. Purdue U., Lafayette. October 6-7, 1976. 

Also presented at the Kentucky Industrial Coal Conference. April 26-27, 

1978. 

3. Industrial Sector Technology Use Model (ISTUM): Industrial Energy Use 

in the United States, 1974-2000. Energy and Environmental Analysis, 

Inc. Arlington, Virginia. DOE/FE/2344-1. Prepared for the U.S. 

Department of Energy. October 1979. pp. IV-101 to IV-114 and VI-26 to 

VI-33. 

4. Devitt, T., P. Spaite, and L. Gibbs. Population and Characteristics of 

Industrial/Commercial Boilers in the U.S. PEDCo Environmental, Inc. 

Cincinnati, Ohio. EPA-600/7-79-178a. Prepared for the U.S. Environmental Protection Agency. August 1979. p. 462. 

5. Fossil Fuel Demand for Stationary - Source Combustion and Other Selected 

Data for Each State and Air Quality Control Region. The Mitre Corp. 

April 1975. Fuel mix by AQCR is based upon 1971 data from a Battelle 

Columbus study performed for EPA. 

6. Summary of Regulatory Analysis New Source Performance Standards: 

Industrial-Commercial-Institutional Steam Generating Units of Greater 

Than 100 Million Btu/hr Heat Input. U.S. Environmental Protection Agency, 

Office of Air Quality Planning and Standards. Draft. March 1985. 

7. Reference 6, pp. 41, 42. 

8. Reference 6, pp. 51, 52. 

9. A Statistical Study of Coal Sulfur Variability and Related Factors. 

Foster Associates, Inc. Washington, D.C. Prepared for the U.S. 

Environmental Protection Agency. Draft. July 27, 1979. p. ix. 

3-42 
P.72 

FUEL CHOICE DECISIONS 

This section summarizes the fuel choice decision criteria in IFCAM. 

Given the industrial boiler characteristics reviewed in Section 3, cost 

estimates are generated and compared for each boiler in the population. 

The fuel type with the lowest expected life cycle costs is selected. 

This section is organized in two parts. First, capital and annual 

non-fuel operating and maintenance (O&M) and fuel costs are discussed. 

Second, the fuel choice decision framework is described. 

4.1 COST COMPONENTS 

4.1.1 Capital and Annual Non-Fuel O&M Costs 

The major components of new industrial boiler capital costs are: 

t Equipment 

- Boiler 

- Auxiliary equipment such as instrumentation, pumps, fuel 

handling, waste disposal, water treatment 

- Pollution control 

- Monitoring 

t Direct installation 

• Indirect installation 

- Engineering 

- Construction fees 

- Start-up 

• Land 

• Other 

- Interest during construction 

- Contingencies 

- Working capital 

4-1 
P.73 

The annual non-fuel O&M cost components are: 

• Labor 

• Materials, supplies, and spare parts 

• Chemicals 

• Utilities (i.e., electricity and water) 

t Steam 

• Solid waste disposal and water treatment 

• Overhead 

t General and administrative costs, local property taxes, and 

insurance 

• Interest on working capital 

• Monitoring, reporting, and malfunction expenses 

The capital and annual non-fuel O&M cost estimates are generic in that 

they do not vary with respect to special site-specific conditions. They 

are assumed to be representative of budget estimates used for planning 

purposes. It is also assumed that these costs will not increase in real 

terms over time or vary by region. 

The capital and annual non-fuel O&M cost estimates for new industrial 

coal-fired boilers are unique for each coal type (the cost estimates are a 

function of the heating value of the coal type) and type of combustion 

(underfeed stoker, spreader stoker, or pulverized coal). The capital and 

annual non-fuel O&M cost estimates for new oil/gas watertube boilers 

(excluding pollution control equipment) do not vary substantially by fuel 

type (natural gas or residual fuel oil) because these units are assumed to 

have dual-fuel firing capability. 

The FGD system cost estimates are a function of: 

• The boiler flue gas flow rate and fuel firing rate 

• The sulfur content and heating value of the fuel type 

• The required SO2 emissions removal efficiency 

These cost estimates indicate that the scrubber costs have economies of 

scale related to the sulfur content of the fuel and the required SO2 emissions 

removal efficiency. With respect to scrubber capital costs, however, EPA 

is assuming that the cost estimates used in IFCAM should be based on high 

sulfur fuel types with high (90 percent) SO2 emissions removal efficiencies. 

