p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

5) ll-K-(A)-18 

Docket Number: 

A-83-27 

Printed 11/12/200811:12:48 AM Sheet 5 of 325 
ENERGY AND ENVIRONMENTAL ANALYSIS, INC. 

1655 North Fort Myer Drive 

Arlington, Virginia 22209 

(703) 528-1900 
P.3 

PROJECTED IMPACTS OF ALTERNATIVE 

SULFUR DIOXIDE NEW SOURCE 

PERFORMANCE STANDARDS FOR INDUSTRIAL 

FOSSIL FUEL-FIRED BOILERS 

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 

Arlington, Virginia 22209 

March 1985 
-££_ 

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. 
TABLE OF CONTENTS 

P.5 

£i2£ 

1. INTRODUCTION 1-1 

2. METHODOLOGY 2-1 

2.1 Analytical Approach 2-1 

2.2 Key Modeling Assumptions 2-2 

2.3 Evaluation Criteria 2-11 

References 2-13 

3. PROJECTED IMPACTS OF ALTERNATIVE SO2 EMISSIONS STANDARDS 3-1 

3.1 Regulatory Baseline and Alternative SO2 

Emissions Standards 3-1 

3.2 Projected National Impacts of the Alternative 

SO2 Emissions Standards 3-4 

3.3 Projected Regional SOg Emissions Forecasts 3-12 

4. ECONOMIC IMPACTS : 4-1 

4.1 Introduction 4-1 

4.2 Industry Economic Profiles 4-2 

4.3 Economic Impact Analysis 4-9 

APPENDIX A: OVERVIEW OF IFCAM A-l 

APPENDIX B: PROJECTED FUEL PRICES: REFERENCE PRICE SCENARIO B-l 

APPENDIX C: PROJECTED FUEL PRICES: HIGHER OIL AND GAS 

PRICES SCENARIO C-1 

APPENDIX D: CHARACTERISTICS OF INDUSTRIAL COAL TYPES IN IFCAM D-1 

APPENDIX E: DELIVERED INDUSTRIAL COAL PRICE FORECAST E-1 

APPENDIX F: IFCAM PROJECTIONS FOR 1990 BY BOILER SIZE CLASS F-l 
P.6 

LIST OF TABLES 

Page 

2-1 Industrial Boiler Pollution Control Equipment 

Options in IFCAM 2-3 

2-2 Projected Industrial Fossil Fuel Demand 2-5 

2-3 World Oil Price Forecasts 2-9 

3-1 Regulatory Baseline NSPS Assumptions 3-2 

3-2 Alternative SO2 NSPS Emissions Standards for New 

Industrial Fossil Fuel-Fired Boilers 3-3 

3-3 Projected Fuel Demand in 1990 From Large New 

Industrial Fossil Fuel-Fired Boilers 3-6 

3-4 Comparison of Total Projected SO2 Emissions in 1990 

From New Large Industrial Fossil Fuel-Fired Boilers 3-8 

3-5 Comparison of Projected Costs 3-11 

3-6 Projected Solid and Liquid Waste Disposal Requirements 3-13 

3-7 Projected Regional SO2 Emissions in 1990 3-14 

3-8 Projected Regional SO2 Emissions in 1990 3-15 

3-9 Projected Regional SO2 Emissions in 1990 •••» 3-16 

3-10 Projected Regional SO2 Emissions in 1990 3-17 

3-11 Projected Regional SO2 Emissions in 1990 3-18 

3-12 Projected Regional SO2 Emissions in 1990 3-19 

4-1 Fossil Fuel Consumption Characteristics of the 

Major Steam Users ' 4-4 

4-2 Major Steam Users Economic Impacts 4-12 

4-3 Summary of Key Economic Impacts of SO2 Control 

Level VI on Selected Industries 4-17 

4-4 Model Firm and Plan Configuration: Beet Sugar 

Industry Alternative 4-18 

4-5 Economic Impacts of Alternative Control Level VI 

for Beet Sugar Refining • 4-20 

4-6 Model Firm and Plant Configuration: Rubber 

Reclaiming Industry 4-22 

4-7 Economic Impacts of Alternative Control Level VI 

for Rubber Reclaiming 4-24 
P.7 

LIST OF TABLES (continued) 

Page 

4-8 Model Firm and Plant Configurations: Automobile 

Manufacturing 4-26 

4-9 Economic Impacts of Alternative Control Level VI 

for Automobile Manufacturing 4-28 

4-10 Model Firm and Plant Configuration: Petroleum 

Refining Industry 4-29 

4-11 Economic Impacts of Alternative Control Level VI 

for Petroleum Refining 4-31 

4-12 Model Firm and Plant Configuration: Iron and 

Steel Industry 4-33 

4-13 Economic Impacts of Alternative Control Level VI 

for Iron and Steel 4-34 

4-14 Model Firm and Plant Configuration: Liquor 

Distilling Industry 4-36 

4-15 Economic Impacts of Alternative Control Level VI 

for Liquor Distilling 4-37 

4-16 Small Plants in Selected Industries 4-39 

4-17 Industrial Boiler NSPS: Small Business Impact Analysis 

to Study Need for Regulatory Flexibility Analysis 4-40 

A-l Industrial Boiler Pollution Control Technologies in IFCAM A-7 

A-2 IFCAM Industrial Boiler Size/Type Assumptions A-11 

A-3 FGD Technology Constraints in IFCAM A-12 

A-4 PM Emissions Pollution Control Technology 

Constraints in IFCAM A-13 

B-l World Oil Price Forecast: Reference Price Scenario B-2 

B-2 Projections of Industrial 3.0 Percent Sulfur 

Residual Fuel Oil Prices B-3 

B-3 Projections of Industrial 1.6 Percent Sulfur 

Residual Fuel Oil Prices B-4 

B-4 Projections of Industrial 0.8 Percent Sulfur 

Residual Fuel Oil Prices B-5 

B-5 Projections of Industrial 0.3 Percent Sulfur 

Residual Fuel Oil Prices B-6 

B-6 Projections of Industrial Natural Gas Prices B-7 
LIST OF TABLES (continued) 

Page. 

C-1 World Oil Price Forecast: Higher Oil and Gas 

Prices Scenario • C-2 

C-2 Projections of Industrial 3.0 Percent Sulfur 

Residual Fuel Oil Prices C-3 

C-3 Projections of Industrial 1.6 Percent Sulfur 

Residual Fuel Oil Prices C-4 

C-4 Projections of Industrial 0.8 Percent Sulfur 

Residual Fuel Oil Prices C-5 

C-5 Projections of Industrial 0.3 Percent Sulfur 

Residual Fuel Oil Prices C-6 

C-6 Projections of Industrial Natural Gas Prices C-7 

D-1 Sulfur Dioxide Emission Rates by Coal Type D-2 

D-2 Average Ash Content by Region (Bituminous Coal Types) D-3 

D-3 Average Ash Content by Region (Subbituminous Coal Types) D-4 

D-4 Average Heat Content by Region (Bituminous Coal Types) D-5 

D-5 Average Heat Content by Region (Subbituminous Coal Types) D-6 

Delivered Industrial Coal Price Forecast E-1 

F-l Comparison of IFCAM Projections for 1990 F-2 

F-2 Regulatory Baseline Projections for 1990 by 

Boiler Size Class F-3 

F-3 Alternative Control Level I Projections for 1990 

by Boiler Size Class F-4 

F-4 Alternative Control Level II Projections for 1990 

by Boiler Size Class F-5 

F-5 Alternative Control Level III Projections for 1990 

by Boiler Size Class F-6 

F-6 Alternative Control Level IV Projections for 1990 

by Boiler Size Class F-7 

F-7 Alternative Control Level V Projections for 1990 

by Boiler Size Class F-8 

F-8 Alternative Control Level VI Projections for 1990 

by Boiler Size Class • F-9 
P.9 

LIST OF FIGURES 

Page 

1 Federal Regions of the United States 2-6 

2 Change in Product Price Due to Regulatory Option 4-11 

A-l IFCAM Model Structure A-5 
1. INTRODUCTION 

This report presents projected environmental, cost, and energy impacts 

of alternative sulfur dioxide (SO2) air emission standards for new industrial 

fossil fuel-fired boilers. These draft standards would supersede the emission regulations that currently exist in Subpart D of 40 CFR Part 60. The 

effects of the alternative SO2 emission standards are assessed in this 

report. The methodology used to examine environmental, cost, and fossil 

fuel results projected under current and alternative emission regulations 

also is discussed. 

For individual boilers, air emission regulations can play a significant role in determining boiler fuel choice and the levels of air emissions. 

Air emission regulations can result in measureable national and regional 

environmental, cost, and energy impacts, including changes in the types of 

fossil fuels combusted and changes in the level of air pollutant emissions 

generated by new industrial fossil fuel-fired boilers. 

The analysis of alternative regulations is designed to highlight potential environmental, cost, and energy impacts. These impacts are measured 

in terms of the projected change under current versus alternative air emission regulations. The analysis of environmental impacts focuses on changes 

in levels of air emissions. Cost impacts are evaluated in terms of incremental changes in the total annualized costs for boiler and pollution 

control equipment capital, operating, and fuel costs. Energy impacts are 

evaluated in terms of shifts in the demand between fuel types (e.g., coal 

or residual fuel oil versus natural gas). 

Current SO2 emission regulations serve as the base case, from which 

all impacts are measured. Briefly, SO2 emission control regulations in the 

base case for new industrial boilers are the current New Source Performance 

Standards (NSPS) for boilers with heat input capacity greater than 73 MW 

(250 MMBtu/hr). Current SO2 emission regulations for all smaller boilers 

— and for boilers larger than 73 MW (250 MMBtu/hr) heat input if more 

stringent than NSPS -- are State Implementation Plan regulations (SIP's). 

1-1 
P.11 

This analysis examines projected impacts in the fifth year following 

proposal of standards. It was assumed that the recommended standards would 

be proposed in 1985 and that the impact analysis should, therefore, focus 

on projected results for new industrial fossil fuel-fired boilers installed 

in the five-year period between 1985 and 1990. The emissions and energy 

demand projections from new industrial fossil fuel-fired boilers presented 

in this report represent annual estimates for calendar year 1990. 

This report addresses only fossil fuel (coal, oil and natural gas) 

consumption in large new industrial boilers. It does not analyze commercialinstitutional boilers or nonfossil fuel-fired steam-generating units (i.e., 

wood or municipal solid waste combustion). 

The balance of this report is presented in four parts. Section 2 

presents the modeling approach employed to analyze the alternative standards 

and describes key assumptions and inputs. The potential 1990 national and 

regional impacts for the alternative standards are presented in Section 3. 

Section 4 summarizes the national 1990 economic impact results for the most 

stringent regulatory alternative examined. 

1-2 
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2. METHODOLOGY 

The methodology for assessing the environmental, cost, and energy 

impacts of the alternative air emission standards is described briefly in 

this section. The first part describes the model used to project the mix 

of industrial boiler fossil fuel demand, the level of air emissions, and 

the annualized cost of generating steam. The second part summarizes key 

modeling assumptions and model inputs used in this analysis. The third 

part briefly describes the criteria used to evaluate emission, cost, and 

energy impacts of alternative regulations. 

2.1 ANALYTICAL APPROACH 

This analysis is based upon results from the Industrial Fuel Choice 

Analysis Model (IFCAM), an energy demand model developed by Energy and 

Environmental Analysis, Inc. (EEA). In addition to generating fuel mix 

estimates, IFCAM projects levels of air emissions and steam generating 

costs. 

IFCAM is a disaggregated process engineering model; models of this 

type simulate the effects of specific policies on new and existing technical alternatives, including innovative boiler designs and new pollution 

control equipment. IFCAM is designed to assess the impact of several 

factors on fuel choice decisions in the industrial sector, including fuel 

prices, energy and environmental policies, and capital and annual operating 

and maintenance (O&M) costs of firing alternative fossil fuels. 

The U.S. Department of Energy (DOE) is the primary source for projections of overall industrial fossil fuel demand by region. IFCAM disaggregates DOE industrial fossil fuel demand forecasts into nine industrial subsectors. Energy use in each of these industrial subsectors then is divided 

into boiler and process heat applications. 

Industrial boiler fossil fuel use is subdivided further to reflect the 

amount of fuel that will be used in new and existing boilers of different 

sizes and capacity utilization rates. Existing boilers are classified 

according to the type of fuel they are designed to fire and whether they 

2-1 
can be retrofitted to fire alternative fuels. Eight size classes and five 

capacity utilization rate categories are delineated for both new and existing boilers. 

Each new boiler is sited in an Air Quality Control Region (AQCR). New 

boilers are located within each AQCR according to historical siting patterns. 

Because State environmental regulations for existing and new boilers often 

vary by AQCR, IFCAM applies current regulations on an AQCR basis. These 

regulations are based on State air laws for existing fossil fuel-fired 

boilers. 

The boilers represented in IFCAM are fired by one of several types of 

fossil fuels: coal, distillate fuel oil, residual fuel oil, or natural 

gas. IFCAM provides a choice between nine coal types that vary by sulfur, 

ash, and Btu content. Additionally, four residual fuel oil types that vary 

by sulfur content are available. The price of each fuel type can vary by 

region. 

The pollution control equipment options available in IFCAM are presented in Table 2-1. For each fuel type (i.e., coal, oil, and gas), the least 

cost pollution control strategy that meets the alternative standard is 

calculated. The least cost strategy includes finding the lowest cost 

option in terms of the boiler, pollution control equipment, and annual fuel 

costs. 

Based on the characteristics of each combustor (e.g., size, operating 

rate, pollution control requirements), capital and operating costs are 

generated for each fuel type. The fuel type associated with the lowest 

after-tax present value (including expected fuel expenses and boiler and 

pollution control equipment capital and O&M costs) of the total cost of 

generating steam over the boiler's investment period is selected. 

The structure of IFCAM is summarized in Appendix A of this report. 

2.2 KEY MODELING ASSUMPTIONS 

This section presents the approach used in this analysis to model 

variables that could affect significantly the mix of fossil fuels demanded 

by industrial boiler owners.* These variables are: 

•Other assumptions are summarized in Appendix A. 

2-2 
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TABLE 2-1. INDUSTRIAL BOILER POLLUTION CONTROL 

EQUIPMENT OPTIONS IN IFCAM 

Pollutant Technology 

S02 Flue gas desulfurization 

dual alkali3 

lime spray drying0 

sodium 

PM 

NOv 

Single mechanical collector 

Dual mechanical collector 

Side stream separator 

Electrostatic precipitator 

Fabric filter 

Combustion modification 

low excess air 

staged combustion air 

*Tray type scrubber. 

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

2-3 
P.15 

t Regional industrial fossil fuel demand projections 

• Energy policies 

0 Fuel price forecasts 

• Environmental policies 

2.2.1 Regional Industrial Fossil Fuel Demand Projections 

DOE is the primary source of projections of total industrial fossil 

fuel demand. The rate of projected growth in industrial fossil fuel demand 

is a significant parameter because it determines, to a large extent, the 

expected demand for new industrial fossil fuel-fired boilers. 

DOE does not project regional estimates of fuel consumption in industrial boilers. DOE does project regional estimates of total industrial 

fossil fuel demand for heat and power using the Energy Information Administration's (EIA's) Intermediate Future Forecasting System (IFFS). IFFS 

includes an econometric industrial energy demand model, the Purchased Heat 

and Power System (PURHAPS).1'

2 

The EIA regional industrial fossil fuel demand forecasts are summarized 

in Table 2-2. The ten Federal regions are illustrated in Figure 1. These 

projections are assumed to remain the same for regulatory baseline and alternative regulations examined in Sections 3 and 4 because the cost impacts 

are not expected to be sufficiently high to alter total projected energy 

demand. 

The projections shown in Table 2-2 are a function of macroeconomic 

variable projections. For example, real growth in the Gross National Product 

between 1985 and 1990 is assumed to average 2.9 percent per year and real 

growth in manufacturing output between 1985 and 1990 is assumed to average 

3.3 percent per year. The Federal Reserve Board industrial production index 

is expected to increase at a rate of 3.7 percent annually between 1985 and 

1990.3 

Not all of the projected net increase in industrial fossil fuel demand 

shown in Table 2-2 is attributable to new industrial boilers. A significant 

portion of this net increase is attributable to new process heat equipment. 

2.2.2 Enerqy Policies 

Energy policies contained in the National Energy Act of 1978 and the 

Omnibus Reconciliation Act of 1981 are key modeling assumptions in this 

analysis. These bills contain sections relevant to industrial boiler fuel 

choice, including: 

2-4 
P.16 

TABLE 2-2. PROJECTED INDUSTRIAL FOSSIL FUEL DEMAND* 

PJ (1012 Btu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

U.S. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

Total 

1985 

Refinery 

0 

(0) 

48 

(43) 

62 

(59) 

46 

(44) 

107 

(101) 

509 

(482) 

26 

(25) 

34 

(32) 

127 

(120) 

33 

(31) 

992 

(937) 

1990 

Refinery 

0 

(0) 

43 

(41) 

57 

(.54) 

43 

(41) 

99 

(94) 

473 

(448) 

25 

(24) 

32 

(30) 

117 

(111) 

. 30 

(28) 

919 

(871) 

1985 

Industry0 

207 

(196) 

512 

(485) 

946 

(897) 

1,615 

(1,531) 

2,339 

(2,217) 

2,915 

(2,763) 

628 

(595) 

557 

(528) 

733 

(695) 

.442 

(419) 

10,894 

(10,326) 

1990 

Industry0 

224 

(212) 

541 

(513) 

1,017 

(964) 

1,728 

(1,638) 

2,499 

(2,369) 

3,180 

(3,014) 

668 

(633) 

627 

(594) 

817 

(774) 

510 

(483) 

11,811 

(11,194) 

aU.S. Department of Energy, Energy Information Administration. 1982 

Annual Energy Outlook, Middle World Oil Price (Case A) . The regional 

distribution is unofficial and has not been reviewed by EIA. Sum of nonmetallurgical coal, natural gas, distillate and residual fuel oil. 

Excludes petro-chemical feedstocks and natural gas consumed as lease and 

plant fuels. Includes total boiler and process heat fossil fuel demand. 

Excludes fuel consumption in petroleum refineries. Includes construction, 

mining, agriculture, fishing, forestry, and other manufacturing sectors. 

2-5 
ro 

i 

cn 

REGION NAMES 

FIGURE 1 

Federal Regions of the United States 

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.18 

• The Energy Tax Act of 1978 (ETA) 

• The Economic Recovery Tax Act of 1981 (ERTA) 

The ETA provides several tax incentives for the use of coal and alternative fuels. Additional investment tax credits (ITC's) are granted for 

coal and alternative fuel commercial investments. Under the ETA, ITC's and 

accelerated depreciation alternatives are denied for oil and gas investments. 

The ETA authorizes a 10 percent tax credit (in addition to the standard 

10 percent ITC) for coal and alternative fuel investments made between 

October 1, 1978 and December 31, 1982, including investments in the following: 

• Boilers and other combustors that use coal or an alternative fuel 

• Equipment to produce alternative fuels 

• Pollution control equipment 

• Equipment for handling and storage of alternative fuels 

Because authorization for the additional ITC expires in 1982, this provision 

has not been modeled for this analysis of projected new industrial boiler 

installations from 1986 to 1990. 