This assumption reflects industry practice of designing FGD systems to achieve 

4-2 
'90 percent SO2 emissions reduction in order to provide maximum fuel firing 

flexibility even though the scrubber may be operated at lower efficiency. 

The scrubber O&M cost estimates do reflect economies of scale associated 

with the sulfur content of the coal and the actual operating efficiency. 

The minimum scrubber operating efficiency rate is 50 percent SO2 emissions 

reduction. All of the boiler flue gas is scrubbed (regardless of the scrubber 

operating efficiency); it is not assumed that a portion of the boiler flue 

gas bypasses the scrubber when the scrubber is in operation. 

The cost estimates for particulate matter emissions control equipment 

do not vary significantly by coal type or PM emissions regulation. 

Boiler efficiency is improved with the use of low excess air (a N0X 

emissions control technique) because less air is heated to flue gas 

temperatures. This is reflected in the low excess air O&M cost estimates 

expressed as a negative expense (boiler fuel input savings). 

These boiler and pollution control equipment cost estimates have been 

developed by several EPA contractors. Cost estimates were developed for 

several model boilers. Cost algorithms were developed based on these generic 

point estimates. Radian Corporation (Research Triangle Park, NC) is currently 

responsible for documenting and revising these cost algorithms for EPA's 

2 

industrial boiler NSPS analysis. 

4.1.2 Fuel Costs 

Projected fuel costs significantly affect fuel choice decisions for 

new industrial boilers because they contribute a large share of total life 

cycle costs. For example, coal will be selected only if fuel cost savings 

will be sufficient to offset the relatively higher capital and operating 

costs associated with coal utilization. 

IFCAM includes the following fuel types: 

• Natural gas 

• Distillate fuel oil 

t Residual fuel oil 

- 3.0 percent sulfur 

- 1.6 percent sulfur 

- 0.8 percent sulfur 

- 0.3 percent sulfur 

4-3 
P.75 

• Coal 

- Six bituminous sulfur content classes 

- Three subbituminous sulfur content classes 

The major characteristics of the nine coal types in IFCAM (Btu and ash 

content) vary by region (see Tables 3-8 through 3-11). 

Projected fuel prices are expected to increase in real terms over time 

and to vary by region (but not to vary within a Federal region).* Fuel 

price forecasts selected by EPA for use in the industrial boiler NSPS 

analysis have been based on published DOE forecasts (i.e., EIA's Annual 

Energy Outlook or the biennial National Energy Policy Plan forecasts 

prepared by the Office of Policy, Planning and Analysis) or projections 

prepared by EPA contractors. 

4.2 INVESTMENT DECISION APPROACH 

4.2.1 Decision Criteria 

The fuel choice decision framework in IFCAM is based on the premise 

that industry will try to minimize the total costs of generating steam or 

heat over the useful life of the facility. Specifically, decision-makers 

will tend to select that fuel with the lowest after-tax net present value 

(NPV) of the total projected cash outflows for operating, maintenance, 

fuel, and capital costs over the investment period. 

For a given set of projected fuel prices and government policies 

(energy, environmental, and tax), IFCAM selects the least-cost fuel type 

for each boiler record by: 

1) Estimating the capital and annual non-fuel O&M costs for each 

fuel type 

2) Estimating the capital and annual non-fuel O&M costs for 

applicable pollution control equipment options for each fuel 

type 

*Intra-regional variability is simulated in IFCAM by assigning SIP's at the 

AQCR level (not using regional "average" SIP's). 

4-4 
3) For each combination of fuel type and alternative pollution 

control equipment configuration,* the after-tax NPV of total 

boiler and pollution control equipment capital and annual nonfuel O&M costs is calculated 

4) The after-tax NPV of projected fuel costs is derived and added 

to the total after-tax NPV of the boiler and pollution control 

equipment capital and annual non-fuel O&M costs for each fuel 

type/pollution control equipment configuration 

5) The total after-tax NPV (capital, O&M and fuel) is compared for 

each fuel type/pollution control equipment configuration and the 

alternative with the lowest total after-tax NPV is selected 

These steps have been modified in the past to model special government 

policies. For example, the Economic Regulatory.Administration of the U.S. 

Department of Energy proposed procedures to determine if the cost of burning 

coal substantially exceeded the cost of burning oil in new large industrial 

3 

boilers in accordance with the Powerplant and Industrial Fuel Use Act. 