In IFCAM, these provisions are modeled for the calculation of aftertax boiler and pollution control equipment capital cost cash flows. Investments in new industrial coal-fired boilers receive the standard 10 percent 

ITC and qualify for an accelerated depreciation method, whereas no ITC's 

and straight line depreciation are calculated for new industrial oil-and 

gas-fired boiler investments. 

The ERTA revises the depreciation schedules for captial investment and 

thus improves the tax incentives for new industrial boilers. The depreciation period for new coal-, oil-, and natural gas-fired industrial boilers 

is reduced to five years. 

The Tax Equity and Fiscal Responsibility Act (TEFRA) of 1982 revised 

the Accelerated Cost Recovery System (ACRS) annual recovery percentages for 

five-year period recovery property acquired after 1985. TEFRA also reduced 

the basis for depreciation by 50 percent of the ITC taken when the regular 

ITC (10 percent for five-year recovery period property placed in service 

after 1980) is selected. These TEFRA Federal tax code revisions are not 

reflected in this analysis. They do not apply to new industrial oil and 

2-7 
P.19 

gas boiler investments because they are not permitted to be depreciated 

using the ACRS accelerated depreciation schedule and they do not qualify 

for the ITC. The TEFRA Federal tax code revisions do apply to new industrial coal boiler investments, but they are not expected to significantly 

alter the projected impacts of the alternative NSPS which are presented in 

Sections 3 and 4 of this report. 

In addition, provisions of the Powerplant and Industrial Fuel Use Act 

of 1978, which prohibit the use of oil or natural gas in large new industrial boilers, are an available feature in IFCAM but currently are not 

utilized in the analysis of the potential impacts of the recommended NSPS. 

2.2.3 Fuel Price Forecasts 

Fuel choice decisions in IFCAM are based on selecting the alternative 

with the lowest total after-tax net present value of capital, annual O&M 

and fuel expenses over a 15-year period. In this analysis, the fuel 

expenses are estimated based on projected regional delivered fuel prices 

from 1987 to the year 2001. 

Naturally there is uncertainty related to energy market conditions 

over the next fifteen years. Two regional forecasts of industrial residual 

fuel oil and natural gas prices were developed in order to evaluate the 

sensitivity of IFCAM results (projected impacts of alternative NSPS) to 

this key exogenous assumption, industrial fuel price differences. 

Table 2-3 presents the two world oil price forecasts. Both forecasts 

are based on DOE's (Office of Policy, Planning and Analysis) WOIL forecasting model. EEA estimated regional industrial residual fuel oil and natural 

4 

gas prices for both world oil price projections. These forecasts are 

presented in Appendices B and C. Distillate fuel oil price forecasts were 

not prepared because it is expected that natural gas prices will remain 

lower than distillate fuel oil prices and, therefore, natural gas (or 

residual fuel oil) will be a lower cost new industrial boiler fuel type. 

Only one set of projected industrial coal prices were used in this 

analysis. Therefore, the two fuel price scenarios have different projected 

industrial residual fuel oil and natural gas prices but identical projected 

industrial coal prices. 

2-8 
P.20 

TABLE 2-3. WORLD OIL PRICE FORECASTS* 

(1982 $/bbl) 

Reference Higher oil and 

price gas prices 

Year scenario0 scenario0 

25.90 

31.90 

46.50 

57.40 

aAverage refiner acquisition cost of imported crude oil. 

Energy and Environmental Analysis, Inc. 

cCase B of the fourth National Energy Policy Plan (NEPP-IV or NEPP-1983). 

Energy Projections to the Year 2010. U.S. Department of Energy, Office 

of Policy, Planning and Analysis. DOE/PE-0029/2. October 1983. 

1985 

1990 

1995 

2000 

25.00 

28.00 

32.00 

37.00 

2-9 
P.21 

The industrial coal types in IFCAM have been defined by ICF Incorporated 

in terms of coal type (bituminous or subbituminous) and sulfur, ash, and 

Btu content. There are up to nine distinct coal types per region in IFCAM: 

6 sulfur classes for bituminous coals and 3 sulfur classes for subbituminous 

coals. The tables in Appendices D and E summarize the key characteristics 

and projected prices for the industrial coal types in IFCAM. 

2.2.4 Environmental Policies 

Environmental policies embodied in the 1970 Clean Air Act (CAA) and 

the subsequent 1977 amendments define the regulatory context for this analysis. The Act gave the EPA the authority to establish National Ambient Air 

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

population. There are currently NAAQS for six "criteria pollutants": sulfur 

oxides, PM, N0X, lead, carbon monoxide (CO), and ozone. Industrial sources 

are subject to two classes of environmental regulations adopted to ensure 

compliance with ambient air standards: State Implementation Plan (SIP's) 

and Nonattainment (NA)/Prevention of Significant Deterioration (PSD). The 

CAA gave the EPA the authority to promulgate NSPS regulations governing the 

emissions of pollutants from specific categories of newly constructed 

sources. Each new source must meet requirements of all of these programs. 

For purposes of this analysis, no attempt was made to predict the impact 

of NA, PSD, or local regulations not part of SIP's. Therefore, each new 

boiler is assumed to be subject to a SIP or NSPS, whichever may be more 

stringent. The SIP's in IFCAM are characteristic of those regulations for 

existing industrial fossil fuel-fired boilers. 

The CAA stipulates that each State must prepare a SIP that provides 

for the implementation, maintenance, and enforcement of the NAAQS within 

its geographic area. SIP's vary substantially among States, both in the 

severity of the standards and the way they are expressed. States specify 

standards in a variety of forms including pounds of pollutant per energy 

content 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. 

2-10 
P.22 

A set of SIP regulations reflecting the regional diversity of air 

emission limits has been compiled for use in IFCAM. These SIP's are 

identified by pollutant, fuel type, boiler size, and AQCR and are converted 

to pounds of pollutant per million Btu. 

The SIP file is current as of July 1980 for particulate matter and 

nitrogen oxide emission standards. The SIP file has been updated to March 

1983 for SO2 emission regulations. 

The CAA requires that SIP's include provisions designed to upgrade 

areas of air quality not in attainment with NAAQS. To the extent that NA 

provisions are reflected in the SIP's, NA-related SIP revisions are 

incorporated into the IFCAM SIP file. 

PSD requires that States maintain the air quality of their areas 

attaining NAAQS. Each PSD area is subject to provisions of one of three 

PSD classes that specify allowable incremental increases in ambient air 

pollutant concentrations. Construction of individual stationary sources is 

reviewed to ensure that expected emissions from these new facilities will 

not increase an area's ambient air pollution concentration greater than 

allowed increments such that it exceeds the NAAQS. Because PSD provisions 

are applied by States to individual facilities on a case-by-case or sitespecific basis, PSD has not been modeled. 

Because only a limited number of NA SIP revisions are modeled in 

IFCAM, and PSD regulations have not been addressed, the stringency of local 

regulations may be understated. Consequently, the impact of the 

alternative emission regulations may be overstated because a number of 

boilers may be subject to more stringent local regulations than are 

reflected in IFCAM. 

2.3 EVALUATION CRITERIA 

Throughout the development of alternative emission regulations for new 

industrial boilers, a set of key output parameters has been considered to 

be particularly useful in comparing projected aggregate impacts of alternative regulations. This set of criteria includes the following three parameters: 

• Level of emissions 

• Cost of generating steam 

• Coal and residual fuel oil demand 

2-11 
P.23 

These criteria are used to evaluate impacts of the alternative standards 

for distinct boiler size classes and are described in this section. 

The level of SO2 emissions projected under alternative regulations 1s 

a primary criterion by which to evaluate these regulations. The level of 

emissions is a function of both the regulatory scenario and the mix of fuels 

demanded. 

In addition, the effect of alternative regulations on the total expected cost of generating steam in new industrial boilers is evaluated. Steam 

costs include capital and operating costs for the boiler, capital and operating costs for any required pollution control equipment, and fuel costs. 

The cost impact of the alternative standards is the change from the base 

case in the total cost of generating steam. For this analysis, aggregate 

costs for the least-cost fuel types are presented on a before-tax annualized 

basis using a 10 percent discount rate and a 15-year investment period. 

Coal penetration is projected coal demand expressed as a percentage of 

total projected fossil fuel demand (coal, fuel oil, and natural gas) for 

new industrial boilers. The impact of alternative standards on coal penetration is then examined. The potential for increased coal use in the 

industrial sector is partly a function of environmental regulations 

applicable to industrial facilities. In particular, air emission regulations 

can increase significantly the cost of burning coal compared to the 

alternative of burning a relatively clean type of fossil fuel such as 

natural gas. 

The potential for increased residual fuel oil combustion in the industrial sector is also partly a function of environmental regulations. 

Proposed air emission standards may affect projected residual fuel oil 

demand in new industrial boilers. 

2-12 
P.24 

REFERENCES 

1. 1982 Annual Energy Outlook. U.S. Department of Energy, Energy 

Information Administration. D0E/EIA-0383(82). April 1983. 

2. Supplement to the 1982 Annual Energy Outlook. U.S. Department of 

Energy, Energy Information Administration. D0E/EIA-0408(82). July 

1983. 

3. Reference 1, p. 126; Reference 2, p. 53. 

4. Regional Forecasts of Industrial Residual Fuel Oil and Natural Gas 

Prices. Energy and Environmental Analysis, Inc. Arlington, Virginia. 

Prepared for the U.S. Environmental Protection Agency. July 1984. 

2-13 
P.25 

3. PROJECTED IMPACTS OF ALTERNATIVE 

SO2 EMISSIONS STANDARDS 

This section describes the regulatory baseline NSPS air emissions 

standards and alternative SO2 emissions regulations for new industrial 

fossil fuel-fired boilers. Projected emissions, cost and energy demand 

effects pf the alternative standards, relative to the regulatory baseline, 

are summarized. 

3.1 REGULATORY BASELINE AND ALTERNATIVE SO2 EMISSIONS STANDARDS 

The regulatory baseline is represented by current and proposed air 

emissions standards: the current SO2 NSPS, the proposed PM and N0X NSPS 

and current SIP's. Table 3-1 presents the current SO2 NSPS and the 

proposed PM NSPS. New industrial boilers are assumed to be subject to a 

SIP if the SIP is more stringent than the applicable NSPS shown in this 

table. 

All new industrial oil- and gas-fired and spreader stoker coal-fired 

boilers larger than 29 MW (100 MMBtu/hr) are assumed to employ low excess 

air to control N0X emissions. If the residual fuel oil burned in the new 

large industrial boiler has a nitrogen content greater than 0.35 percent, 

staged combustion air is required to control N0X emissions. All new 

pulverized coal-fired industrial boilers larger than 29 MW (100 MMBtu/hr) 

require staged combustion air to control N0X emissions. These assumptions 

for new large industrial residual fuel oil and coal boilers are consistent 

with the proposed N0X NSPS (49 FR 25103). 

The proposed N0X NSPS for new large industrial natural gas and distillate fuel oil boilers is based on the low N0X burner technology, not a current pollution control option in IFCAM. This difference in assumptions 

will not significantly affect the expected impacts of alternative SO2 NSPS 

for new industrial coal and residual fuel oil boilers. 

The alternative SO2 emissions standards are presented in Table 3-2. 

These alternatives are applicable for new industrial residual fuel oil and 

coal boilers larger than 29 MW (100 MMBtu/hr). The applicable regulation 

3-1 
TABLE 3-1. REGULATORY BASELINE NSPS ASSUMPTIONS 

ng/J (lb/MMBtu) 

Fuel type 

Natural gas 

Distillate fuel oil 

Residual fuel oil 

Coal 

Boiler size 

category 

MW (MMBtu/hr) 

<73 

>73 

<73 

>73 

<73 

>73 

<29 

29-73 

>73 

(<250) 

(>250) 

(<250) 

(>250) 

(^250) 

(>250) 

(<100) 

(100-250) 

(>250) 

340 

34C 

520 

S02 

__ 

(0.8)a 

SIP 

(0.8)* 

SIP 

SIP 

(1.2)a.d 

PM 

43 (0.1)a 

43 (0.1)a 

SIP 

43 (0.1)* 

SIP 

22 (0.05)°»c 

22 (0.05)° 

aCurrent NSPS (40 CFR Part 60, Subpart D for fossil fuel-fired steam 

generators). 

Proposed NSPS (49 FR 25103). 

c86 ng/J (0.20 lb/MMBtu) if the annual capacity utilization rate is less 

than 30 percent. 

30-day rolling average. 

3-2 
TABLE 3-2. ALTERNATIVE SO2 NSPS EMISSIONS STANDARDS FOR 

NEW INDUSTRIAL FOSSIL FUEL-FIRED BOILERS 

to 

I 

CO 

Alternative 

control 

level 

Baseline 

I 

II 

III 

IV 

V 

VI 

Boiler size 

category 

MW (MMBtu/hr) 

29-73 

>73 

29-73 

>73 

>29 

>29 

>29 

>29 

>29 

(100-250) 

(>250) 

(100-250) 

(>250) 

(>100) 

(>100) 

(>100) 

(>100) 

(>100) 

Residual 

Ceiling 

ng/J (lb/MMBtu) 

340 (0.8) 

690 (1.6) 

340 (0.8) 

340 (0.8) 

340 (0.8) 

130 (0.3) 

340 (0.8) 

130 (0.3) 

fuel oil 

Required 

percentage 

reduction 

__ 

— 

— 

— 

— 

„c,d 

90b 

Coal 

Ceiling3 

ng/J (lb/MMBtu) 

520 

730 

520 

520 

390 

260 

520 

260 

U.2) 

(1.7) 

(1.2) 

(1.2) 

(0.9) 

(0.6) 

(1.2) 

(0.6) 

Required 

percentage 

reduction 

— 

— 

— 

>50D 

>50° 

70-90M 

90° 

30-day rolling average. 

Scrubbing is required. 

cScrubbing is not required if the uncontrolled emission rate is equal to or less than 130 ng SO2/J (0.3 lb 

SO2/MMBU1). If the uncontrolled emission rate is greater than 130 ng SO2/J (0.3 lb S02/MMBtu), 70-90 

percent SO2 emissions reduction is required. 

jThe floor emissions rate is 260 ng SO2/J (0.6 lb S02/MMBtu). 
P.28 

is either an emissions ceiling (i.e., alternative control levels I through 

IV) or a fixed (i.e., alternative control level VI) or variable (i.e., 

alternative control level V) percentage reduction. 

Compliance with the alternative SO2 NSPS emissions standards is 

achieved by burning a low sulfur fuel type (with an uncontrolled emission 

rate equal to or lower than emissions ceiling in Table 3-2) or scrubbing a 

medium or high sulfur fuel type. When scrubbing, the controlled SO2 

emission rate must remain lower than the ceiling presented in Table 3-2. 

For alternative control levels III through VI, all coal types must be 

scrubbed. For alternative control level V, all coal types must be scrubbed 

with a 90 percent SO2 emissions removal rate; if the controlled emission 

rate is lower than 260 ng SO2/J (0.6 lb S02/MMBtu), the percentage 

reduction rate may be reduced to (but no lower than) 70 percent. 

Alternative control level V represents the level of control currently 

required under Subpart Da for new electric utility coal-fired steam 

generating units. 

3.2 PROJECTED NATIONAL IMPACTS OF THE ALTERNATIVE S02 EMISSIONS STANDARDS 

This section presents IFCAM projections of total SO2 emissions and 

fuel demand by fuel type in 1990 from new industrial fossil fuel-fired 

boilers larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 

1990. This section also presents IFCAM projections of total capital and 

annualized costs for these new industrial boiler investments. IFCAM 

projections for the regulatory baseline NSPS assumptions are compared with 

IFCAM forecasts for the alternative SO2 NSPS emissions standards. Results 

by boiler size class are presented in Appendix F. 

3.2.1 Fuel Demand Impacts 

IFCAM projects that 604 new industrial fossil fuel-fired (coal, fuel 

oil, or natural gas) boilers, each larger than 29 MW (100 MMBtu/hr), will 

be installed during this period in the United States. They are expected to 

consume a total of 525 PJ (498 trillion Btu) in 1990. This projected 

"population" of large new industrial boilers is based on: 

• The assumed rate of growth in total industrial fossil fuel demand 

(see Table 2-2) 

3-4 
• Estimates of how much of this projected increase will be consumed 

in industrial boilers versus process heaters 

• Estimates of the retirements of existing industrial boilers during 

the 1985-1990 period 

t Estimates of the distribution of fuel demand in new large versus 

small industrial boilers 

This forecast of new large industrial fossil fuel-fired boiler installations is held constant in this analysis and is not altered as a function of 

other input assumptions (e.g., projected oil and gas prices or alternative 

SO2 NSPS assumptions). 

Table 3-3 presents the projected fossil fuel mix by fuel price scenario, 

SO2 NSPS assumption, and fuel type. The fuel mix is not fixed; it is a 

function of the fuel price scenario, the SO2 NSPS assumptions, and many 

other model parameters (i.e., boiler and pollution control equipment cost 

estimates). 

The projected demand for coal in new industrial boilers is \/ery low 

under the reference price scenario. Coal is not selected because the 

projected industrial natural gas and residual fuel oil prices are not large 

enough to offset the relatively high coal capital and annual non-fuel O&M 

expenses. 

The projected coal market share is significantly higher for the higher 

oil and gas prices scenario. Projected natural gas and residual fuel oil 

prices are much higher under the higher oil and gas prices scenario than 

they are under the reference price scenario (reference Appendices B and C). 

The fuel choice decision criteria in IFCAM for new industrial boilers is 

based on a comparison of projected after-tax capital, O&M and fuel expenses 

over a 15-year period. Therefore, higher projected oil and gas prices are 

expected to increase the projected demand for coal. 

In general, coal may be an economical fuel type when the new industrial 

boiler sizes and/or expected annual capacity utilization rates are large. 

Coal is ne^er selected in IFCAM as a new industrial boiler fuel type if the 

expected annual capacity utilization rate is lower than 30 percent. Therefore, the expected annual capacity utilization rate for each new unit is an 

important factor in the fuel choice decision process in IFCAM. 

3-5 
P.30 

TABLE 3-3. PROJECTED FUEL DEMAND IN 1990 FOR LARGE NEW 

INDUSTRIAL FOSSIL FUEL-FIRED BOILERS* 

PJ (IO12 Btu) 

Fuel price 

scenario 

Reference 

Higher Oil and 

Gas Prices 

Alternative 

control 

level 

Baseline 

I 

II 

III 

IV 

V 

VI 

Baseline 

I 

II 

III 

IV 

V 

VI 

Natural 

gas 

160 (152) 

161 (153) 

237 (225) 

245 (232) 

282 (267) 

282 (267) 

310 (294) 

218 (207) 

250 (237) 

264 (250) 

364 (345) 

364 (345) 

364 (345) 

370 (351) 

Residual 

fuel oil 

341 (323) 

347 (329) 

271 (257) 

271 (257) 

217 (206) 

217 (206) 

188 (178) 

8 (7) 

0 (0) 

0 (0) 

0 (0) 

0 (0) 

0 (0) 

0 (0) 

Coal 

24 (23) 

18 (17) 

18 (17) 

9 (9) 

27 (26) 

27 (26) 

27 (26) 

300 (284) 

275 (261) 

262 (248) 

161 (153) 

161 (153) 

161 (153) 

155 (147) 

lEach larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. 

Total fossil fuel demand in 1990 is 525 PJ (498 trillion Btu). 

3-6 
P.31 

Another key factor is the location of the new unit. SIP's and projected fuel prices vary by region. 

Residual fuel oil demand in new industrial boilers is ^ery small under 

the higher oil and gas price scenario. In general, the projected natural 

gas prices are lower than the projected residual fuel oil prices in this 

scenario (reference Appendix C) . As a result, natural gas is a lower cost 

alternative than residual fuel oil. 

Under the reference price scenario, a significant amount of residual 

fuel oil is projected. In this case, the projected natural gas prices are 

not lower than the projected residual fuel oil prices (reference Appendix 

B ). They are similar to the projected medium or low sulfur residual fuel 

oil prices. Since the projected industrial natural gas and residual fuel 

oil prices are somewhat "competitive" in the reference price scenario, there 

is a significant amount of natural gas and residual fuel oil demand. The 

actual projected natural gas/residual fuel oil mix is a function of SIP's 

and the SO2 NSPS assumptions for residual fuel oil. 

The projected demand for natural gas is higher under the alternative 

standards than it is under the regulatory baseline in Table 3-3. The 

alternative SO2 emissions standards increase the costs of burning residual 

fuel oil and coal in large new industrial boilers. Some new units (which 

selected coal or residual fuel oil under the regulatory baseline) select 

natural gas under the alternative standards as the least-cost alternative. 

Under the reference price scenario/regulatory baseline, the new 

industrial boiler population has selected residual fuel oil as the primary 

fuel type. Under the higher coal and gas prices/regulatory baseline, the 

new industrial boiler population has chosen coal as the primary fuel type. 

3.2.2 Projected SO2 Emissions Impacts 

Table 3-4 presents the projected SO2 emissions for the alternative 

standards. The total projected SO2 emissions reduction in 1990 is projected 

to range from 68-281 Gg (75-310 thousand short tons). The total projected 

SO2 emissions reductions are relatively large (up to 95 percent). 

Some portion of the total projected SO2 emissions reductions presented 

in Table 3-4 is due to the fact that the fuel mix is not held constant 

between the regulatory baseline and the alternative standards. A portion 

3-7 
P.32 

TABLE 3-4. COMPARISON OF TOTAL PROJECTED SO2 EMISSIONS IN 

1990 FROM NEW LARGE INDUSTRIAL FOSSIL FUEL-FIRED BOILERS* 

Gg (IO3 short tons) 

Fuel price scenario 

Alternative Higher oil and 

control level Reference gas prices 

Baseline 253 (279) 296 (326) 

I 185 (204) 134 (148) 

II 96 (106) 103 (114) 

III 93 (102) 42 (46) 

IV 35 (39) 31 (34) 

V 43 (47) 27 (30) 

VI 15 (16) 15 (16) 

aEach larger than 29 MW (100 MMBtu/hr) and installed between 1985 and 1990. 

3-8 
P.33 

of the new industrial boilers, that select coal or residual fuel oil under 

the regulatory baseline, choose natural gas under the alternative standards 

(see Table 3-3). 

Compliance fuel types (as opposed to scrubbing non-compliance fuel 

types) are the primary control strategy selected for the regulatory baseline 

and alternative control levels I and II. Compliance fuel types are also 

selected as the primary compliance strategy for new large industrial 

residual fuel oil boilers for alternative control level III. 

Industrial residual fuel oil-fired boilers can burn a \/ery low sulfur 

fuel type (less than 0.3 percent sulfur) or scrub emissions from the combustion of a medium or high sulfur fuel type under alternative control levels 

IV and V. Under the reference price scenario/alternative control levels IV 

and V, 188 new industrial residual fuel oil boilers select scrubbers and 57 

new industrial residual fuel oil boilers select a very low sulfur fuel type. 

In many cases, it is less expensive to scrub a 1.6 percent sulfur residual 

fuel oil than it is to burn a very low sulfur fuel type. This occurs because 

the projected residual fuel oil sulfur premiums (0.3 percent sulfur residual 

fuel oil price less the 1.6 percent sulfur residual fuel oil price) are 

larger than the annualized scrubber capital and O&M costs. Scrubbers are 

not selected on all new industrial residual fuel oil boilers under the 

alternative control levels IV and V because scrubbers are not an economical 

compliance alternative for new units with low annual capacity utilization 

rates. 

Sodium scrubbers are the only FGD technology selected in IFCAM. Lime 

spray drying and dual alkali FGD technologies are options in IFCAM which 

are not selected because they are more expensive than sodium scrubbing 

systems. 

The projected SO2 emissions reductions presented in Table 3-4 are due 

to scrubbing, switching to lower sulfur coal or residual fuel oil types, 

and to switching from coal or residual fuel oil combustion under the 

regulatory baseline to natural gas combustion under the alternative control 

level. Accordingly, the average cost-effectiveness of SO2 emissions 

3-9 
P.34 

control on large new industrial fossil fuel-fired boilers (derived from 

these aggregate IFCAM projections) reflect several types of pollution control 

strategies and do not match estimates of the average cost-effectiveness of 

any single technology. 

3.2.3 Projected Cost Impacts 

The projected increase in total annualized costs is projected to range 

from $8 million to $133 million (reference Table 3-5). The total annualized 

cost increases are larger for the reference price scenario than for the 

higher oil and gas prices scenario for two reasons: 

• There is more total demand for residual fuel oil and coal in the 

reference price scenario/regulatory baseline (365 trillion Btu) 

than under the higher oil and gas prices/regulatory baseline (307 

trillion Btu). 

• A significant number of new industrial coal-fired boilers under 

the higher oil and gas prices/regulatory baseline choose natural 

gas under the alternative standards (see Table 3-3). This type 

of "switching" from a capital- and annual non-fuel O&M-intensive 

investment (coal) to a fuel cost-intensive alternative (natural 

gas) can result in small (or sometimes negative) increases in 

total before-tax annualized costs.* If the fuel mix was held 

constant (that is, if the fuel mix under the higher oil and gas 

prices/alternative standards was identical to the fuel mix under 

the higher oil and gas prices/regulatory baseline), then the range 

of the total projected annualized cost increase under the higher 

oil and gas prices scenario would be significantly higher than 

$10-33 million. 

Table 3-5 shows that the total projected capital costs are much higher 

under the higher oil and gas prices scenario than under the reference price 

scenario. This is because coal is a capital-intensive investment and the 

projected coal demand is much higher under the higher oil and gas 

•Recall that IFCAM makes fuel choice decisions based on a comparison of 

after-tax costs. 

3-10 
P.35 

TABLE 3-5. COMPARISON OF PROJECTED COSTS* 

(millions of 1982 dollars) 

Alternative 

control level 

Fuel price scenario 

Reference 

Higher oil and 

gas prices 

Total annualized costs°>c 

Baseline 

I 

II 

III 

IV 

V 

VI 

Increase in total annualized 

costs over the Baseline 

I 

II 

III 

IV 

V 

VI 

Total capital costs0 

Baseline 

I 

II 

III 

IV 

V 

VI 

3,349 

3,357 

3,406 

3,408 

3,476 

3,474 

3,482 

8 

57 

59 

127 

125 

133 

2,588 

2,468 

2,479 

2,391 

2,649 

2,652 

2,653 

3,725 

3,735 

3,743 

3,754 

3,757 

3,758 

3,757 

10 

18 

29 

32 

33 

32 

5,925 

5,562 

5,350 

4,077 

4,066 

4,078 

3,986 

aNew industrial fossil fuel-fired boilers larger than 29 MW (100 MMBtu/hr) 

and installed between 1985 and 1990. 

Capital costs x 0.13147 (a capital recovery factor based on a 10 percent 

interest rate and a 15-year period) plus annual non-fuel O&M costs plus 

levelized fuel costs. 

cIncludes total boiler and pollution control equipment expenses. 

3-11 
P.36 

prices scenario than under the reference price scenario. Total projected 

capital costs are lower under most of the alternative standards than under 

the regulatory baseline because the projected coal demand in new industrial 

boilers is lower under the alternative standards than under the regulatory 

baseline (see Table 3-3). 

3.2.4 Other Impacts 

Sodium scrubbing is the only FGD technology selected in IFCAM. It 

generates a liquid effluent. Table 3-6 indicates that the projected increase 

in liquid waste due to the alternative standards is as large as 5.4 million 

cubic meters. 

The projected solid waste disposal requirements are larger under the 

higher oil and gas prices scenario because there is a much larger demand 

for coal in this case versus the base case fuel prices. Under the higher 

oil and gas prices scenario, the projected total solid waste disposal 

requirements drop due to the alternative standards because total projected 

coal demand declines (see Table 3-3). 

3.3 PROJECTED REGIONAL SO2 EMISSIONS FORECASTS 

IFCAM projects regional large new industrial fossil fuel-fired boiler 

SO2 emissions. Figure 1 presents the ten Federal regions. 

Tables 3-7 through 3-12 present the regional SO2 emissions forecasts 

for the regulatory baseline and the six alternative control levels. Most 

of the projected SO2 emissions reductions are located in Federal regions 4, 

5, and 6. 

3-12 
P.37 

TABLE 3-6. PROJECTED SOLID AND LIQUID WASTE 

DISPOSAL REQUIREMENTS 

Coal boiler Scrubber 

Alternative solid waste* liquid waste0 

control level Gg (IO3 short tons) IO3 cubic meters 

Reference fuel prices 

Baseline 97 (107) 811 

I 66 (73) 732 

II 69 (76) 1,154 

III 38 (42) 1,262 

IV 115 (127) 4,409 

V 115 (127) 4,205 

VI 115 (127) 4,944 

Higher oil and gas prices 

Baseline 1,228 (1,345) 667 

I 1,111 (1,225) 699 

II 1,046 (1,153) 826 

III 701 (773) 5,584 

IV 681 (751) 5,719 

V 701 (773) 6,080 

VI 651 (718) 6,062 

aNew industrial coal-fired boilers installed between 1986 and 1990 which 

are larger than 29 MW (100 MMBtu/hr). Includes coal boiler bottom ash and 

fly ash collected by particulate matter emissions control equipment. 

New industrial coal and residual fuel oil boilers installed between 1986 

and 1990 which are larger than 29 MW (100 MMBtu/hr). Includes sodium 

scrubbing treated effluent. 

3-13 
P.38 

TABLE 3-7. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Reference price scenario 

Regulatory 

baseline 

2.8 

4.6 

19.1 

48.4 

58.2 

77.1 

17.1 

7.4 

6.6 

12.1 

253.5 

(3.1) 

(5.1) 

(21.0) 

(53.3) 

(64.1) 

(85.0) 

(18.9) 

(8.2) 

(7.3) 

. (13.3) 

(279.4) 

Alternative control 

I 

2.8 

4.4 

18.1 

37.2 

43.7 

44.6 

12.0 

5.4 

6.2 

11.6 

186.1 

(3.1) 

(4.8) 

(20.0) 

(41.0) 

(48.2) 

(49.2) 

(13.2) 

(6.0) 

(6.8) 

(12.8) 

(205.1) 

2.4 

3.7 

12.9 

24.9 

29.8 

b 

1.7 

3.5 

5.4 

11.4 

95.9 

level 

II 

(2.7) 

(4.1) 

(14.2) 

(27.4) 

(32.9) 

b 

(1.9) 

(3.9) 

(6.0) 

(12.6) 

(105.8) 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

Less than 50 Mg (55 short tons). The projected SO2 emission reduction 

is 99 percent because natural gas is the only fuel type selected in this 

region under alternative control level II. 

3-14 
P.39 

TABLE 3-8. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Reference price scenario 

Regulatory 

baseline 

2.8 

4.6 

19.1 

48.4 

58.2 

77.1 

17.1 

7.4 

6.6 

12.1 

253.5 

(

3-D 

(5.1) 

(21.0) 

(53.3) 

(64.1) 

(85.0) 

(18.9) 

(8.2) 

(7.3) 

(13.3) 

(279.4) 

Alternative control 

III 

2.4 

3.7 

12.9 

24.9 

29.8 

b 

b 

1.5 

5.4 

11.4 

92.2 

(2.7) 

(4.1) 

(14.2) 

(27.4) 

(32.9) 

b 

b 

(1.6) 

(6.0) 

(12.6) 

(101.7) 

0.8 

1.6 

5.3 

9.9 

9.1 

b 

b 

0.8 

2.6 

5.0 

35.1 

level 

IV 

(0.9) 

(1.8) 

(5.8) 

(10.9) 

(10.0) 

b 

b 

(0.9) 

(2.9) 

(5.5) 

(38.7) 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

Less than 50 Mg (55 short tons). The projected SO2 emission reduction 

is 99 percent because natural gas is the only fuel type selected in this 

region under alternative control levels III and IV. 

3-15 
P.40 

TABLE 3-9. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Reference pr 

Regulatory 

baseline 

2.8 

4.6 

19.1 

48.4 

58.2 

77.1 

17.1 

7.4 

6.6 

12.1 

253.5 

(3.1) 

(5.1) 

(21.0) 

(53.3) 

(64.1) 

(85.0) 

(18.9) 

(8.2) 

(7.3) 

(13.3) 

(279.4) 

ice scenario 

Alternative control 

V 

0.9 

1.7 

6.7 

10.9 

12.1 

b 

b 

0.8 

3.4 

6.1 

42.7 

(1.0) 

(1.9) 

(7.4) 

(12.0) 

(13.3) 

b 

b 

(0.9) 

(3.8) 

(6.7) 

(47.1) 

0.2 

0.5 

2.6 

3.3 

5.3 

b 

b 

0.3 

0.8 

1.7 

14.8 

level 

VI 

(0.2) 

(0.6) 

(2.9) 

(3.6) 

(5.8) 

b 

b 

(0.3) 

(0.9) 

(1.9) 

(16.3) 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

Less than 50 Mg (55 short tons). The projected SO2 emission reduction 

is 99 percent because natural gas is the only fuel type selected in this 

region under alternative control levels V and VI. 

3-16 
P.41 

TABLE 3-10. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Higher 

Regulatory 

baseline 

b 

5.2 

25.4 

73.5 

74.1 

70.7 

22.9 

13.3 

2.8 

7.8 

295.7 

b 

(5.7) 

(28.0) 

(81.0) 

(81.7) 

(77.9) 

(25.2) 

(14.7) 

(3.1) 

(8.6) 

(325.9) 

oil and gas prices 

Alternative control 1 

I II 

b 

2.0 

15.8 

32.4 

32.3 

27.9 

4.1 

10.8 

2.8 

5.8 

133.9 

b 

(2.2) 

(17.4) 

(35.7) 

(35.6) 

(30.8) 

(4.5) 

(11.9) 

(3.1) 

(6.4) 

(147.6) 

b 

1.8 

11.2 

23.5 

22.8 

25.6 

3.4 

8.7 

2.8 

3.8 

103.7 

evel 

b 

(2.0) 

(12.4) 

(25.9) 

(25.1) 

(28.2) 

(3.7) 

(9.6) 

(3.1) 

(4.2) 

(114.3) 

*New industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

'Less than 50 Mg (55 short tons). 

3-17 
P.42 

TABLE 3-11. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Higher 

Regulatory 

baseline 

b 

5.2 

25.4 

73.5 

74.1 

70.7 

22.9 

13.3 

2.8 

7.8 

295.7 

b 

(5.7) 

(28.0) 

(81.0) 

(81.7) 

(77.9) 

(25.2) 

(14.7) 

(3.1) 

(8.6) 

(325.9) 

oil and gas prices 

Alternative control 

III 

b 

1.2 

7.3 

7.2 

10.8 

6.9 

1.2 

2.4 

0.6 

3.7 

41.4 

b 

(1.3) 

(8.1) 

(7.9) 

(11.9) 

(7.6) 

(1.3) 

(2.7) 

(0.7) 

(4.1) 

(45.6) 

b 

0.8 

5.1 

6.2 

7.3 

6.0 

0.7 

1.6 

0.5 

2.4 

30.6 

level 

IV 

b 

(0.9) 

(5.6) 

(6.8) 

(8.0) 

(6.6) 

(0.8) 

(1.8) 

(0.5) 

(2.7) 

(33.7) 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

Less than 50 Mg (55 short tons). 

3-18 
P.43 

TABLE 3-12. PROJECTED REGIONAL SO2 EMISSIONS IN 1990* 

Gg (IO3 short tons) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Federal region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

U.S. 

Higher 

Regulatory 

baseline 

b 

5.2 

25.4 

73.5 

74.1 

70.7 

22.9 

13.3 

2.8 

7.8 

295.7 

b 

(5.7) 

(28.0) 

(81.0) 

(81.7) 

(77.9) 

(25.2) 

(14.7) 

(3.1) 

(8.6) 

(325.9) 

oil and gas prices 

Alternative c 

V 

b 

0.8 

5.1 

4.4 

7.3 

4.2 

0.8 

1.6 

0.5 

2.4 

26.9 

b 

(0.9) 

(5.6) 

(4.8) 

(8.0) 

(4.6) 

(0.9) 

(1.8) 

(0.5) 

(2.7) 

(29.7) 

:ontrol 

b 

0.5 

3.4 

1.5 

6.7 

1.0 

0.1 

0.5 

0.2 

0.5 

14.5 

level 

VI 

b 

(0.6) 

(3.8) 

(1.6) 

(7.4) 

(1.1) 

(0.1) 

(0.6) 

(0.2) 

(0.5) 

(16.0) 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and larger than 29 MW (100 MMBtu/hr). 

Less than 50 Mg (55 short tons). 

3-19 
P.44 

4. ECONOMIC IMPACTS 

4.1 INTRODUCTION 

This section presents economic impacts for one of the alternative 

SO2 emission standards for new industrial fossil fuel-fired boilers. 

The alternative control level selected reflects an upper bound on the 

stringency of emission standards which have been studied by EPA. SO2 

alternative control level VI (reference Table 3-2) requires scrubbing on 

all new industrial residual fuel oil and coal boilers with a heat input 

capacity larger than 29 MW (100 MMBtu/hr). 

In determining if potentially severe economic impacts could occur 

to industrial users of steam, the impact analysis examines both costrelated impacts and capital availability issues. Cost related impacts 

include impacts on product price, value added, and return on assets for 

selected industries. Capital availability issues refer to the ability 

of a firm to obtain capital to finance the costs of control required by 

an alternative SO2 standard. 

A detailed description of the methodology and background information used in the impact analysis is contained in the draft EIS Fossil 

Fuel-Fired Industrial Boilers - Background Information, Volume 1, (EPA450/3-82-006a) published in March, 1982. The following discussion presents a summary of the analytical framework and industry profiles included in the draft EIS document. The impact results have been revised 

to reflect the current national cost impacts generated by EEA's Industrial Fuel Choice Analysis Model (IFCAM). 