This cost test can be included in the fuel choice decision logic in IFCAM. 

Life cycle costs are compared in IFCAM on an after-tax basis because 

Federal tax laws are different for oil/gas boilers than they are for coal 

units. The Energy Tax Act of 1978 (Title III) provided tax incentives for 

the use of coal and alternative fuels. New industrial coal-fired boiler 

investments qualify for the regular 10 percent investment tax credit (ITC) 

and accelerated depreciation methods. However, investments in new industrial 

oil- and gas-fired boilers do not qualify for the regular ITC and straight 

line depreciation is required for these units. 

4.2.2 Overview of NPV Calculations 

A conventional NPV approach is used to calculate the total after-tax 

cost of producing steam or hot water in a boiler. The components of this 

calculation include: 

*For example, three FGD systems or several particulate matter emissions 

control equipment alternatives for new industrial coal-fired boilers. 

4-5 
P.77 

FCt - the fuel cost in year t 

OM. - the annual non-fuel operating costs in year t 

C - the total capital cost of the facility 

Ct - the capital cost expended in year t 

D. - depreciation expense on capital in year t 

e - the share of capital cost which can be expensed 

(does not form the basis for capital depreciation) 

T - the marginal income tax rate (e.g., 0.5) 

ITC - the allowable investment tax credit (e.g., 0.1) 

i - the real, after-tax discount rate (e.g., 0.08) 

L - the investment period (years) 

After-tax NPV = y (l-T)(-FCt-OMt-Dt-eC) + Dt -(l-e)C, + (l-e)(Ct)(ITC) 

t=l (l+i)t _ 1 

Expensible Construction Costs 

A portion (10 percent) of equipment and facility construction costs is 

considered expensible in IFCAM. These expensible costs, allowable deductions 

for income tax purposes, are excluded from the depreciable capital cost. 

Expensible costs normally are higher than initial engineering costs. They 

can vary for each case depending on the amount of work done in-house and 

the portion of turnkey costs (i.e., total package delivered to the fuel 

user). The estimate that 10 percent of construction costs are expensible 

is assumed to be typical, based on discussions with equipment vendors. It 

is also assumed to be expensed in the first year. 

4-6 
I 

Construction Period 

This period refers to the interval when capital expenditures are being 

incurred for facility construction, and no fuel is being burned. This period 

is assumed to be two years. Dt=FCt=0Mt=0, for t=l,2. Ct=0, for t 

greater than 2. 

Depreciation 

Depreciation is an accounting convention which represents the decline 

in property value as a result of time and/or use. This is important in the 

calculation of income tax liabilities. Industrial boilers are depreciable 

property. 

The Energy Tax Act of 1978 permits investments in new industrial coalfired boilers to be depreciated using accelerated methods while requiring 

investments in new oil/gas industrial boilers to be depreciated using a 

4 

straight line method. The Economic Recovery Tax Act of 1981 established 

the accelerated cost recovery system (ACRS) for property placed in service 

after 1980. The annual recovery percentages were revised by the Tax Equity 

and Fiscal Responsibility Act of 1982. Industrial boilers are five-year 

recovery property. 

In this analysis, the annual depreciation charges must be converted 

5 

from nominal to real dollars. 

Investment Tax Credit (ITC) 

The ITC rate is distinguished by fuel type in order to analyze specific 

policy options related to different fuel types. The Energy Tax Act of 1978 

provides several tax incentives for the use of coal and alternative fuels. 

This legislation authorizes an additional 10 percent business energy investment 

tax credit for coal and alternative fuel investments made between October 

1, 1978 and December 31, 1982 for the following: 

• Boilers and other combustors 

• Equipment to produce alternative fuels 

t Pollution control equipment 

• Fuel handling and storage equipment 

However, since authorization expires in 1982 for coal-related property, the 

additional alternative energy property ITC is not modeled for new industrial 

boilers installed after 1983. 

4-7 
P.79 

New coal investments qualify for the regular 10 percent ITC, and 

investments in new oil/gas boilers are denied the regular ITC. The Tax 

Equity and Fiscal Responsibility Act (TEFRA) of 1982 provides two options: 

• Take a reduced ITC (8 percent for five-year recovery property 

placed in service after 1980) with no adjustment for the 

depreciation basis or 

• Take the regular ITC (10 percent for five-year recovery property 

placed in service after 1980) and reduce the basis for 

depreciation by 50 percent of the amount of the credit taken 

Since new industrial oil/gas boilers are denied the ITC, these TEFRA 

Federal tax code revisions apply only to new industrial coal-fired boiler 

investments in IFCAM. These TEFRA Federal tax code revisions have not yet 

been incorporated into IFCAM. 