Because the number of industries that could be affected by the proposed standard is large, a two-fold approach has been used to assess the 

level and nature of the economic impact without undertaking a detailed 

analysis of e^/ery industry. The first component is performed on the 

general industry level (i.e., food or steel industries) for major steamusing industries. Eight industry groups, which account for approximately 70 percent of total industrial steam consumption are examined. 

The second component of the user impact analysis focuses on the 

economic impact of selected four-digit Standard Industrial Classification (SIC) industries. This focus is necessary since the major 

4-1 
steam user analysis utilizes industry averages to assess economic 

impact. Because each two-digit SIC industry grouping is composed of 

many four-digit SIC industries, the industry average may not capture the 

impact of regulatory options on specific four-digit SIC industries. In 

addition, four-digit SIC industries that are not part of the eight 

industry groups analyzed under major steam users may be affected 

severely. To remedy the situation, the economic impact on selected 

four-digit SIC industries is examined. The industries chosen for this 

component of the analysis were selected by a screening process designed 

to identify the four-digit SIC industries most likely to experience 

adverse economic impacts. By evaluating the economic impact on 

industries most likely to be affected adversely, the impact on other 

industries groups can be inferred to be less severe. 

The remainder of this section is divided into two parts. Section 

4.2 presents an overview of the profiles for industries that will be 

covered in the economic impact analysis. Section 4.3 covers the results 

of the impact analysis. 

4.2 INDUSTRY ECONOMIC PROFILES 

4.2.1 Major Steam Users Profile 

The major steam users consist of the following eight industry 

groups: 

• 

t 

§ 

• 

• 

• 

• 

• 

Food 

Textiles 

Paper 

Chemicals 

Petroleum refining 

Stone, clay, and glass 

Steel 

Aluminum. 

These industries are examined because together they will bear most of 

the cost burden of an alternative SO2 standard. Except for steel and 

aluminum, the industries examined are identified by a two-digit SIC 

code. 

4-2 
P.46 

These eight industries generally use approximately 50 percent or 

more of their energy consumption to generate steam and/or have steam 

costs that comprise a major percentage of production costs. Table 4-1 

shows 1976 total fossil fuel consumption (excluding raw material and 

feedstock uses) and the percent of total consumption accounted for by 

boilers in each of the major steam user groups. Approximately 48 percent of all industrial non-feedstock fossil fuel consumption in 1976 was 

in boilers. The paper, food, and textiles industries consumed significantly more of their fossil fuel in boilers than in other uses; the 

paper industry consumed approximately 87 percent of its fossil fuel in 

boilers, the food industry 83 percent, while the textile industry used 

80 percent. The chemicals and aluminum industries also were well above 

the average for industrial boiler fossil fuel consumption. 

4.2.2 Selected Industries Profile 

This section contains profiles of the seven four-digit SIC industries selected for analysis. Due to the large number of four-digit SIC 

industries, screening criteria were used to target those industries most 

likely to experience cost-related impacts and/or capital availability 

constraints. 

Industries most likely to experience cost-related impacts are those 

with a high steam cost to production cost ratio. A high ratio usually 

stems from one of two factors: 1) the production process is steamintensive or 2) the firm or industry has cyclic steam requirements, 

resulting in a low capacity utilization of the boiler equipment. Low 

capacity utilization causes the capital cost component of steam costs to 

rise, yielding high annualized costs per unit of steam. Therefore, 

capacity utilization and percentage of steam costs to total product 

costs are used as selection criteria. 

Capital availability constraints occur when the cost of acquiring 

funds is so high that a firm considers a project to be uneconomic or 

financially unattractive. Capital availability is most often a problem 

for relatively small firms. Although some large firms may have excessive debt burdens, lack of access to organized capital markets is more 

often characteristic of small firms. Thus, size is used to identify 

firms with potential capital availability problems. 

4-3 
TABLE 4-1. FOSSIL FUEL CONSUMPTION CHARACTERISTICS OF THE MAJOR STEAM USERS 

i 

SIC Code 

20 

22 

26 

28 

29 

32 

3312 

3315-17 

3334, 

3353-55 

Industry 

Food 

Textiles 

Paper 

Chemicals 

Petroleum 

Refineries 

Stone, clay 

and glass 

Steel 

Aluminum 

Other0 

Total 

Total fossil 

fuel consumption*»D 

IO12 kJ 

797.8 

224.9 

1,191.9 

2,537.2 

1,395.3 

1,128.8 

967.4 

275.4 

2,476.1 

10,994.7 

(IO*2 Btu) 

(756.3) 

(213.2) 

(1,129.9) 

(2,405.3) 

(1,322.7) 

(1,070.1) 

(917.1) 

(261.1) 

(2,347.3) 

(10,423.0) 

Industrial boiler* 

fossil fuel consumption 

as a percent of total 

fossil fuel consumption 

83 

81 

87 

66 

26 

4 

30 

64 

32 

48 

aEnergy and Environmental analysis, Inc. The Industrial Sector Energy Consumption Data Base (ECDB) 

for 1975 and 1976. December 15, 1980. 

DExcludes raw materials, feedstock, and use in vehicles. Includes coal, distillate and residual 

fuel oil, and natural gas. 

cIncludes agriculture, mining, miscellaneous manufacturing, and construction industries. 
P.48 

The following six four-digit SIC industries have been selected for 

the economic impact analysis and are briefly described in this section. 

• Beet sugar refining 

• Rubber reclaiming 

• Automobile manufacturing 

• Petroleum refining 

• Iron and steel manufacturing 

• Liquor distilling 

The fruit and vegetable canning industry, initially profiled for 

potential economic impacts, has not been included in this report because 

it is anticipated that its new steam generating equipment would burn 

natural gas as the primary fuel type and not be affected by an alternative SO2 NSPS standard. 

Beet Sugar Refining Industry: The U.S. beet sugar refining industry (SIC 2063) is characterized by relatively few producers. As of mid1982, 10 companies operated 40 plants generally located in the midwestern and Pacific States. 

Refining operations are highly seasonal, usually commencing in midSeptember and ending by mid- to late March. The length of the refining 

season varies from 120 to 220 days, depending on beet crop conditions. 

During the average refining season of 180 days, plants operate seven 

days a week, 24 hours a day. Annual capacity utilization of boilers at 

a plant is typically in the range of 30 to 45 percent. 

In recent years, the annual total output of the beet sugar industry 

has been decreasing. The number of plants in the industry also has decreased; firms have closed less profitable plants, run operations as a 

cooperative (i.e., where the firm is owned by the sugar beet farmers) 

or, as a last resort, entirely terminated operations. The major 

explanation for decreased production is the increasing level of cane 

sugar imports and the use of concentrated fructose as a substitute for 

sugar. 

Due to declining sales, most domestic producers are not considering 

expansion. Instead, they are focusing on plant (and boiler) maintenance 

4-5 
P.49 

and/or replacements as well as company consolidations when economically 

practical. Due to the industry's small profit margin, only the larger, 

more profitable firms that benefit from economies of scale would consider investing in a boiler replacement. 

Rubber Reclaiming Industry: The rubber reclaiming industry (SIC 

3031) consists of eight producers operating eight manufacturing establishments. Although the bulk of reclaiming occurs in Ohio, manufacturing 

plants are located throughout the eastern States. 

Rubber reclaimers buy old rubber tires, inner tubes, and other 

scrap rubber materials and recycle them into a reusable form of rubber, 

notably tires and floor mats. Approximately 60 percent of all reclaimed 

rubber is used in tire manufacturing. For several manufacturers, unmolded reclaimed rubber is the sole output, while for others, especially 

the larger integrated firms, unmolded recycled rubber is not a primary 

product but part of an internal subprocess producing various rubber 

goods. 

For the past decade, the rubber reclaiming industry has suffered 

from volatile sales, production fall-offs, and plant reductions. A 

series of external factors account for these conditions. Most stringent 

ceilings on the amounts of reclaimed rubber allowed in car tires have 

been the largest obstacle to the industry's expansion. With the increasing popularity of radial tires, which contain a much smaller percent of reclaimed rubber than standard ply tires, reclaimed rubber consumption has decreased. 

With production dropping, selling prices fluctuating, and production costs mounting, the industry is not considering expanding productive capacity, but instead is using available funds to replace existing 

capital assets. 

Automobile Manufacturing Industry: The U.S. automobile manufacturing industry (SICs 3711, 3713, and 3714) consists of four firms engaged in manufacturing and assembling "American-made" vehicles. These 

vehicles are produced in many States (and sometimes in other countries), 

with the majority of production occurring in Michigan, Missouri, Ohio, 

California, New Jersey, and Wisconsin. In addition to producing 

automobiles, the four manufacturing firms produce light trucks, 

commercial trucks, buses, and other motor vehicles. 

4-6 
P.50 

Except for the industry leader, the market shares of domestic manufacturers declined between 1978 and 1983 due to the increased market 

share of the dominant domestic producer as well as the increased sales 

of imported automobiles. The share of total sales accounted for by imports increased by about one-third between 1977 and 1984, from 18.3 percent to 23.5 percent. 

Petroleum Refining Industry: The petroleum refining industry (SIC 

2911) consists of 153 companies operating 289 domestic refineries. Of 

these firms, 19 control over 70 percent of the U.S. refining capacity. 

Although refineries operate in 41 States, approximately 27 percent 

of the crude distillation capacity is concentrated in Texas. California 

and Louisiana, the second and third largest petroleum refining States, 

respectively, jointly account for another 27 percent of crude distillation capacity. 

The U.S. petroleum refining industry has suffered from an operating 

cost disadvantage when compared to foreign oil companies. U.S. oil 

companies face higher taxes and labor costs than their foreign counterparts. This partially explains why the United States imports a significant share of its oil requirements in the form of refined products (as 

opposed to crude). Consequently, the United States accounts for less 

than one percent of the world refinery capacity additions. 

Iron and Steel Manufacturing Industry: The iron and steel industry 

(SIC 3312) consists of integrated establishments that produce basic 

steel shapes in the form of semi-finished products such as ingots, 

billets, blooms, and slabs or finished products such as steel strips, 

bars, shapes, heavy structurals, and rails. Establishements primarily 

engaged in producing finished products form purchased iron and steel 

(e.g., non-integrated) are considered separate industries and are 

classified under SIC codes 3315, 3316, and 3317. 

Typically, operations at integrated steel works involve manufacturing iron from raw materials, refining the iron into steel, casting 

and milling the steel into semi-finished shapes, and either selling the 

shapes to non-integrated finishing facilities or hot rolling into 

4-7 
P.51 

finished products at the works. Integrated steel works range in size 

from large plants using several steel-making processes and finishing 

mills to small plants using a single process and selling a semi-finished 

product. 

Over the last decade, the steel industry has suffered from recessionary trends rooted in the 1950's. Spiraling costs and restrained 

prices have reduced industry profits to low levels, leaving major steel 

producers with little capital for maintenance or expansion. As a 

result, domestic steel producers have been postponing large capital commitments, closing or selling unprofitable operations, reducing production levels, and merging with other companies. 

Most of the capital investments made in recent years have been 

piece-meal expansions and replacements rather than large-scale capacity 

additions or new plants. Projects have attempted to cut costs by improving productivity, or boosting yields through modernization. It is 

likely that future investments will follow the same route of piece-meal 

expansions and replacements unless present market conditions improve. 

Liquor Distilling Industry: The liquor distilling industry (SIC 

2085) is made up of those establishments that manufacture liquor by distillation or rectification. They produce cordial and alcoholic 

cocktails by blending processes or by mixing liquors and other ingredients. All liqudrs except brandy are included in this category. 

The liquor distilling industry is comprised of approximtely 50 

firms that operate 100 distilleries. The greatest concentrations of 

distilling plants is located in the east south central States (Federal 

Region 4.) While distilleries are located in 25 States, Kentucky has 27 

percent of the total number of domestic plants. California follows 

second with 11 percent of the total. 

The number of plants that these firms operate has decreased in the 

past decade. In 1972, 121 distilleries were operating; by 1977, this 

sum had fallen to 104, a loss of 17 distilleries in five years. Apparently, no new facilities have been constructed in recent years. Several 

factors may explain the decreasing number of operating distilleries: 

some plants are old, inefficient, and not equipped for the major 

4-8 
oroduction modifications often necessary to satisfy the demands of a 

changing market; furthermore, large firms often find operating fewer 

plants more efficient. 

The major inter-industry competition to the distilled spirits 

industry arises from the beer and wine industries. Beer and wine consumption has grown at the expense, to some degree, of "hard" liquors. 

Intensive advertising campaigns and brand proliferation has helped beer 

consumption grow. Wine, especially white wine, once just a dinner 

beverage, has become a cocktail beverage as well. 

4.3 ECONOMIC IMPACT ANALYSIS 

This section presents the analysis of economic impacts of an SO2 

alternative control level VI on industrial users of steam. The economic 

impact analysis is designed to determine if alternative SO2 emission 

regulations for new industrial boilers will severely affect either major 

steam users or selected industries. 

4.3.1 Major Steam Users Impacts 

The economic analysis of the major steam users focuses on costrelated impacts. Capital availability considerations are best examined 

on a firm level and, therefore, are covered only in the analysis of the 

six selected industries. 

The analysis of major steam users consists of four steps: 

• Step One -- Evaluate price impacts of alternative regulatory 

options on a general industry level assuming the costs of the 

regulatory option are passed completely to the consumer (i.e., 

full cost pass-through). 

• Step Two -- If price impacts are significant, evaluate the 

ability of the industry to pass through the entire costs. 

• Step Three -- If industry is able to pass through costs, 

assess the macroeconomic impacts of the price increase. If 

industry is unable to pass on the additional costs, assess the 

ability of the industry to absorb the additional costs. 

• Step Four -- If cost impacts are significant and the industry 

is unable to absorb the costs, further analysis is warranted 

for the impact on both the other industries (non-major steam 

users) and two-digit SIC industries. 

4-9 
P.53 

The first step of the analysis evaluates the price impacts of 

alternative regulatory options on major steam users. When price impacts 

are determined to be significant, they are evaluated in terms of the 

conditions contained in Steps Two through Four. 

The effect of a regulatory option on product price is calculated by 

finding the product of the change in the cost of new steam, the share of 

steam affected by the regulatory option, and the amount of steam 

consumed per dollar of output, as illustrated in Figure 2. The cost 

impacts are stated in real terms. The only real cost increase is 

assumed to be due to new boiler, pollution control, and fuel costs. All 

other production costs are held constant in real terms. 

A summary of the product price impact for SO2 alternative control 

level VI is found in Table 4-2. For each of the major steam users, the 

table shows: 

• The industry's ratio of steam consumption to dollar of product 

shipments (in MMBtu/$ of shipment) 

• Amount of total steam affected by the alternative SO2 emission 

standard 

• The change in the cost of steam for the reference fuel price 

scenario and higher oil and gas prices scenario 

• The estimated change in the product price under each fuel 

price scenario. 

The ratio of annual steam consumed (per unit output) to annual 

dollar value of shipment (per unit output) is computed by finding the 

quotient of annual steam consumption and the value of shipments. The 

ratio of annual steam consumed to annual dollar value of shipment by 

industry is assumed to remain constant over time. The estimated percent 

of steam affected by the alternative SO2 standard is based on the amount 

of new steam demand projected for the 1986-1990 period as a fraction of 

total steam demand for each industry group. This percentage gradually 

increases over time as more new boilers become operational. 

The alternative SO2 standard examined does not affect product price 

significantly. As Table 4-2 shows, the product price increase is less 

than 0.1 percent for all industries. This result is due primarily to 

the relatively small fraction of total product value accounted for by 

new steam. 

4-10 
FIGURE 2. CHANGE IN PRODUCT PRICE DUE TO REGULATORY OPTION 

Product 

kPrice 

i 

c . Steam ~ 

J/GJ (MMBtu) Steam/\^/Affected By\l f / Cost of \ / Cost of \ \ 

1\ Product Price /W^Regulatory Jf % 1 I New Steam) " I New Steaa) \ 

Option ' i I ' Regulatory ' Current J 

Option Regulation 

• GJ (MMBtu)/Steam Product Price 

Annual GJ (MMBtu) Steam/Annual Output (Total Number of Units) 

Annual $ Value of Shipments/Annual Output (Total Number of Units) 

• Steam Affected by Regulatory Option 

Steam Consumption Affected by Regulatory Option 

Total Steam Consumption 

• Cost of New Steam 

Total Annualized Cost of Steam 

GJ (MMBtu) 
TABLE 4-2. MAJOR STEAM USERS ECONOMIC IMPACTS1/ 

Industry 

Food 

Textiles 

Paper 

Chemicals 

Petroleum Refining 

Stone, Clay & Glass 

Steel 

Aluminum 

Other 

Total 

Steam/Product 

Price (MMBtu/$ 

of Shipments) 

.0035 

.0047 

.0204 

.0152 

.0042 

.0014 

.0060 

.0147 

.0008 

.0033 

% Steam 

Affected 

9 

3 

5 

1 

0 

0 

1 

1 

6 

8 

New Steam Cost Impact 

(Alternative SO2 NSPSBase Case) 

(1982 $/MMBtu) 

Reference 

fuel price 

scenario 

0.32 

0.58 

0.30 

0.25 

-

-

0.56 

0.17 

0.25 

0.27 

Higher 

oil and 

gas prices 

scenario 

0.10 

0.29 

0.07 

0.06 

-

-

0 

0 

.06 

.06 

Change in Product Price 

(Percent) 

Reference 

fuel price 

scenario 

0.01 

0.01 

0.03 

0.01 

-

-

0.01 

0.01 

0.01 

0.01 

Higher 

oil and 

gas prices 

scenario 

0.01 

0.01 

0.01 

0.01 

-

-

0 

0 

0.01 

0.01 

1/The base case assumes the 

alternative control level 

proposed PM and N0X NSPS 

VI (shown in Table 3-2). 

is in force. The alternative SO2 standard is 
P.56 

The major steam users in aggregate will not experience a significant impact. This does not mean, however, that a component of the major 

steam user Industry group will not be affected adversely. The selected 

industries study focuses both on industries from within the major steam 

users and from other manufacturing groups to assess whether smaller industry groups may be affected. 

4.3.2 Selected Industries Impacts 

The analysis of selected four-digit SIC industries forms the second 

part of the economic impact analysis. The major focus is the effect of 

the alternative NSPS on product cost, profitability, and capital availability for the firm. A small business analysis is also presented to 

evaluate the need for further review of the impacts under the Regulatory 

Flexibility Act. 

4.3.2.1 Cost and Profitability Impacts Methodology 

The following three steps are used to estimate the cost impact of 

regulatory options on a selected industry: 

t Step One -- Define a model plant for the selected industry 

• Step Two -- Evaluate the cost impacts for the model plant, 

assuming full cost absorption 

• Step Three -- Evaluate the impacts on the profitability of the 

model plant 

Each step is described below. 

Model plant. The selected industries analysis focuses on model 

plants to measure the economic impact of SO2 alternative control level 

VI on each industry. The model plant represents a typical plant for the 

segment of each industry that might be considering a boiler investment 

either as boiler expansion or replacement. A model plant is used since 

it is difficult to obtain precise details about the expansion and 

replacement plans of actual firms. 

This analysis presents economic impacts for the model plant assuming the decision has already been made in the base case to expand or 

to replace its existing boilers. However, decisions regarding plant 

investments, including new steam generating capacity, ultimately depend 

on the market conditions faced by each firm. If it appears that it 

would be too costly for a firm with declining sales or a low profit margin to invest in a new boiler(s) and the necessary pollution control 

equipment, the firm could elect to defer the investment. A decision to 

4-13 
defer the new boiler investment may be more attractive to the firm until 

the point at which it becomes too expensive to maintain the plant's existing boilers compared to replacing them with new units. The cost of 

installing and operating additional pollution control equipment to comply with the SO2 alternative control level might also contribute to the 

possibility that the firm would defer the new boiler investment. However, the decision concerning new steam generating units is expected to 

depend more on the investment in new boiler equipment than the pollution 

control equipment due to the relative magnitude of their respective 

costs. 

The fuel type burned in the existing boiler(s) of the model plant 

is determined by industry sources. The fuel type of the replacement or 

expansion boilers is based on industry trends and projections from IFCAM 

based on the combustor's size, location, and applicable energy and 

environmental regulations. 

The following production characteristics for the model plant are 

supplied: 

t Plant Output/Year -- average product output per year in those 

plants more 1ikely to invest in new boilers. 

• Price (Cost)/Unit of Output -- the historic, average selling 

price per unit, in reaT 1982 dollars. 

• Plant Sales/Year -- plant output per year multiplied by price 

per unit of output. 

• Plant Earnings/Year -- plant sales per year multiplied by a 

derived profit margin (percent return on sales). This figure 

estimates the profitability of the model plant. 

Product Cost Impacts: The effect of regulatory options on product 

cost is calculated by finding the product of the change in the cost of 

new steam, the share of steam affected by the new regulation, and the 

amount of steam consumed per dollar of output. The cost impacts are 

stated in real terms. The only real cost increase is due to new boiler 

and fuel costs; all other real production costs are held constant. 

It should be noted that the effect of the cost impact on product 

price is related to the market conditions for each firm and to what 

degree the firm behaves as a price-taken vs. a price-setter. The price 

impact is thus dependent on the extent that the firm is able to pass on 

the increased cost through increases in the price of its product(s). 

4-14 
P.58 

The impact on a plant's value added is also determined. Value 

added represents the portion of the total product value that can be attributed to the plant's non-raw material costs of manufacturing the product. It covers the remaining product value after the cost of all 

material inputs have been deducted. The value added per dollar of product for each selected industry has been calculated nationally using 

U.S. Census of Manufacture's data on a four-digit SIC basis. 

Profitability Impacts. The additional costs due to a regulatory 

option will affect the profitability of an industry. This impact will 

be assessed by examining the following two financial indicators for the 

model plant: 

• Net Profit After Taxes (Net Income). Profit after all costs 

and taxes have been deducted. 

• Return on Assets. Net income divided by total assets, 

converted to a percent form. 

The change in these indicators due to regulatory options is a measure of 

the ability of the model plant to absorb the additional costs of a 

regulatory option. 

4.3.2.2 Capital Availability 

Capital availability constraints may result if a regulatory option 

creates a need for financing additional pollution control investments. 

The firm is the focus of the capital availability analysis because decisions involving large capital expenditures are made at the corporate 

level. Depending upon the state of corporate cash reserves and the 

relative costs of various financing tools, a firm will choose a 

combination of internal and external financing instruments to meet the 

additional investments required to comply with regulatory option. 

The capital availability analysis focuses on the following two 

financial indicators, which ensure each industry's financing ability: 

• Coverage Ratio -- the number of times operating income 

(earnings before taxes and interest expenses) covers fixed 

obligations (annual interest on debt instruments and long-term 

leases) 

• Debt/Equity Ratio -- a measure of the relative proportions of 

two types of external financing. 

These two indicators are analyzed for both the base case and the 

regulatory options. The change in indicators due to the regulatory 

4-15 
P.59 

option is analyzed to determine how difficult it will be for the firm to 

meet financial requirements for the pollution control equipment investment. 

The cash flow coverage ratio is calculated by dividing operating 

income by fixed obligations, both of which could change as a result of 

alternative regulatory options. If the coverage ratio remains above the 

3.0 standard benchmark, the cost of capital can be assumed to be above 

"acceptable" levels. However, as the coverage ratio falls, the cost of 

obtaining capital will rise. 

The debt/equity ratio is calculated by dividing total debt by total 

equity of the firm (book values). The incremental debt incurred from 

financing the pollution control required by the regulatory option is 

added to the base case debt. A new debt/equity ratio then is calculated 

and the change is analyzed to assess the effect of the regulatory option 

on the firm's capital structure. 

4.3.2.3 Summary of Selected Industry Economic Impacts 

A summary of the key economic impacts results for selected industries is shown in Table 4-3. The impact on product cost and value added 

is less than 1.0 percent for all industries, except for beet sugar refining. The larger impact on the beet sugar refining model plant 

reflects the relatively large portion of product costs attributable to 

generating steam for the refining process. However, as discussed 

further below, this impact is not expected to have a significant effect 

on the beet sugar refining industry. The impact on the model firms return-on-assets for the selected industries is a decrease of 0.1 to 2.8 

percentage points. The largest impact on return-on-asset occurs for the 

model firm in the rubber reclaiming industry. 

A summary discussion of the impacts for each selected industry is 

presented below. 

4.3.2.4 Beet Sugar Refining Industry 

Model firm and plant description. The major characteristics of the 

model plant and firm for the beet sugar refining industry are listed in 

Table 4-4. The model firm is made up of four plants, which are located 

in the north central United States (Federal Region 8) . Each plant is 

identical in its steam use and product output. 

4-16 
TABLE 4-3. SUMMARY OF KEY ECONOMIC IMPACTS OF 

SO2 ALTERNATIVE CONTROL LEVEL VI 

ON SELECTED INDUSTRIES 

Selected Industry 

Beet Sugar Refining 

Increase in the model plant's: 

Product cost 

(percent) 

1.5 

Value added cost 

(percent) 

5.0 

Decrease in the model 

Firm's return on assets 

(percentage points) 

0.8 

1 

Rubber Reclaiming 

Auto Manufacturing 

Petroleum Refining 

Iron and Steel Mfg. 

Liquor Distilling 

0.5 

0.004 

0.02 

0.10 

0.12 

0.9 

0.12 

0.14 

0.25 

0.24 

2.8 

0.1 

0.1 

0.1 

0.3 
TABLE 4-4. MODEL FIRM AND PLANT CONFIGURATION: 

BEET SUGAR INDUSTRY 

P.61 

Model firm 

Financial data* 

Average bond rating: 

Coverage ratio: 

Debt/equity ratio: 

Model plant 

Production data* 

Plant output/year: 

Price/unit output: 

Plant sales/year: 

Plant earnings/year: 

Boiler configuration 

Total firing rate: 

No. of boilers: 

Federal region: 

Baa 

12.3 

0.25 

74,000 megagrams (81,000 tons)b 

$68.60/hundred kilogram wt.c 

($31.20/hundred pound wt.) 

$50.5 million

 c 

2.22 mi11ionc»

d 

114 MW (390 MMBtu/hr) 

3 

8 

Characteristics of individual boilers 

Boiler 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

1 

51 

(175) 

coal 

2 

51 

(175) 

coal 

3 

12 

(40) 

residual 

fuel oil 

Annual capacity utilization, percent 

Replacement, expansion 

or existing 

45 45 

replacement 

25 

existing 

*Based upon 1981 values. 

DBased upon the average production of the portion of the industry most 

likely to invest in a new boiler. 

Expressed in 1982 dollars. 

dBased upon the 1981 average return on sales ratio of 4.4 percent. 

4-18 
P.62 

Total annual firm production is 294,000 megagrams (324,000 tons) of 

sugar, with annual sugar sales at $207 million, assuming that beet sugar 

sells for $68.60 per hundred kilograms ($31.20 per hundred pounds) and 

that none of this sugar is added to existing inventories. Annual profits are 4.4 percent of total sales or about $2.2 million. 

The model plant boiler house consists of three fossil fuel-fired 

boilers with a total heat input capacity of 114 MW (390 MMBtu/hr). 

Table 4-4 describes the individual boilers. The two boilers being replaced have a heat input capacity of 51 MW (175 MMBtu/hr) and an annual 

capacity utilization of 45 percent. Approximately 90 percent of total 

steam generated for the plant is from these new boilers. The two new 

boilers are primarily used for process heat and electricity generation. 

Regulatory Impacts. In the base case, all the plant's boiler replacements are subject to an SO2 SIP emission regulation and the proposed PM/N0x NSPS for industrial boilers. Industry representatives expect that any new boilers of this size will fire coal. IFCAM projects 

that coal is the least-cost fuel type and that a low sulfur western coal 

is the least-cost coal type. A fabric filter will be installed to ensure that particulate emissions do not exceed the proposed PM standard 

in the base case. 

The projected economic impacts for the beet sugar model plant and 

firm are shown on Table 4-5. As a result of installing FGD equipment to 

comply with the alternative SO2 standard, beet sugar production costs 

for the model plant are estimated to increase 1.5 percent. The impact 

on the plant's value added portion of total production costs is 5.0 percent (using a value added-to-value of shipments ratio of 0.3). Based on 

a threshold standard of 5.0 percent for measuring the cost impact of a 

regulatory option, the impact on total plant production costs is within 

the range where adverse impacts are not expected to become significant. 

Since the product cost and value added impacts occur at only one of the 

firm's four plants, these costs could actually be factored into the 

firm's total beet sugar production and actually result in a lower overall price impact. 

The impact on the firm's net income, as shown in Table 4-5, reduces 

its annual income from $1.1 million to $0.7 million. This decrease in 

net revenues is estimated to lower the model firm's return-on-assets 

4-19 
P.63 

TABLE 4-5. ECONOMIC IMPACTS OF SO2 ALTERNATIVE CONTROL LEVEL VI FOR 

BEET SUGAR REFINING 

Percent increase in plant's product cost: 1.5 

Percent increase in value added cost: 5.0 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 1.1 

Alternative control level VI: 0.7 

Return on assets for firm (percent): 

Base Case: 2.3 

Alternative control level VI: 1.5 

Capital availability impacts: 

Coverage ratio: 

Percent financed by debt 

0* 100% 

Base Case: 12.33 9.07 

Alternative control level VI 12.33 8.95 

Debt/equity ratio: 

Base Case 0.217 0.361 

Alternative control level VI 0.217 0.366 

4-20 
P.64 

from 2.3 percent to 1.5 percent. Many beet sugar plants have been able 

historically to operate with low profit margins, since beet sugar 

growers in many cases cooperatively own the plant and maintain its 

operation to process their sugar beets. Beet sugar firms have been increasing their use of coal in their plants to help reduce energy costs 

and help maintain their profit margins. Even with the FGD requirement 

to meet the alternative SO2 standard, it is expected that the cost of 

using oil and gas over the long-run will be higher than installing coalfired boilers and the necessary pollution control equipment. Thus the 

lower rate of profits due to the alternative SO2 standard is expected to 

be less severe than if the plant continues to use its existing oil- or 

gas-fired boilers. 

The effect of the alternative SO2 standard on the model firms 

coverage ratio and debt/equity ratio are also presented in Table 4-5. 

There is a small decrease in the coverage ratio from 9.07 to 8.95 when 

100 percent debt financing is assumed. The ratios are well above the 

3.0 acceptable benchmark. The debt/equity ratio increases in the base 

case from 0.217 to 0.361 when comparing zero percent to 100 percent debt 

financing. However, the impact of increased debt financing due to the 

SO2 alternative standard has minimal effect on the debt/equity ratio and 

will not change this firm's ability to secure financing for the additional capital investment for SO2 pollution control equipment. 

It should be noted that the proposed standard is not expected to be 

the primary criterion in the decision to install a new steam plant. The 

firm will need to evaluate the investment as being cost-effective with 

or without more stringent emission regulations.1 Given the low rate of 

return in these firms, the major issue is whether any capital investment 

is justified, even with the intent of reducing energy costs by installing a coal-fired boiler. Under the alternative SO2 standard, the 

firm still would save energy costs in the long-term by installing the 

coal-fired boiler, although savings would be less than in the base case. 

4.3.2.5 Rubber Reclaiming Industry 

Model firm and plant description. Table 4-6 presents the model 

plant and firm for the rubber reclaiming industry. Each plant within 

the industry is assumed to be identical in its production process; each 

produces the same amount of output with equal amounts of steam. The 

4-21 
P.65 

TABLE 4-6. MODEL FIRM AND PLANT CONFIGURATION: 

RUBBER RECLAIMING INDUSTRY 

Model 

Model 

firm 

Financial data* 

Average bond rating: 

Coverage ratio: 

Debt/equity ratio: 

plant 

Production data* 

N. 

9 

0. 

A.b 

9 

24 

Plant output/year: 

Price/unit output: 

Plant sales/year: 

Plant earnings/year: 

Boiler configuration 

Total firing rate: 

No. of boilers: 

Federal region: 

18,100 megagrams (20,000 tons)c 

$0.53/kilogram ($0.24/pound)d 

$9.3 million

 d 

$0.49 milliond»e 

66.8MW (224 MMBtu/hr) 

3 

8 

Characteristics of individual boilers 

Boiler 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

Annual capacity utilization, percent 

Replacement, expansion 

or existing rep 

1 

29 

(100) 

coal 

45 

lacement 

2 

18.2 

(62) 

oil/gas 

45 

existing 

3 

18.2 

(62) 

oil/gas 

45 

a1978 values. 

bN.A. = Not available. 

cAverage of plant output/year for 1974 - 1978. 

•^Expressed in 1982 dollars. 

eBased upon the 1978 return on sales ratio of 5.2 percent. 

4-22 
P.66 

typical plant operates in the midwestern United States and has a yearly 

output of 18,100 megagrams (20,000 tons). The typical producer selling 

price is $0.53 per kilogram ($0.24 per pound), yielding sales of $9.3 

million. Applying an industry-wide profit margin of 5.2 percent of 

sales, the model plant earns $480,000 in profit. 

The typical plant's boiler house contains three boilers that have a 

combined firing capacity of 66 MW (224 MMBtu/hr). All boilers are 

assumed to operate at 45 percent of annual rated capacity. 

Regulatory Impacts. The replacement boilers under both the base 

case and the SO2 alternative standard is assumed to burn coal. In the 

base case, in order to meet the proposed PM/N0x emission regulation, the 

plant will install a fabric filter on the boiler. 

A summary of the economic impacts is presented in Table 4-7 for the 

rubber reclaiming industry model firm. The increase in the model 

plant's product costs and value added costs due to the SO2 control on 

the 100 MMBtu/hr boiler are both less than 1.0 percent. 

Table 4-7 includes the change in net income due to the alternative 

SO2 standard. The impact on profits assumes that sales are constant in 

real terms and that expenses rise only due to the new boiler investment 

for the 100 MMBtu/hr unit. Assuming a 50 percent corporate income tax, 

net income decreases from $210,000 in the base case to $60,000. Return 

on assets for the model plant decreases from 3.8 percent for the base 

case to 1.0 percent under the alternative SO2 standard. 

Table 4-7 also lists the rubber reclaiming industry's coverage 

ratio and debt/equity ratio for two financing options for the additional 

capital investment. The coverage and debt/equity ratios do not change 

significantly between the base case and the SO2 alternative standard 

case. These ratios do vary, however, depending on the financing 

strategy. For example, the coverage ratio decreases from 9.9 to 6.7 in 

the base case. While this represents a 32 percent decrease, the average 

ratio is still above the 3.0 standard benchmark. The debt/equity ratio 

for the alternative SO2 standard varies from 0.24 to 0.32 which is well 

below the 1.0 threshold level. The low long-term debt proportion suggests that the industry may have unused debt capacity. Assuming that 

the firm will finance externally, the majority of^the external funds may 

come from debt instruments. 

4-23 
P.67 

TABLE 4-7. ECONOMIC IMPACTS OF SO2 ALTERNATIVE CONTROL LEVEL VI FOR 

RUBBER RECLAIMING 

Percent increase in plant's product cost: 0.5 

Percent increase in value added cost: 0.9 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 0.21 

Alternative control level VI: 0.06 

Return on assets for firm (percent): 

Base Case: 3.8 

Alternative control level VI: 1.0 

Capital availability impacts: 

Coverage ratio: 

Percent financed by debt 

0% 100% 

Base Case: 9.9 6.7 

Alternative control level VI 9.9 6.6 

Debt/equity ratio: 

Base Case .24 .31 

Alternative control level VI .24 .32 

4-24 
P.68 

The results of the analysis indicate that the regulatory option 

cause percentage increases in product cost of one percent or less. Profits remain positive, although relatively low, under the alternative 

SO2 standard. Data on capital availability suggest that the firm will 

be able to finance the new boiler and control equipment investment under 

the alternative SO2 standard. 

The firm may elect to defer its investment in new boiler and pollution control equipment until its profit margin improves. But, as noted 

earlier, the installation of a new coal-fired boiler should reduce 

energy costs in the long-term, even though those savings would be reduced by the added cost of complying with the alternative SO2 standard. 

4.3.2.6 Automobile Manufacturing Industry 

Model firm and plant description. The model firm and plant 

configuration for the automobile manufacturing industry is presented in 

Table 4-8. The plant that operates in Federal Region 5 is assumed to be 

part of a 26-plant firm. Total firm production is 2,340,000 vehicles, 

with annual car and light truck sales of $20.4 billion, assuming an 

average price (1982 dollars) of $8,670 per vehicle. These production 

statistics do not include foreign-made cars (such as the Dodge colt or 

the Chevrolet Sprint) normally part of the United States automobile 

companies' fleets. Because these cars are not produced in this country, 

their production costs would not be affected by alternative regulatory 

options. Net profit for the model firm is assumed to be 4.28 percent of 

total sales, or $873 million. 

The model plant boiler house consists of four coal-fired boilers 

with a total heat input capacity of 106 MW (361 MMBtu/hr). The boiler 

investment decision is to replace one of these units with a similarly 

sized new coal-fired boiler. 

Regulatory Impacts. In the base case, the plant's boiler replacement must comply with SO2 SIP air emission limits and the proposed 

PM/N0x NSPS. Based on historical industry trends, the fuel for the new 

boiler is projected to be coal. In the base case, the plant will 

install a fabric filter for PM control. A once-through sodium FGD will 

be installed to comply with the alternative SO2 standard. 