Income Tax Rate 

A tax rate of 50 percent is used to reflect the marginal corporate 

Federal and State income tax rate for investment decisions. This assumes 

that corporations' earnings are sufficient to make this maximum tax rate 

relevant for fuel choice decisions. 

Discount Rate 

A discount rate is the expression of the time value of capital used in 

equivalence calculations comparing alternatives. This rate is essentially 

a value judgement based on a compromise between present consumption (i.e., 

distribution of profits to stockholders) and capital formation. The 

discount rate represents the required rate of return; that rate at which 

stockholders are indifferent between this and their next best investment 

opportunity. Traditionally, the required rate of return simply has meant 

the cost of capital. If an investment does not pay for itself plus the 

charges incurred to finance the project, a firm is better off not making 

the investment. 

The discount rate in IFCAM represents the average real (not nominal) 

after-tax cost of capital. The discount rate for new industrial boiler 

investment calculations in IFCAM is 8 percent. 

4-8 
I 

Investment Period 

The investment period is the number of years of cash flows included in 

the calculation of the after-tax NPV. The length of the investment period 

is important in that it affects the relative economics of capital-intensive 

alternatives such as coal. If the investment period is short (e.g., five 

years), the fuel savings associated with coal may not be sufficient to offset 

the high coal capital and annual non-fuel O&M costs and oil or gas would be 

selected as the least-cost fuel type. If a long period is used (e.g., 25-40 

years), the coal fuel cost savings may be sufficient in many cases to offset 

the high coal capital and annual non-fuel O&M costs. 

The current investment period in IFCAM is 15 years. This includes the 

two-year construction period and 13 years of operation. Estimates of the 

physical life of new industrial boilers range from 20 years for package 

units to 45 years for large field erected units. Due to the discounted 

cash flow decision criteria, depreciation costs and annual O&M and fuel 

expenses contribute relatively little to the total NPV for periods longer 

than 15 years. Therefore, a single investment period for all boiler fuel 

choice decisions is not expected to seriously bias the analysis. 

4.2.3 Calculation of NPV Factors 

Table 4-1 summarizes the financial parameters used in IFCAM's new 

industrial boiler cost comparisons. Tables 4-2 and 4-3 show how after-tax 

NPV factors for capital expenses are derived. For every dollar of coal 

boiler capital costs, the after-tax NPV is 52.61 cents.* For every dollar 

of oil/gas boiler capital costs, the after-tax NPV is 62.65 cents. The 

oil/gas boiler capital factor is larger than the coal boiler capital factor 

because current Federal tax laws promote the use of coal and alternative 

fuels. 

Table 4-4 indicates that the after-tax NPV is $3,659 for every dollar 

of annual non-fuel O&M costs. Table 4-5 presents a similar calculation for 

fuel costs. In this example, the after-tax NPV for fuel costs is 

$23.72/MMBtu x the boiler annual natural gas consumption quantity. 

*55.83 cents when TEFRA Federal tax code revisions are incorporated into 

IFCAM in the future. 

4-9 
P.81 

TABLE 4-1. FINANCIAL PARAMETER ASSUMPTIONS FOR NEW INDUSTRIAL BOILER ' 

DISCOUNTED AFTER-TAX NPV COST COMPARISONS 

Financial parameter Coal Oil/Gas 

Investment period (years) 15 15 

Depreciation method 

Depreciation period (years) 

Investment tax credit (percent) 

Business energy tax credit (percent) 

Income tax rate - Federal and State (percent) 

After-tax, real discount rate (percent) 

Inflation rate (percent) 

Construction period (years) 

Accelerated Cost Recovery System. As defined by the Economic Recovery 

Tax Act of 1981 for property acquired after 1985, the annual recovery 

percentages are 20, 32, 24, 16, and 8 respectively. The Tax Equity and 

Fiscal Responsibility Act of 1982, which has not yet been incorporated 

into IFCAM, revised the annual recovery percentages for property acquired 

after 1985: 15, 22, 21, 21 and 21 percent respectively. 

The Energy Tax Act of 1978 indefinitely excludes new oil- and gas-fired 

industrial boilers from any ITC and restricts these boilers to straight 

line depreciation. 

r 

As defined by the Economic Recovery Tax Act of 1981. 