4-25 
TABLE 4-8. MODEL FIRM AND PLANT CONFIGURATION: 

AUTOMOBILE MANUFACTURING INDUSTRY 

P.69 

Model firm 

Financial data* 

Average bond rating: 

Coverage ratio: 

Debt/equity ratio: 

Model plant 

Production data* 

Plant output/year: 

Price/unit output: 

Assembly plant sales/yr: 

Assembly plant earnings/ 

year: 

Aaa/B 

20.17 

0.11 

Boiler configuration 

Total firin g rate: 

No. of boilers : 

Federal region: 

90,130 automobiles0 

$8,686 automobilec 

$782.9 million 0 

$33.5 million c»

d 

106 MW (361 MMBtu/hr) 

4 

5 

Characteristics of individual boilers 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

Annual capacity utilization, percent 

Replacement, expansion 

or existing 

Boiler 

1 

25.5 

(87) 

coal 

0

e 

2 

25.5 

(87) 

coal 

25 

existing 

3 

25.5 

(87) 

coal 

25 

4 

29 

(100) 

coal 

25 

replacement 

a1978 values. 

°Based upon average industry estimates. 

Expressed in 1982 dollars. 

dBased upon the 1978 return on sales ratio of 4.28 percent. 

eBoiler number one is used as a standby boiler. 

4-26 
P.70 

The estimated economic impacts for the auto industry model firm are 

summarized in Table 4-9. Production cost and value added impacts are 

negligible (i.e., less than 0.1 percent). 

Table 4-9 shows the change in profit margin for the automotive 

industry. Because the boiler investment is such a small fraction of 

total expenses, the net income changes due to a regulatory option are 

small compared to the base case. The alternative SO2 standard results 

in a less than one percent decline in net income compared to the base 

case. Return on assets remains constant at 9.17. 

The coverage and debt/equity ratios for the autombile manufacturing 

industry are also shown in Table 4-9. The coverage ratio declines 

slightly from 20.17 to 20.10. The debt/equity ratio remains at 0.11. 

Neither of these ratios suggests problems in obtaining capital in either 

of the regulatory options. Since these rates show a low percentage of 

debt, future investments could be funded largely from debt, depending 

upon the interest rate and the industry's inclination toward debt 

financing. 

The results of the analysis indicate that the alternative SO2 standard does not significantly affect any of the above financial 

parameters. The impact on product cost is negligible due to the low 

ratio of new steam cost to total dollar output. Capital availability is 

not constrained by any of these cases, suggesting that the firm will be 

able to finance a new boiler replacement. 

4.3.2.7 Petroleum Refining Industry 

Model firm and plant description. Table 4-10 presents the model 

firm and plant for the petroleum refining industry. This plant, 

operating in the Southwest (Federal Region 6) , is assumed to be part of 

a seven-plant firm. Total production for the model firm is 112.93 

million barrels of refined product per year. Assuming a price of 

$33.65 per barrel and an annual net profit margin of 4.51 percent, the 

firm realizes annual sales of $3.8 billion and annual profits of $171.4 

million. Comparing these figures to 1978 U.S. refined product 

consumption, this firm satisfies approximately two percent of total 

demand and accounts for about four percent of the domestically refined 

petroleum products market. 

4-27 
P.71 

TABLE 4-9. ECONOMIC IMPACTS OF S02 ALTERNATIVE CONTROL LEVEL VI FOR 

AUTOMOBILE MANUFACTURING 

Percent increase in plant's product cost: .004 

Percent increase in value added cost: .012 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 37.8 

Alternative control level VI : 37.6 

Return on assets for firm (percent): 

Base Case: 9.17 

Alternative control level VI : 9.14 

Capital availabilit y impacts: 

Coverage ratio : 

Percent financed by debt 

0% 100% 

Base Case: 20.17 20.10 

Alternative control level VI 20.17 20.10 

Debt/equity ratio: 

Base Case .11 .11 

Alternative control level VI .11 .11 

4-28 
P.72 

TABLE 4-10. MODEL FIRM AND PLANT CONFIGURATION: 

PETROLEUM REFINING INDUSTRY 

Model firm 

Financial data* 

Average bond rating : Aaa/A 

Coverage ratio : 14.12 

Debt/equity ratio : 0.32 

Model plant 

Production data* 

Plant output/year: 16,133 barrels 

Price/unit output: $33.65 per barrel 0'

0 

Plant sales/year: $543.9 million 0 

Plant earnings/year: $24.5 million°»d 

Boiler configuration 

Total firin g rate: 381.0 MW (1300 MMBtu/hr) 

No. of boilers : 4 

Federal region: 6 

Characteristics of individual boilers 

Boiler 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

1 

95.2 

(325) 

refinery 

gas 

75 

2 

95.2 

(325) 

refinery 

gas 

75 

existing 

3 

95.2 

(325) 

natural 

gas 

75 

4 

95.2 

(325) 

coal 

75 

replacement 

Annual capacity utilization, percent 

Replacement, expansion 

or existing 

a1978 values. 

°The price per unit output is based upon the average price for all 

v refined products. 

°Expressed in 1978 dollars. 

dBased upon the 1978 return on sales ratio of 4.51 percent. 

4-29 
P.73 

The model plant boiler house consists of four boilers, with a total 

heat input capacity of 381 MW (1,300 MMBtu/hr). Each boiler has a 

firing capacity of 95 MW (325 MMBtu/hr) and is used at 75 percent of 

heat input capacity. Three of the boilers are existing units, firing 

refinery and natural gas. The fourth unit, firing a mixture of 

petroleum coke and residual oil, will be replaced by a new coal-firing 

boiler in 1990. Approximately 25 percent of boiler steam generation for 

this plant will be provided by the new coal-firing boiler. 

Regulatory Impacts. Historically, a significant share of the 

boiler fossil fuel demand in the petroleum refining industry has been 

met with the use of liquid, solid, and gaseous waste by-products of 

refinery operations. Because the focus of this analysis is on the 

choice between coal, oil, and gas, the fuel type for the new boiler is 

limited to these fuels. The new boiler under both the base case and the 

alternative SO2 standard is assumed to burn coal. 

Table 4-11 presents the change in product cost and value added for 

the refining plant due to the alternative SO2 standard. Assuming 100 

percent cost pass-through, the price impact is less than 0.1 percent. 

This small percentage is due primarily to the small fraction that new 

steam costs comprises of total product cost. Table 4-11 also shows that 

net income for the refinery company decreases about one percent to $33.3 

million. 

The coverage and debt/equity ratios for the model petroleum 

refinery indicate that neither the regulatory option nor the financing 

strategy affect these ratios significantly. The coverage ratio 

decreases from 14.12 to 14.08, or less than 0.3 percent. The 

debt/equity ratio remains at 0.32 under all financing options. 

The results of the analysis indicate that the alternative SO2 standard does not result in significant cost impacts on the petroleum 

refining industry. Profitability is affected only slightly by the 

incremental expenses due to new boiler investment. Return on assets, 

however, remains at 5.9 percent under the base case and alternative SO2 

standard. 

Capital availability appears to be stable for the petroleum 

refining industry. The coverage ratio is sufficiently high to assume 

4-30 
P.74 

TABLE 4-11. ECONOMIC IMPACTS OF SO2 ALTERNATIVE CONTROL LEVEL VI FOR 

PETROLEUM REFINING 

Percent increase in plant's product cost: .02 

Percent increase in value added cost: .14 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 33.6 

Alternative control level VI : 33.3 

Return on assets for firm (percent): 

Base Case: 5.98 

Alternative control level VI : 5.93 

Capital availabilit y impacts: 

Coverage ratio : 

Percent financed by debt 

0% 100% 

Base Case: 14.12 14.08 

Alternative control level VI 14.12 14.08 

Debt/equity ratio: 

Base Case .32 .32 

Alternative control level VI .32 .32 

4-31 
that the refinery will not have problems obtaining external funds for 

the boiler investment. 

4.3.2.8 Iron and Steel Manufacturing Industry 

Model firm and plant description. Table 4-12 depicts the model 

firm and plant for the integrated iron and steel industry. This plant 

is assumed to be part of a five-plant firm, located in the midwestern 

States. Total production for the model firm is 8.2 million megagrams 

(9.0 million tons) of raw steel per year. Assuming a real price of $534 

per megagram ($480 per ton) and an annual net profit margin of 2.9 percent, the firm realizes annual sales of $4.3 billion and annual profits 

of $126.4 million. 

The model plant boiler house consists of four boilers with a total 

heat input capacity of 216 MW (736 MMBtu/hr). Three of the boilers have 

a capacity of 40 MW (137 MMBtu/hr) and the fourth has a capacity of 95 

MW (325 MMBtu/hr). All the boilers currently fire blast furnace gas and 

have an annual capacity utilization of 55 percent. The three 40 MW 

boilers are retired and assumed to be replaced by three similarly sized 

coal-fired boilers. Approximately 55 percent of boiler steam generation 

for this plant will be provided by the new coal-fired boilers. To 

comply with the alternative SO2 standard, a once-through sodium FGD 

system is installed. 

Regulatory Impacts. Table 4-13 indicates that there is no significant change in product cost, value added, or profitability for the 

industry as a result of the changes in cost of new steam. The 

profitability analysis for the base case and alternative SO2 standard 

assumes that sales are held constant in real terms and that expenses 

increase only as a result of new boiler investment. This incremental 

expense is assumed to be absorbed by the firm and is not passed on to 

the consumer. Given this assumption, net income is $24.0 million in the 

base case and $23.4 million in the alternative SO2 standard case. 

Return on assets decreases from 3.36 percent to 3.28 percent. Because 

of the relatively large sales and expense base for the industry, the 

incremental expense brought about by the increase in new steam cost of 

the alternative SO2 standard does not significantly affect the firm's 

profitabi1ity. 

4-32 
TABLE 4-12. MODEL FIRM AND PLANT CONFIGURATION: 

IRON AND STEEL MANUFACTURING INDUSTRY 

Model firm 

Financial data* 

Average bond rating: 

Coverage ratio: 

Debt/equity ratio: 

Model plant 

Production data* 

Plant output/year: 

Price/unit output: 

Plant sales/year: 

Plant earnings/year: 

Boiler configuration 

Total firing rate: 

No. of boilers: 

Federal region: 

N.A.° 

6.09 

0.52 

1,632,600 megagrams 1,800,000 tons) 

$534 megagram (484 per ton)0 

$870.7 million ° 

$25.3 million°»d 

215 MW (736 MMBtu/hr) 

4 

5 

Characteristics of individual boilers 

Boiler 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

Annual capacity utilization, percent 

Replacement, expansion 

or existing 

1 

40.1 

(137) 

coal 

55 

2 

40.1 

(137) 

coal 

55 

replacement 

3 

40.1 

(137) 

coal 

55 

4 

95.2 

(325) 

blast 

furnace 

gas 

55 

existing 

a1978 values. 

°N.A. = Not available. 

Expressed in 1982 dollars. 

dBased upon the 1978 return on sales ratio of 2.9 percent. 

4-33 
P.77 

TABLE 4-13. ECONOMIC IMPACTS OF SO2 ALTERNATIVE CONTROL LEVEL VI FOR 

IRON AND STEEL 

Percent increase in plant's product cost: 0.1 

Percent increase in value added cost: 0.25 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 24.0 

Alternative control level VI: 23.4 

Return on assets for firm (percent): 

Base Case: 3.36 

Alternative control level VI: 3.28 

Capital availability impacts: 

Coverage ratio: 

Percent financed by debt 

0% 100% 

Base Case: 6.09 5.82 

Alternative control level VI 6.09 5.80 

Debt/equity ratio: 

Base Case .52 .52 

Alternative control level VI .54 .54 

4-34 
P.78 

Table 4-13 also shows that coverage and debt/equity ratios do not 

vary significantly as a function of the regulatory option. The coverage 

ratio decreases from approximately 6.09 with zero percent debt financing 

to approximately 5.82 with 100 percent debt in the base case. The 

alternative SO2 standard will reduce the coverage ratio to 5.82 under 

the 100 percent debt financing case. The debt/equity ratios vary from 

0.52 to 0.54 for the various financing strategies. 

The results of the analysis indicate that the regulatory options 

cause low percentage increases in product cost. New steam costs for the 

regulatory options comprise a relatively small portion of average 

product cost. Profitability likewise is affected slightly by the 

incremental expenses due to new boiler investment. 

With regard to financing capability, the analysis of coverage 

ratios indicates that new boiler investment can be funded with up to 100 

percent debt. The 3.0 coverage benchmark is always exceeded even when 

total debt financing is assumed. This firm's solvency position remains 

stable even when total debt financing is undertaken. Due to the 

industry's large equity base, the debt ratios do not exhibit wide 

variances as a result of the two financing options. 

4.3.2.9 Liquor Distilling Industry 

Model firm and plant description. The model plant and boiler configuration of the liquor distilling industry is shown in Table 4-14. It 

is assumed that the typical firm operates three plants. The model plant 

is located in a southeastern State and produces 17 million liters (4.5 

million gallons) of distilled liquor annually. 

The model plant operates two boilers, one rated at 29 MW (100 

MMBtu/hr), the other at 18 MW (62 MMBtu/hr), with a total firing 

capacity of 47 MW (162 MMBtu/hr) and 45 percent capacity utilization. 

The model plant elects to replace the larger natural gas/oil-fired 

boiler with an identically configured coal-fired boiler. 

Regulatory Impacts. The model plant replacement boilers for the 

liquor distilling industry are assumed to be coal-fired. To meet the 

proposed PM/N0x NSPS in the base case, a fabric filter is installed for 

PM control. 

Table 4-15 illustrates the changes in product cost, value added, 

and profitability due to the SO2 alternative standard. Sales are 

4-35 
P.79 

^rggg 

\ty 

TABLE 4-14. MODEL FIRM AND PLANT CONFIGURATION: 

LIQUOR DISTILLING INDUSTRY 

Model firm 

Financial data* 

Average bond rating : N.A.° 

Coverage ratio : 5.44 

Debt/equity ratio : 0.292 

Model plant 

Production data* 

Plant output/year: 17.0 millio n liter s (4.5 millio n gallons) 

Price/unit output: $2.31 lite r ($8.27/gallon) ° 

Plant sales/year: $39.2 millio n ° 

Plant earnings/year: $1.68 million°» d 

Boiler configuration 

Total firin g rate: 47.3 MW (162 MMBtu/hr) 

No. of boilers : 2 

Federal region: 4 

Characteristics of individual boilers 

Boiler 

Capacity, MW 

(MMBtu/hr) 

Fuel type 

Annual capacity utilization, percent 

Replacement, expansion 

or existing 

1 

29 

(100) 

coal 

45 

replacement 

2 

18.2 

(62) 

oil/gas 

45 

existing 

a1978 values. 

bN.A. = Not available. 

cExpressed in 1982 dollars. 

dBased upon the 1978 return on sales ratio of 2.9 percent. 

4-36 
P.80 

TABLE 4-15. ECONOMIC IMPACTS OF SO2 ALTERNATIVE CONTROL LEVEL VI FOR 

LIQUOR DISTILLING 

Percent increase in plant's product cost: 0.12 

Percent increase in value added cost: 0.24 

Model firm: 

Net income after taxes (IO6 1982 $) 

Base Case: 0.29 

Alternative control level VI: 0.17 

Return on assets for firm (percent): 

Base Case: .68 

Alternative control level VI: .37 

Capital availability impacts: 

Coverage ratio: 

Percent financed by debt 

0% 100% 

Base Case: 5.44 4.32 

Alternative control level VI 5.44 4.26 

Debt/equity ratio: 

Base Case .29 .36 

Alternative control level VI .29 .37 

4-37 
P.81 

assumed to be constant in both regulatory options, and expenses increase 

only as a result of the new boiler investment. Net income level 

decreases from $290,000 in the base case to $170,000 under the SO2 

alternative standard. Return on assets is 0.68 percent in the base case 

and 0.37 percent under the alternative SO2 standard. 

Table 4-15 also presents comparative coverage and debt/equity 

ratios for the alternative SO2 standard. These results show the 

coverage ratio in the base case decreasing from 5.44 with zero percent 

new debt to 4.32 with 100 percent debt. The coverage ratio decreases 

from 5.44 to 4.26 for zero and 100 percent financing under the 

alternative SO2 standard. However, both coverage ratios are still above 

the 3.0 coverage benchmark. 

The results of the analysis indicate that product cost is expected 

to increase by slightly over one-half of a percent. New steam costs for 

the alternative SO2 standard comprise a relatively small portion of 

average product cost. Profitability shows a decline as a result of the 

SO2 regulatory option when compared to the base case. Return on assets 

decreases from 0.68 percent in the base case to 0.37 percent. 

The firm may elect to defer its investment in new boiler and pollution control equipment until its profit margin improves. But, as noted 

earlier, the installation of a new coal-fired boiler should reduce 

energy costs in the long-term, even though those savings would be 

reduced by the added cost of complying with the alternative SO2 

standard. 

With regard to financing capability, the analysis of coverage 

ratios indicates that new boiler investment can be funded totally by 

debt while still meeting the 3.0 coverage benchmark. The industry 

maintains a relatively stablized solvency position even when 100 percent 

debt financing is assumed. 

4.3.3 Small Business Analysis 

The effects of SO2 standards on small businesses are considered in 

this section. For six of the seven industries, small plants are characterized in Table 4-16. 

For beet sugar, iron and steel, distilled liquor, and petroleum 

refining, average-size small plants are examined. Using 1977 Census 

data on plant sales and the Small Business Administration's definition 

4-38 
P.82 

TABLE 4-16. SMALL PLANTS 

IN SELECTED INDUSTRIES 

Small plant characteristics 

Average sales0 

SIC) Max. employees3 (IO6) (MMBtu/hr) 

23.1 175 

14.2 125 

22.7 125 

224.1 100 

Beet sugar (1063) 

Iron and steel (3312) 

Distilled liquor (2085) 

Petroleum refining 

(2911) 

Auto manufacturing 

(3711) 

Reclaimed rubber (3031) 

Fruit and vegetable 

canning (2033) 

750 

1,000 

750 

1,500 

1,000 

750 

500 

252. ld 100d 

9.3e 224e 

NAf NAf 

aSmall Business Size Standards, SBA Rules and Regulations. July 15, 1980 

45FR47415. Schedule A. Definition of Small Business for the Purpose of 

Pollution Control Guarantee Assistance under PL94-305. Section 121.3-16. 

°Except as noted, small plant sales represent the average sales of small 

plants in the 1977 Census of Manufacturers, converted to 1982 dollars using 

the GNP price deflator. 

°Boiler sizes for small plants are estimated using the same heat intensities 

as at the large plants in each industry. 

dThe small plant shown is that which would need a 100 MMBtu/hr boiler. 

eThe average plant in this industry is a small plant. 

^Not applicable. Plants are fired by natural gas and are consequently not 

likely to be affected by the SO2 standards. 

4-39 
-JEJL-

- <.£_ -^^",—•-• - -^ 

of small plants in each industry (a maximum of 750 to 1,500 employees), 

the averag^saTes per plant was calculated among all plants classified 

as smalfc-Wfceach Industry. In turn, sales were converted to 1982 

dollars using the GNP price deflator. 

Corresponding boiler capacities were estimated for such small 

plants by using the boiler heat intensities per dollar of product 

described earlier for large plants in the same industries. 

The same procedure was followed to estimate the size of a small 

automobile manufacturing plant; however, the average small plant would 

have only a three MMBtu/hr boiler. The small plant used instead in this 

analysis is scaled up to the size that uses a 100 MMBtu/hour boiler; 

this is still within SBA's definition of small for that industry. 

In the case of reclaimed rubber, it was found that the average 

plant analyzed in Section 4.3.2.5 was already a small plant, and that 

further analysis of this industry is not needed in this section. 

Fruit and vegetable canning plants also are not analyzed in this 

section, because they burn natural gas in their boilers and therefore 

would not be affected by standards for SO2 emissions. 

Potential impacts for small plants in the first five industries are 

summarized in Table 4-17. The results show how small plants would be 

affected and address EPA's four guideline criteria for determining 

whether a Regulatory Flexibility Analysis is needed: 

• Annual compliance costs are compared to base case production 

costs (sales, less net income and taxes); 

• Annual compliance costs as a percentage of sales are compared 

for small versus large plants (model plants from the BIDs); 

• The debt-to-equity ratio with control equipment outlays 

financed entirely from debt is compared with the base case 

ratio to assess capital adequacy; 

• Net income as a percent of sales is measured to determine 

plant profitability (or closure) with full absorption of the 

annualized compliance costs. 

Results for small plants in each of the five industries showed that 

no industry would need a formal Regulatory Flexibility Analysis. 

Annualized compliance costs range from 0.1 to 2.9 percent of production 

4-40 
TABLE 4-17. INDUSTRIAL BOILERS NSPS 

SMALL BUSINESS IMPACT ANALYSIS TO STUDY NEED FOR A REGULATORY FLEXIBILITY ANALYSIS 

Selected industries 

Product cost impact 

for average small plant3 

(percent) 

Total annualized cost as 

percent of sales for small 

and large model plants: 

Small Plant Large Plant0 

Debt/equity ratios for 

small firm under base case 

and alternative 

standard 

Alternative 

Base Case Standards 

Net income as percent of 

sales to gauge the 

Potential for plant closurec 

i 

Beet sugar. SIC 2063 1.7 

Iron and steel, SIC 3312 2.9 

Distilled liquor, SIC 2045 1.4 

Petroleum refining, SIC 2911 0.1 

Auto manufacturing, SIC 3711 0.1 

1.7 

2.8 

1.3 

0.1 

0.1 

1.5 

0.1 

0.1 

0.0 

0.0 

0.22 

0.52 

0.29 

0.32 

0.11 

0.48 

0.69 

0.36 

0.33 

0.12 

0.5 

1.2 

1.9 

4.4 

4.2 

^Product cost impact is calculated by dividing the increase in total annualized costs due to additional pollution control 

equipment by the annual production costs for the average small plant. 

DLarge plant data is based on Table 4-3. 

cAssuming full cost absorption after controls. 

WI 

u oo 
costs at the five industries, below EPA's guideline threshold of five 

percent. Annualized compliance costs as a percentage of sales at small 

versus large plants similarly do not exceed EPA's guidelines. The 

differential for small plants ranges from 0.1 to 2.7 percentage points, 

below EPA's guideline level of 10 percentage points. 

The debt-to-equity ratio remains below 1.0, the benchmark used in 

the BID. Assuming that capital investments for SO2 emissions control 

are financed 100 percent by debt, the debt ratios of the controls range 

from 0.12 to 0.69. This shows residual capital availability for small 

plants even after compliance with the standards. 

Finally, no small plants would likely close due to the recommended 

standards. Net income with full absorption of compliance costs would 

remain positive. New income as a percent of sales ranges from 0.5 to 

4.4 percent of sales. 

In sum, none of EPA's guidelines for a formal Regulatory 

Flexibility Act Analysis is triggered in the analysis of small plant 

impacts. 

4-42 
P.86 

APPENDIX A 

OVERVIEW OF IFCAM 

A.l PURPOSE 

The Industrial Fuel Choice Analysis Model (IFCAM) is an energy demand 

model developed by Energy and Environmental Analysis, Inc. (EEA) to evaluate 

fuel choice decisions in the industrial sector over a five to 15-year forecasting horizon. IFCAM is a highly disaggregated process engineering model* 

designed to analyze factors affecting fuel choice decisions in industrial 

boiler energy applications. 

IFCAM assesses the impacts of four sets of factors affecting industrial 

fuel choice: fuel prices, State and Federal energy and environmental policy 

proposals, the costs associated with firing alternate fuels, and other key 

model parameters such as the expected size distribution of new industrial 

boilers. The model is capable of estimating the energy, environmental, and 

cost impacts of alternative air emission regulations for new industrial 

boilers. 

A.2 ANALYTICAL FRAMEWORK 

A.2.1 Summary of Approach 

IFCAM focuses on boiler fuel choice decisions between coal, oil, and 

natural gas. The model determines fuel choices for boilers in each of the 

10 Federal regions using projected industrial fuel prices and total fossil 

•Process engineering models simulate the effects of specific policies on 

new and existing technical alternatives through the application of direct 

engineering information. Other types of models are: econometric 

(mathematical equations solved simultaneously with coefficients estimated 

statistically from historical data); optimization (derivation of "best" 

solutions by means of algebraic procedures such as linear programming); 

simulation or systems dynamics (mathematical equations solved recursively 

with coefficients estimated from modeler's experience and intuition). 

A-l 
fuel demand that primarily have been generated by the U.S. Department of 

Energy (DOE). IFCAM does not consider feedstock energy uses such as 

metallurgical coal or raw materials derived from petroleum or natural gas 

in the chemical industry. 

A very disaggregate representation of industrial energy uses is 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 by new and existing 

boilers of different sizes and capacity utilizations rates. New and 

existing boilers are classified on the basis of the type of fuel they were 

designed to fire and whether they can be retrofitted to fire alternative 

fuels. Eight size classes are delineated for boilers. There are five 

capacity utilization rate categories for boilers. 

The final level of disaggregation incorporates regional detail. Industrial boiler fuel use is divided among Air Quality Control Regions (AQCR's). 

Since a large number of regions are considered by IFCAM, the model can 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 development stage. 

Based on the characteristics of each combustor (size, operating rate, 

pollution control requirements, etc.), capital and nonfuel operating costs, 

are generated for the options of choosing oil, gas, or coal. The fuel type 

associated with the lowest after-tax present value (including expected fuel 

expenses) of the total cost of generating energy over the investment period 

is selected. 

The model generates energy, environmental, and cost impacts. Outputs 

include regional industrial boiler fossil energy demands by fuel type, air 

emissions, solid waste disposal requirements, energy penalties associated 

A-2 
P.88 

with the operation of pollution control equipment, demand for new pollution 

control equipment and boilers by size and type, and total costs (capital, 

annual operating, maintenance and fuel expenses) of using fossil energy to 

generate steam. 

A.2.2 Capabilities 

Four classes of energy policy measures can be analyzed with IFCAM: 

fuel taxes, investment incentives, energy regulatory policies, and environmental regulatory policies. A variety of tax credits and changes in the 

tax treatment of capital proposed to provide incentives to invest in coalrelated 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. The provisions of FUA are not applied in this 

impact analysis of New Source Performance Standards (NSPS) for industrial 

boilers. 

Environmental regulatory policies that could affect fuel choice 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 particulate matter (PM), sulfur dioxide (SO2), and 

nitrogen oxide (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 

(FGD) 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. IFCAM's 

scrubber cost estimates are unique for each coal type and SO2 emission 

regulation. 

Several types of alternative NSPS specifications of SO2 emissions 

control for industrial residual fuel oil and coal-fired boilers can be 

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

specified as: 

A-3 
P.89 

0 A ceiling emission rate (ng of pollutant/Joule (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/J (0.6 

lb/MMBtu)) 

• A minimum percentage removal to be applied if the recommended 

percentage removal results in controlled emission rates lower 

than the "floor" 

IFCAM can simulate the impact of alternative fuel price scenarios on 

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

residual fuel oil (four sulfur classes), natural gas, and coal (9 types) 

are considered in the model. 

The fuel choice decision is sensitive to non-fuel costs of burning 

alternate fuels. While the best available cost data are used, the model 

can evaluate the impact of any alternative cost estimates. 

In addition to these three sets of factors, many other key variables 

affect fuel use. The model is designed, for example, to evaluate the 

effects of varying industrial production growth rates, and to alter the 

distribution of size and operating characteristics of new boilers. 

A.2.3 Model Logic 

Figure A-l outlines the model structure and identifies key inputs, 

outputs, and major analytical steps. 

Inputs 1, 2, and 3 - Enerqy Demand and Industrial Production: The 

level of industrial fossil fuel demand and nine industrial production growth 

rates by region are critical inputs to IFCAM. Although such inputs can be 

derived from many sources, in the past they have been taken from the Energy 

Consumption Data Base (ECDB), DOE projected industrial energy use, and the 

macroeconomic model that drives the DOE modeling framework. 

Model Step #1 - Characterize Industrial Enerqy Use: This initial step 

breaks down the projected fossil fuel use by industrial sector, new and 

existing facilities, type of combustor (e.g., boiler versus process heater), 

size of boiler, and a variety of other classifications. These factors, 

discussed below, are significant because they: 

A-4 
I 

Input 2 

Industrial Production" 

Growth Rates 

Input 1 

Industrial Fossil 

Fuel Use in 1974 

CHARACTERIZE 

FUEL 

CONSUMPTION 

Input 3 

Projected Industrial^ 

Jossil Fuel Demand/ 

Input 6 

Environmental 

Regulations 

Input 8 

Energy Policy 

Input 4 

Geographic 

Distribution of Boilers 

£ 

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 

t Input 10 

Capital and 

O&M Cost Data 

FIGURE A-1 

IFCAM MODEL STRUCTURE 

TJ 

P 
P.91 

• Alter the costs of using alternate fuels (e.g., fuel costs vary 

according to industrial location) 

• Determine the economics of fuel choice (considering such factors 

as the boiler's capacity utilization rate) 

• Distinguish elements of energy use specifically targeted by 

energy policy measures (e.g., new boilers above a cutoff size). 

Inputs 4 and 5 - Geographic and Boiler Size/Capacity Utilization 

Distributions: The geographic and boiler size/capacity utilization 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 and fuel type on an AQCR basis. 

Model Step #3 - Identify Environmental Requlations 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. Available pollution control technologies are identified in 

Table A-l. Compliance options are identified for each fuel type. 

Inputs 7, 8, and 9 - Fuel Prices, Enerqy Policy, and Financial 

Parameters: Specifications for a particular model run and projection year 

are incorporated at this step. Specifications include the fuel price 

scenario, financial parameters, and energy regulatory policies. 

Fuel price variations are used in IFCAM to model fuel taxes, natural 

gas price deregulation, or variations in price trajectories. Fuel prices 

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

classes), coal (9 coal types), and natural gas. The price of each fuel 

type can differ by region. 

Investment incentives considered have focused primarily on differential depreciation methods for coal-, oil-, or gas-fired units and on 

A-6 
P.92 

TABLE A-l. INDUSTRIAL BOILER POLLUTION CONTROL TECHNOLOGIES 

IN IFCAM 

Pollutant Technology options 

SO2 Flue gas desulfurization 

- dual alkali9 

- lime spray drying0 

- sod i um 

PM Single mechanical collector 

Dual mechanical collector 

Side stream separator 

Electrostatic precipitator 

Fabric filter 

NOv Combustion modifications 

- low excess air 

- staged combustion air 

Tray type scrubber. 

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

A-7 
P.93 

increased investment tax credits (ITC's) for coal-derived fuel firing. The 

impacts of different depreciation methods and investment incentives are 

handled within the scope of the main model logic. 

The coal conversion regulatory program established under the FUA targets 

boilers whose rated capacity is greater than 29 MW (100 MMBtu/hr) heat input. 

An economic test compares the total cost (capital, annual O&M and fuel) of 

burning coal to the total cost of burning imported oil to simulate legislative provisions related to economic exemptions. This procedure projects 

the level of increased coal use under the program, excluding any implementation problems. As noted earlier, the coal conversion economic test option 

in IFCAM is not currently utilized in evaluating alternative NSPS's for 

industrial boilers. 

Input 10 - Capital and O&M Cost Data: Capital and O&M cost data relative to the range of boiler and pollution control equipment modeled in IFCAM 

are derived from numerous sources. Engineering cost data is revised on an 

as-needed basis when current estimates are refined or new estimates become 

available. 

Model Step #4 - Evaluate Economics of Fuel Choice: Based on the 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 present value (including capital and annual O&M and fuel 

expenses) of the cost of generating energy over the investment period then 

is selected. 

The components of Net Present Value (NPV) can be divided into three 

major subsets: policy inputs, standard model assumptions, and key model 

variables. Policy inputs are depreciation life and method, ITC, and fuel 

prices. Standard model assumptions are construction period and corporate 

tax rate. These elements do not vary by boiler characteristics and 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). 

A-8 
P.94 

A.3 KEY DATA INPUTS 

This section summarizes key assumptions used in this analysis. These 

estimates may be revised in future model runs. 

A.3.1 Cost Algorithms 

The capital and operating costs of new boilers and associated pollution control equipment have been developed by several contractors. These 

costs were generalized to be expressed as algorithms. The algorithms are 

functions of a number of significant parameters. 

The capital cost estimates include all installation costs (which are 

assumed not to vary by region) and indirect charges such as contingencies, 

land, and working capital. The boiler costs include auxiliary equipment 

such as the powerhouse and fuel and ash handling facilities. The annual 

non-fuel O&M cost estimates include labor, materials, parts, solid waste 

disposal and utility and commodity costs. The capital and annual non-fuel 

O&M cost estimates are assumed not to increase in real terms over time. 

A.3.2 Financial Parameters 

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

that industry will try to minimize the total costs of generating energy 

over the useful life of the facility. Specifically, industrial managers 

will select the fuel type with the lowest after-tax NPV of cash outflows 

for operating, fuel, and capital costs. 

IFCAM models the key elements of the Energy Tax Act of 1978 (ETA) and 

the Economic Recovery Tax Act of 1981 (ERTA). The ETA influences after-tax 

NPV calculations by permitting investments in coal facilities to be depreciated using accelerated methods while requiring investments in new gas or 

oil boilers to be depreciated using a straight line method. Both new coal 

and oil/gas boilers are depreciated over 5 years. New coal-fired boilers 

qualify for the regular 10 percent investment tax credit (ITC), but new 

oil/gas boilers are excluded from the regular ITC. Special energy tax 

credits are not incorporated because they expired on December 31, 1982 for 

conventional coal systems. 

IFCAM assumes an investment period of 15 years for new boilers. The 

corporate income tax rate is assumed to be 50 percent and includes Federal 

and local tax liabilities. 

A-9 
P.95 

The discount rate in IFCAM represents the average real (not nominal) 

after-tax cost of capital. The real, after-tax discount rate is eight percent for new units. 

A.3.3 Boiler Characteristics 

IFCAM uses eight standard boiler sizes. Table A-2 summarizes key 

assumptions in each boiler size class. Costs and emission rates vary 

significantly with the boiler type and firing method. All new firetube 

boilers are single-fuel fired. All new watertube oil and gas boilers are 

dual-fuel fired. 

A.3.4 Technology Limits 

There are limits on the capability of control technology to remove air 

pollutants. The estimates used in this analysis for new coal-fired industrial boilers are listed in Tables A-3 and A-4. 

A.3.5 Air Emissions Calculations 

IFCAM projects air emissions for three pollutants: SO2, PM, N0X. The 

level of air emissions is a function of fuel type, boiler type, and the 

emission regulation. If the applicable regulation requires no emission 

reductions, the uncontrolled emission rates are the level of air emissions. 

If the applicable regulation requires emission reductions in coalfired boilers for SO2, then the level of emissions is the following: 

Controlled SO2 emissions = (R x S x (1-Sc)) + ((1-R) x A) 

where: S = uncontrolled annual average SO2 emissions from 

coal combustion, ng/J (lb/MMBtu) 

Sc = reduction required to meet standard (fraction) 

R = 0.90 for lime spray drying FGD 

= 0.95 for dual alkali and sodium FGD 

A = uncontrolled SO2 emissions from natural gas 

combustion (backup fuel) 

This calculation assumes a reliability factor (R) for scrubbers and a 

low sulfur fuel standby option in the event of pollution control equipment 

malfunction. 

A-10 
P.96 

TABLE A-2. IFCAM INDUSTRIAL BOILER SIZE/TYPE ASSUMPTIONS 

Boiler s 

MU (MMBtu 

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) 

ize category, 

/hr) heat input 

Representative 

size 

Greater than 73 

(greater than 

250) 

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 

coalb 

Field-erected, 

watertube, 

spreader stoker 

or pulverized 

coal0 

Field-erected, 

watertube, 

spreader stoker 

or pulverized 

coal0 

Field-erected, 

watertube, 

pulverized coal 

Type 

Residual oil/ 

natural gasa 

Package, 

firetube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Two package, 

watertube0 

Two package, 

watertube0 

Distillate oil/ 

natural gasa 

Package, 

firetube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Package, 

watertube 

Two package, 

watertube0 

Two package, 

watertube0 

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

A mix is assumed in this size class. 

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

A-11 
P.97 

TABLE A-3. FGD TECHNOLOGY CONSTRAINTS IN IFCAM* 

Technology Limits 

Dual alkali 

Lime spray drying 

Sod i um 

90 percent0 removal of uncontrolled 

SO2 emissions for all coal types 

90 percent0 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 percent0 removal of uncontrolled 

SO2 emissions for all coal types 

U.S. Environmental Protection Agency. 

}30-day, rolling average basis. 

A-12 
TABLE A-4. PM EMISSIONS POLLUTION CONTROL 

TECHNOLOGY CONSTRAINTS IN IFCAM* 

Technology 

Minimum PM 

emission standard 

Single mechanical collector 

stoker/bituminous 

stoker/subb i tumi nous 

pulverized/all 

Dual mechanical collector 

stoker/bituminous 

stoker/subbituminous 

pulverized/all 

Side stream separator 

stoker/bituminous 

stoker/subbituminous 

pulverized/all 

Electrostatic precipitator 

Fabric filter 

Lime spray drying FGD*5 

Dual alkali FGD/single 

mechanical collector 

high sulfur coal (greater 

than 3.5 lb S02/MMBtu) 

other coal types (less 

than 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. 

A-13 
P.99 

APPENDIX B. PROJECTED FUEL PRICES: 

REFERENCE PRICE SCENARIO 

B-l 
p.1 

TABLE B-l. WORLD OIL PRICE FORECAST: 

REFERENCE PRICE SCENARIO* 

(1982 $/bbl) 

Average refiner acquisition 

Year cost of imported crude oil 

1985 25 

1990 28 

1995 32 

2000 37 

'Energy and Environmental Analysis, Inc. 