The alternative energy property investment tax credit for new coal boiler 

investments (authorized by the Energy Tax Act of 1978) expired on 

December 31, 1982 and, therefore, is not applicable to new industrial 

boilers ordered after 1985. 

eUsed to convert depreciation charges from nominal to real dollars. 

Included in the investment period. 

ACRS3 

5

C 

10 

o

d 

50 

8 

5 

2 

Strai ght line 

5

C 

0

b 

0 

50 

8 

5 

2 

4-10 
TABLE 4-2. DERIVATION OF THE AFTER TAX NPV FACTOR FOR 

COAL BOILER CAPITAL EXPENSES* 

Depreciable 

Deprecia- Expensible capital Discounted 

Year tionD construction0 investment^ ITCe Cash flow^ cash flow9 

l 0.0500 h 

2h 

3 

4 

5 

6 

7 

(0.0857) 

(0.1306) 

(0.0933) 

(0.0592) 

(0.0282) 

0.4500 

0.4500 

(0.0450) 

(0.0450) 

0.4550 

0.4050 

(0.0857) 

(0.1306) 

(0.0933) 

(0.0592) 

(0.0282) 

0.4550 

0.3750 

(0.0735) 

(0.0735) 

(0.0686) 

(0.0403) 

(0.0178) 

0.5261 

3Total capital cost is 1.0. 

Only 90 percent of the capital cost is assumed to be depreciable. Nominal 

depreciation charges are adjusted for inflation to derive annual real 

depreciation credits. The annual recovery factors (ARF), not including 

TEFRA provisions, are 0.20, 0.32, 0.24, 0.16, and 0.08 respectively for 

i = 1-5. Depreciation credits = ((1-tax rate) x D-j) - D-j, or - D-j/2 for 

i = 1-5. Di = 0.9 x ARF1/(1.05)1 for i = 1-5. 

c(l-tax rate) x 10 percent of the total capital cost = 0.5 x 0.1 x 1.0 = 

0.05. 

Total capital cost less expensible construction costs allocated evenly 

over the two-year construction period, or (1.0-(0.1 x 1.0))/2 = 0.45. 

investment Tax Credit (ITC) is 10 percent of the depreciable capital cost. 

f 

Sum of depreciation, expensible construction, depreciable captial 

investment and ITC. 

gCash flowt/(1.08)t_1. 

i_ 

Construction period. Boiler is placed in service at the beginning of 

year 3. 

4-11 
P.83 

TABLE 4-3. DERIVATION OF THE AFTER-TAX NPV FACTOR FOR 

-a OIL/GAS BOILER CAPITAL EXPENSES' 

Depreciable 

. Expensible capital , Discounted 

Year Depreciation construction investment Cash flow cash flow 

19 

29 

3 

4 

5 

6 

7 

(0.0857) 

(0.0816) 

(0.0777) 

(0.0740) 

(0.0705) 

0.0500 0.4500 

0.4500 

0.5000 

0.4500 

(0.0857) 

(0.0816) 

(0.0777) 

(0.0740) 

(0.0705) 

0.5000 

0.4167 

(0.0735) 

(0.0648) 

(0.0571) 

(0.0504) 

(0.0444) 

0.6265 

3Total capital cost is 1.0. Regular ITC is excluded by the Energy Tax Act. 

Only 90 percent of the capital cost is assumed to be depreciable. Nominal 

depreciation charges are adjusted for inflation to derive annual real 

depreciation credits. Straight line depreciation (20 percent per year for 

5 years) is assumed. Depreciation credits.= ([1-tax rate] x D.) - D., or 

- D./2 for i = 1-5. D. = 0.9 x 0.2/(1.05r for i = 1-5.

 n n 

c(l-tax rate) x 10 percent of the total capital cost = 0.5 x 0.1 x 1.0 = 

0.05. 

Total capital cost less expensible construction costs allocated evenly 

over the two-year construction period, or (1.0 - [0.1 x 1.0])/2 = 0.45. 

eSum of depreciation, expensible construction, and depreciable capital 

investment. 

fCash flowt/(1.08)t_1. 

9construction period. Boiler is placed in service at the beginning of 

year 3. 