B-2 
P.2 

TABLE B-2. PROJECTIONS OF INDUSTRIAL 

3.0 PERCENT SULFUR RESIDUAL FUEL OIL PRICES8 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

3.94 

3.93 

3.93 

3.91 

4.08 

3.93 

4.05 

3.74 

3.55 

3.50 

1990 

4.43 

4.42 

4.42 

4.40 

4.57 

4.42 

4.54 

4.23 

4.03 

3.99 

1995 

4.99 

4.98 

4.98 

4.96 

5.12 

4.98 

5.09 

4.79 

4.57 

4.53 

2000 

5.66 

5.65 

5.65 

5.62 

5.79 

5.65 

5.75 

5.47 

5.23 

5.19 

Energy and Environmental Analysis, Inc. Reference price scenario, 

B-3 
P.3 

TABLE B-3. PROJECTIONS OF INDUSTRIAL 

1.6 PERCENT SULFUR RESIDUAL FUEL OIL PRICES* 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.21 

4.20 

4.20 

4.17 

4.34 

4.19 

4.31 

4.00 

3.82 

3.77 

1990 

4.73 

4.72 

4.72 

4.70 

4.86 

4.72 

4.83 

4.53 

4.33 

4.29 

1995 

5.32 

5.31 

5.31 

5.29 

5.45 

5.31 

5.42 

5.13 

4.91 

4.87 

2000 

6.04 

6.03 

6.03 

6.01 

6.17 

6.03 

6.14 

5.85 

5.61 

5.57 

'Energy and Environmental Analysis, Inc. Reference price scenario. 

B-4 
P.4 

TABLE B-4. PROJECTIONS OF INDUSTRIAL 

0.8 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.51 

4.50 

4.50 

4.48 

4.65 

4.50 

4.61 

4.31 

4.15 

4.11 

1990 

5.07 

5.06 

5.06 

5.03 

5.20 

5.06 

5.17 

4.87 

4.70 

4.65 

1995 

5.71 

5.70 

5.70 

5.68 

5.84 

5.70 ^ 

5.81 

5.51 

5.33 

5.29 

2000 

6.49 

6.48 

6.48 

6.46 

6.63 

6.48 

6.59 

6.30 

6.09 

6.05 

'Energy and Environmental Analysis, Inc. Reference price scenario. 

B-5 
P.5 

TABLE B-5. PROJECTIONS OF INDUSTRIAL 

0.3 PERCENT SULFUR RESIDUAL FUEL OIL PRICES* 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.81 

4.80 

4.80 

4.78 

4.95 

4.80 

4.92 

4.61 

4.43 

4.38 

1990 

5.41 

5.40 

5.40 

5.37 

5.55 

5.40 

5.51 

5.21 

5.00 

4.96 

1995 

6.10 

6.09 

6.09 

6.07 

6.24 

6.09 

6.20 

5.90 

5.68 

5.64 

2000 

6.94 

6.93 

6.93 

6.91 

7.08 

6.93 

7.04 

6.75 

6.50 

6.45 

'Energy and Environmental Analysis, Inc. Reference price scenario. 

B-6 
TABLE B-6. PROJECTIONS OF INDUSTRIAL 

NATURAL GAS PRICES* 

(1982 $/MMBtu) 

P.6 

Region 1985 1990 1995 2000 

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 

4.38 

4.29 

4.16 

4.57 

4.32 

4.02 

3.86 

3.68 

4.02 

4.44 

5.21 

5.21 

5.17 

5.46 

5.34 

4.95 

4.91 

4.47 

4.94 

5.23 

6.25 . 

6.27 

6.22 

6.47 

6.38 

5.75 

5.92 

5.27 

5.96 

5.85 

7.49 

7.30 

7.25 

7.40 

7.27 

6.75 

6.81 

6.12 

6.56 

6.63 

Energy and Environmental Analysis, Inc. Reference price scenario. 

B-7 
P.7 

APPENDIX C. PROJECTED FUEL PRICES: 

HIGHER OIL AND GAS PRICES SCENARIO 

C-l 
P.8 

TABLE C-l. WORLD OIL PRICE FORECAST 

AND GAS PRIC 

(1982 $/bbl) 

HIGHER OIL AND GAS PRICES SCENARIO* 

Average refiner acquisition 

Year cost of imported crude oil 

1985 25.90 

1990 31.90 

1995 46.50 

2000 57.40 

aCase B. Energy Projections to the Year 2010. U.S. Department of Energy, 

Office of Policy, Planning and Analysis. DOE/PE-0029/2. October 1983. 

C-2 
P.9 

TABLE C-2. PROJECTIONS OF INDUSTRIAL 

3.0 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.07 

4.05 

4.05 

4.03 

4.18 

4.05 

4.15 

3.89 

3.72 

3.68 

1990 

5.05 

5.04 

5.04 

5.02 

5.17 

5.04 

5.14 

4.87 

4.68 

4.64 

1995 

6.93 

6.91 

6.91 

6.90 

7.05 

6.91 

7.02 

6.75 

6.47 

6.44 

2000 

8.40 

8.38 

8.38 

8.37 

8.51 

8.39 

8.52 

8.24 

7.90 

7.87 

Energy and Environmental Analysis, Inc. Higher oil and gas prices 

scenario. 

C-3 
P.10 

TABLE C-3. PROJECTIONS OF INDUSTRIAL 

1.6 PERCENT SULFUR RESIDUAL FUEL OIL PRICES* 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.34 

4.33 

4.33 

4.30 

4.46 

4.33 

4.42 

4.16 

3.99 

3.96 

1990 

5.40 

5.39 

5.39 

5.37 

5.52 

5.39 

5.48 

5.22 

5.03 

5.00 

1995 

7.41 

7.40 

7.40 

7.39 

7.53 

7.40 

7.50 

7.24 

6.96 

6.93 

2000 

9.00 

8.99 

8.99 

8.98 

9.14 

8.99 

9.10 

8.83 

8.51 

8.48 

Energy and Environmental Analysis, Inc. Higher oil and gas prices 

scenario. 

C-4 
P.11 

TABLE C-4. PROJECTIONS OF INDUSTRIAL 

0.8 PERCENT SULFUR RESIDUAL FUEL OIL PRICES8 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.65 

4.64 

4.64 

4.63 

4.77 

4.64 

4.74 

4.47 

4.33 

4.29 

1990 

5.79 

5.79 

5.79 

5.77 

5.91 

5.79 

5.89 

5.63 

5.45 

5.42 

1995 

7.98 

7.98 

7.98 

7.96 

8.09 

7.98 

8.07 

7.80 

7.58 

7.54 

2000 

9.70 

9.69 

9.69 

9.67 

9.82 

9.69 

9.80 

9.52 

9.29 

9.25 

Energy and Environmental Analysis, Inc. Higher oil and gas prices 

scenario. 

C-5 
P.12 

TABLE C-5. PROJECTIONS OF INDUSTRIAL 

0.3 PERCENT SULFUR RESIDUAL FUEL OIL PRICES3 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.96 

4.96 

4.96 

4.94 

5.09 

4.96 

5.05 

4.79 

4.63 

4.58 

1990 

6.19 

6.18 

6.18 

6.17 

6.31 

6.18 

6.28 

6.01 

5.81 

5.77 

1995 

8.55 

8.54 

8.54 

8.52 

8.67 

8.54 

8.63 

8.37 

8.09 

8.06 

2000 

10.41 

10.40 

10.40 

10.38 

10.54 

10.40 

10.50 

10.24 

9.91 

9.87 

Energy and Environmental Analysis, Inc. Higher oil and gas prices 

scenario. 

C-6 
P.13 

TABLE C-6. PROJECTIONS OF INDUSTRIAL 

NATURAL GAS PRICES* 

(1982 $/MMBtu) 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

Region 

New England 

New York/New Jersey 

Middle Atlantic 

South Atlantic 

Midwest 

Southwest 

Central 

North Central 

West 

Northwest 

1985 

4.43 

4.35 

4.29 

4.63 

4.42 

4.08 

3.92 

3.72 

4.05 

4.45 

1990 

5.56 

5.54 

5.52 

5.85 

5.69 

5.41 

5.27 

4.73 

5.23 

5.45 

1995 

7.37 

7.36 

7.36 

7.69 

7.55 

6.96 

7.08 

6.19 

6.91 

7.03 

2000 

9.29 

9.01 

9.00 

9.19 

8.95 

8.57 

8.54 

7.52 

8.19 

8.15 

aEnergy and Environmental Analysis, Inc. Higher oil and gas prices 

scenario. 

C-7 
P.14 

APPENDIX D. CHARACTERISTICS OF 

INDUSTRIAL COAL TYPES IN IFCAM 

D-l 
P.15 

TABLE D-l. SULFUR DIOXIDE EMISSION RATES BY COAL TYPE* 

Coal Type 

Bituminous 

Subbituminous 

Range 

ng/J 

<464 

464-718 

718-1,075 

1,075-1,432 

1,432-2,150 

>2,150 

<464 

464-718 

718-1,075 

(lb/MMBtu) 

(<1.08) 

(1.08-1.67) 

(1.67-2.50) 

(2.50-3.33) 

(3.33-5.00) 

(>5.00) 

(<1.08) 

(1.08-1.67) 

(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) 

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

D-2 
TABLE D-2. AVERAGE ASH CONTENT BY REGION (BITUMINOUS COAL TYPES)3 

(percentage, moist) 

1 

CJ 

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 S02/MMBtu 

1.67-2. 

13.0 

11.4 

12.6 

12.3 

10.5 

15.0 

12.4 

10.0 

16.3 

10.0 

50 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.17 

TABLE D-3. AVERAGE ASH CONTENT BY REGION 

(SUBBITUMINOUS COAL TYPES)3 

(percentage, moist) 

lb $0o/MMBtu 

Region 7TJ5E 1.08-1.67 1.67-2.50 

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 

aICF Incorporated. 

6.9 

7.3 

6.0 

8.4 

7.3 

10.0 

6.9 

7.3 

6.0 

6.9 

7.3 

10.0 

6.9 

7.3 

6.0 

6.9 

7.3 

10.0 

D-4 
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cn -e» 

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O VO 

ro ro 

tn vo 

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8ld 
TABLE D-5. AVERAGE HEAT CONTENT BY REGION 

(SUBBITUMINOUS COAL TYPES)3 

J/g (MMBtu/short ton) 

P.19 

Region ros" 

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. 

10. 

Midwest 

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. 

D-6 
P.20 

APPENDIX E. DELIVERED INDUSTRIAL 

COAL PRICE FORECAST 

• Reference: Memorandum from C. Ebert (ICF Incorporated) to J. 

Greenwald (EPA). Revised Industrial Coal Prices for 

Industrial NSPS Analyses. May 31, 1984. Attachment A. 

• Converted from January 1983 dollars to 1982 dollars using the average 

annual 1982 and fourth quarter 1982 GNP implicit price deflators. 

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P.23 

DELIVERED INDUSTRIAL COAL PRICE FORECAST*1 

(1982 $/MMBtu) 

(Continued) 

Region 

8. North Central 

9. West 

10. Northwest 

Coal type 

Bituminous 

Subbituminous 

Bituminous 

Subbituminous 

Bituminous 

Subbituminous 

Sulfur content 

(lb S02/MMBtu) 

1.08 

1.67 

1.08 

1.67 

1.08 

1.67 

1.08 

1.67 

1.08 

1.67 

1.08 

1.67 

<1.08 

- 1.67 

- 2.50 

<1.08 

- 1.67 

- 2.50 

<1.08 

- 1.67 

- 2.50 

<1.08 

- 1.67 

- 2.50 

<1.08 

- 1.67 

- 2.50 

<1.08 

- 1.67 

- 2.50 

1985 

1.76 

1.61 

1.70 

1.22 

1.17 

1.19 

2.54 

2.39 

2.40 

2.62 

2.52 

2.48 

2.92 

2.63 

2.59 

2.38 

2.40 

1.93 

1990 

1.90 

1.74 

1.81 

1.32 

1.32 

1.21 

2.69 

2.64 

2.64 

2.71 

2.61 

2.56 

3.06 

2.80 

2.72 

2.59 

2.48 

1.99 

1995 

1.98 

1.90 

1.88 

1.41 

1.42 

1.28 

2.75 

2.90 

2.81 

2.83 

2.72 

2.60 

3.13 

2.99 

2.83 

2.62 

2.59 

2.08 

2000 

2.07 

2.01 

1.86 

1.52 

1.45 

1.33 

2.91 

3.05 

2.92 

2.92 

2.84 

2.69 

3.27 

3.18 

2.88 

2.71 

2.67 

2.19 

ICF Incorporated. 

E-4 
P.24 

APPENDIX F 

IFCAM PROJECTIONS FOR 1990 BY BOILER SIZE CLASS 

This appendix summarizes IFCAM forecasts of total SO2 emissions, 

annualized costs, and fossil fuel demand in 1990 from new industrial fossil 

fuel-fired boilers installed between 1985 and 1990 and each larger than 29 

MW (100 MMBtu/hr) heat input capacity. Results are presented for both fuel 

price scenarios (reference Section 2.2.3) and for each alternative SO2 NSPS 

emissions standard (reference Section 3.1). 

In these tables, "gas" is natural gas and "oil" is residual fuel oil. 

F-l 
TABLE F-l. COMPARISON OF IFCAM PROJECTIONS FOR 1990* 

P.25 

Fuel price 

scenario Baseline 

Alternative control level 

II III IV VI 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costsD 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Higher oil and 

gas prices 

SOg emissions 

(IO3 short tons) 

Annualized costsb 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

279 

3,349 

23 

323 

152 

326 

3,725 

284 

7 

207 

204 

3,357 

17 

329 

153 

148 

3,735 

261 

0 

237 

106 

3,406 

17 

257 

225 

114 

3,743 

248 

0 

250 

102 39 47 16 

9 26 26 26 

257 206 205 178 

232 267 267 294 

46 34 30 16 

153 153 153 147 

0 0 0 0 

345 345 345 351 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 

and each larger than 29 MW (100 MMBtu/hr) heat input capacity. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-2 
P.26 

TABLE F-2. REGULATORY BASELINE PROJECTIONS FOR 1990 

BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costsb 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Higher oil and gas pr 

SO? emissions 

(IO3 short tons) 

Annualized costs'3 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

105 

901 

4 

99 

26 

ices 

74 

1,008 

40 

7 

82 

iler size c 

44-58 

(150-200) 

82 

729 

1 

86 

24 

108 

838 

70 

0 

41 

lass, MW (MMBtu/hr) 

58-73 

(200-250) 

52 

445 

6 

46 

15 

86 

493 

48 

0 

19 

>73 

(>250) 

41 

1,275 

13 

92 

87 

59 

1,386 

126 

0 

65 

Total 

279 

3,349 

23 

323 

152 

326 

3,725 

284 

7 

207 

aNew industrial fossil fuel-fired boilers installed between 1986 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-3 
P.27 

TABLE F-3. ALTERNATIVE CONTROL LEVEL I PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

69 

906 

3 

100 

26 

Higher oil and gas prices 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

24 

1,013 

37 

0 

92 

iler size c 

44-58 

(150-200) 

59 

733 

1 

86 

24 

37 

836 

55 

0 

56 

lass, MW (MMBtu/hr) 

58-73 

(200-250) 

35 

444 

0 

51 

16 

29 

500 

43 

0 

24 

>73 

(>250) 

40 

1,275 

13 

92 

87 

58 

1,387 

126 

0 

65 

Total 

204 

3,357 

17 

329 

153 

148 

3,735 

261 

0 

237 

3New industrial fossil fuel-fired boilers installed between 1985 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-4 
TABLE F-4. ALTERNATIVE CONTROL LEVEL II PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS9 

• 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO*2 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

28 

926 

3 

70 

56 

Higher oil and gas prices 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

11 

1,009 

23 

0 

105 

iler size cl 

44-58 

(150-200) 

24 

749 

1 

60 

50 

25 

844 

55 

0 

56 

ass, MW (MMBtu/hr) 

58-73 

(200-250) 

14 

456 

0 

34 

33 

20 

504 

43 

0 

24 

> 73 

(>250) 

40 

1,275 

13 

92 

87 

58 

1,387 

126 

0 

65 

Total 

106 

3,406 

17 

257 

225 

114 

3,743 

248 

0 

250 

*New industrial fossil fuel-fired boilers installed between 1985 and 1990. 

^Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-5 
P.29 

TABLE F-5. ALTERNATIVE CONTROL LEVEL III PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(10° 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

27 

927 

1 

70 

58 

Higher oil and gas prices 

S0?,emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

4 

1,011 

12 

0 

117 

iler size c 

44-58 

(150-200) 

23 

749 

0 

60 

51 

7 

832 

23 

0 

88 

lass, MW (MMBtu/hr) 

58-73 

(200-250) 

14 

456 

0 

34 

33 

5 

500 

17 

0 

50 

>73 

(>250) 

38 

1,276 

9 

92 

91 

30 

1,411 

101 

0 

90 

Total 

102 

3,408 

9 

257 

232 

46 

3,754 

153 

0 

345 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-6 
P.30 

TABLE F-6. ALTERNATIVE CONTROL LEVEL IV PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Higher oil and gas pr 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (1012 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

9 

943 

0 

57 

72 

ices 

3 

1,011 

12 

0 

117 

iler size c 

44-58 

(150-200) 

9 

762 

0 

57 

54 

5 

833 

23 

0 

88 

:lass, MW (MMBtu/hr) 

58-73 

(200-250) 

5 

461 

0 

33 

34 

4 

501 

17 

0 

50 

>73 

(>250) 

15 

1,310 

26 

59 

107 

22 

1,412 

101 

0 

90 

Total 

39 

3,476 

26 

206 

267 

34 

3,757 

153 

0 

345 

3New industrial fossil fuel-fired boilers installed between 1985 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-7 
P.31 

TABLE F-7. ALTERNATIVE CONTROL LEVEL V PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

13 

942 

0 

57 

72 

Higher oil and gas prices 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

3 

1,011 

12 

0 

117 

iler size c 

44-58 

(150-200) 

13 

761 

0 

57 

54 

5 

833 

23 

0 

88 

lass, MW (MMBtu/hr) 

58-73 

(200-250) 

8 

460 

0 

33 

34 

3 

501 

17 

0 

50 

>73 

(>250) 

13 

1,311 

26 

59 

107 

19 

1,414 

101 

0 

90 

Total 

47 

3,474 

26 

206 

267 

30 

3,758 

153 

0 

345 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-8 
TABLE F-8. ALTERNATIVE CONTROL LEVEL VI PROJECTIONS 

FOR 1990 BY BOILER SIZE CLASS* 

Fuel price 

scenario 

Reference 

SO2 emissions 

(IO3 short tons) 

Annualized costs0 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

Bo 

29-44 

(100-150) 

4 

945 

0 

44 

85 

Higher oil and gas prices 

SO? emissions 

(IO3 short tons) 

Annualized costs'? 

(IO6 1982 $) 

Fuel (IO12 Btu) 

coal 

oil 

gas 

2 

1,011 

12 

0 

117 

iler size c 

44-58 

(150-200) 

4 

763 

0 

51 

60 

2 

829 

17 

0 

94 

lass, MW (MMBtu/hr) 

58-73 

(200-250) 

3 

461 

0 

32 

35 

2 

501 

17 

0 

50 

>73 

(>250) 

6 

1,313 

26 

52 

113 

10 

1,415 

101 

0 

90 

Total 

16 

3,482 

26 

178 

294 

16 

3,757 

147 

0 

351 

3New industrial fossil fuel-fired boilers installed between 1985 and 1990. 

Includes capital, operating, maintenance and fuel costs for the boiler 

and pollution control equipment. 

F-9