4-12 
I ' 

TABLE 4-4. DERIVATION OF THE AFTER-TAX NPV FACTOR FOR 

ANNUAL NON-FUEL O&M EXPENSES3 

~ Discounted 

Year Cash flow cash flow 

l

d 0.0 0.000 

2

d 0.0 0.000 

3 0.5 0.428 

4 0.5 0.397 

5 0.5 0.368 

6 0.5 0.340 

7 0.5 0.315 

8 0.5 0.292 

9 0.5 0.270 

10 0.5 0.250 

11 0.5 0.232 

12 0.5 0.214 

13 0.5 0.199 

14 0.5 0.184 

15 0.5 0.170 

3.659 

a Annual non-fuel O&M costs =1.0 for years 3 through 15, 

= 0.0 for years 1 and 2 (construction period) 

Annual non-fuel O&M costs are assumed not to increase in real terms over 

time. 

(1-tax rate) x annual non-fuel O&M cost = 0.5 x 1.0 = 0.5. 

cCash flowed.08)t_1 . 

Construction period. Boiler is placed in service at the beginning of 

year 3. 

4-13 
Year 

l

d 

2

d 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

3See Table 

Presented 

in IFCAM. 

cAfter-tax 

Construct 

year 3. 

TABLE 4-5. EXAMPLE CALCULATION OF THE 

NPV OF ANNUAL FUEL EXPENSES 

After-tax discounted 

cash flow factor3 

0.000d 

0.000d 

0.428 

0.397 

0.368 

0.340 

0.315 

0.292 

0.270 

0.250 

0.232 

0.214 

0.199 

0.184 

0.170 

4-4. 

Natural gas price13 

($/MMBtu) 

5.59 

5.76 

5.94 

6.06 

6.19 

6.32 

6.45 

6.59 

6.66 

6.72 

6.78 

6.86 

6.93 

7.00 

7.07 

for illustrative purposes. Not a current 

discounted cash flow factor x fuel price. 

ion period. Boiler is placed in service at 

4-14 

<\FTER 

i 

fuel 

the 

-TAX

 S " ' 

"\fter-tax NPV0 

($/MMBtu) 

0.00 

0.00 

2.54 

2.41 

2.28 

2.15 

2.03 

1.92 

1.80 

1.68 

1.57 

1.47 

1.38 

1.29 

1.20 

23.72 

price projection 

beginning of 

P.85 
The total after-tax NPV equals the sum of: 

• Total capital cost* x (0.5261 or 0.6265) 

• Total annual non-fuel O&M cost* x 3.659 

• Total after-tax NPV of fuel costs (e.g., annual natural gas 

consumption x $23.72/MMBtu from Table 4-5)~ 

*Boiler and pollution control equipment, 

4-15 
P.87 

REFERENCES 

1. Reference 2, pp. 3-4, 4-3. 

2. Industrial Boiler SO2 Cost Report. Radian Corporation. EPA-450/3-85-011. 

Prepared for the U.S. Environmental Protection Agency. November 1984. 

3. For example, reference 45 FR 84967 (December 24, 1980) and 46 FR 31216 

(June 12, 1981). 

4. Tax Information on Depreciation. Internal Revenue Service, U.S. Department 

of Treasury. Publication 534, 1979 Edition (revised November 1979). 

p. 6. 

5. Note the cost calculation methodology proposed by the Economic Regulatory 

Administration, U.S. Department of Energy to be used to compare the 

costs of burning alternate fuels in new industrial boilers related to 

the Powerplant and Industrial Fuel Use Act (45 FR 84967, December 24, 

1980). 

Egan, T. (Charles River Associates). How to Apply For a FUA Exemption. 

Power. 124:85. September 1980. 

Lincoln, R. (Charles River Associates). How to Avoid Common Errors in 

Life-Cycle Cost Comparisons. Power. 125:74-75. May 1981. 

Kolbe, A., and R. Lincoln (Charles River Associates). What Rate of 

Return Makes Your Energy Investment Worthwhile? Power. 127:72. April 

1983. 

6. Investment Credit. Internal Revenue Service, U.S. Department of the 

Treasury. Publication 572 (revised November 1982). p. 5-6. 

7. Devitt, T., P. Spaite, L. Gibbs. Population and Characteristics of 

Industrial/Commercial Boilers in the U.S. PEDCo Environmental, Inc. 

Cincinnati, Ohio. EPA-600/7-79-178a. Prepared for the Industrial 

Environmental Research Laboratory, U.S. Environmental Protection Agency. 

August 1979. p. 133. 

4-16