Revised Economic Impact Analysis of the 

Industrial Boilers and Process Heaters NESHAP 

_________________________________ 

RTI International is a trade name of Research Triangle Institute. 

June 2007 

Revised Economic Impact Analysis of the Industrial Boilers and Process Heaters NESHAP 

By: 

RTI International 

Health, Social, and Economics Research 

Research Triangle Park, NC 27709 

Prepared for: 

John L. Sorrels 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Air Benefits and Costs Group 

C439-02 

Research Triangle Park, NC 27711 

Contract No. EP-D-06-003 

iii 

CONTENTS 

Section Page

1 Introduction................................................................................................................... 1-1 

1.1 Agency Requirements for an EIA........................................................................ 1-1 

1.2 Scope and Purpose............................................................................................... 1-2 

1.3 Organization of the Report .................................................................................. 1-2 

2 Boiler and Process Heater Technologies ...................................................................... 2-1 

2.1 Characteristics of Steam ...................................................................................... 2-1 

2.2 Fossil-Fuel Boiler Characterization..................................................................... 2-4 

2.2.1 Industrial, Commercial, and Institutional Boilers.................................... 2-4 

2.2.2 Heat Transfer Configurations .................................................................. 2-5 

2.2.3 Major Design Types................................................................................. 2-5 

2.2.3.1 Stoker-Fired Boilers (Coal) ...................................................... 2-5 

2.2.3.2 Pulverized Coal Boilers (Coal)................................................. 2-6 

2.2.3.3 Fluidized Bed Combustion (FBC) Boilers (Coal) .................... 2-6 

2.2.3.4 Tangentially Fired Boilers (Coal, Oil, Natural Gas)................. 2-7 

2.2.3.5 Wall-fired Boilers (Coal, Oil, Natural Gas).............................. 2-7 

2.3 Process Heater Characterization.......................................................................... 2-8 

2.3.1 Classes of Process Heaters....................................................................... 2-8 

2.3.2 Major Design Types................................................................................. 2-9 

2.3.2.1 Combustion Chamber Set-Ups ................................................. 2-9 

2.3.2.2 Combustion Air Supply ............................................................ 2-9 

2.3.2.3 Tube Configurations ............................................................... 2-11 

2.3.2.4 Burners.................................................................................... 2-11 

3 Profile of Affected Units and Facilities, and Compliance Costs .................................. 3-1 

3.1 Regulatory Alternatives....................................................................................... 3-1 

3.1.1 Regulatory Background ........................................................................... 3-2 

3.1.2 Regulatory Authority ............................................................................... 3-2 

3.1.3 Regulatory Alternatives and Control Technologies................................. 3-6 

3.1.3.1 MACT Floor Development....................................................... 3-6 

3.1.3.2 Consideration of Options Beyond the Floor for Existing 

Units........................................................................................ 3-13 

3.1.3.3 EPA Response to Recent Court Decisions in Developing 

the Emission Limitations ........................................................ 3-17 

3.1.3.4 How did EPA Determine the Emission Limitations for 

New Units? ............................................................................. 3-19 
iv 

3.1.4 Considerations of Possible Risk-Based Alternatives to Reduce 

Impacts to Sources ................................................................................. 3-29 

3.1.4.1 Applicability Cutoffs for Threshold Pollutants Under 

Section 112(d)(4) of the CAA ................................................ 3-30 

3.1.4.2 Applicability Cutoffs for Hydrogen Chloride Controls 

Under Section 112(d)(4) of the CAA ..................................... 3-31 

3.1.4.3 Applicability Cutoffs for Total Selected Metals Controls 

Under Section 112(d)(4) of the CAA ..................................... 3-32 

3.2 Profile of Existing Boiler and Process Heaters Units........................................ 3-34 

3.2.1 Development of the Unit Inventory Database ....................................... 3-34 

3.2.2 Distribution of Existing Boilers and Facilities by Industry ................... 3-35 

3.2.3 Technical Characteristics of Existing Boilers........................................ 3-35 

3.2.3.1 Final Rule................................................................................ 3-35 

3.3 Methodology for Estimating Cost Impacts........................................................ 3-38 

3.4 Projection of New Boilers and Process Heaters ................................................ 3-46 

3.5 National Engineering Population, Cost Estimates, and Cost-Effectiveness 

Estimates............................................................................................................ 3-47 

4 Profiles of Affected Industries...................................................................................... 4-1 

4.1 Textile Mill Products (SIC 22/NAICS 313) ........................................................ 4-1 

4.2 Lumber and Wood Products (SIC 24/NAICS 321) ............................................. 4-1 

4.2.1 Supply Side of the Industry...................................................................... 4-3 

4.2.1.1 Production Processes ................................................................ 4-3 

4.2.1.2 Types of Output ........................................................................ 4-3 

4.2.1.3 Major By-Products and Co-Products........................................ 4-4 

4.2.1.4 Costs of Production................................................................... 4-4 

4.2.1.5 Capacity Utilization .................................................................. 4-4 

4.2.2 Demand Side of the Industry ................................................................... 4-5 

4.2.3 Product Characteristics ............................................................................ 4-5 

4.2.4 Uses and Consumers of Outputs.............................................................. 4-6 

4.2.5 Organization of the Industry .................................................................... 4-6 

4.2.6 Markets and Trends.................................................................................. 4-7 

4.3 Furniture and Related Product Manufacturing (SIC 25/NAICS 337) ................. 4-8 

4.4 Paper and Allied Products (SIC 26/NAICS 322) ................................................ 4-9 

4.4.1 Supply Side of the Industry.................................................................... 4-10 

4.4.1.1 Production Process.................................................................. 4-10 

4.4.1.2 Types of Output ...................................................................... 4-11 

4.4.1.3 Major By-Products and Co-Products...................................... 4-11 

4.4.1.4 Costs of Production................................................................. 4-12 

4.4.1.5 Capacity Utilization ................................................................ 4-12 
v 

4.4.2 Demand Side of the Industry ................................................................. 4-13 

4.4.2.1 Product Characteristics ........................................................... 4-13 

4.4.2.2 Uses and Consumers of Products............................................ 4-13 

4.4.3 Organization of the Industry .................................................................. 4-13 

4.4.4 Markets and Trends................................................................................ 4-14 

4.5 Medicinal Chemicals and Botanical Products and Pharmaceutical 

Preparations (SICs 2833, 2834/NAICS 32451)................................................. 4-15 

4.5.1 Supply Side of the Industry.................................................................... 4-15 

4.5.1.1 Production Processes .............................................................. 4-15 

4.5.1.2 Types of Output ...................................................................... 4-17 

4.5.1.3 Major By-Products and Co-Products...................................... 4-17 

4.5.1.4 Costs of Production................................................................. 4-17 

4.5.1.5 Capacity Utilization ................................................................ 4-19 

4.5.2 Demand Side of the Industry ................................................................. 4-19 

4.5.3 Organization of the Industry .................................................................. 4-19 

4.5.4 Markets and Trends................................................................................ 4-21 

4.6 Industrial Organic Chemicals Industry (SIC 2869/NAICS 3251)..................... 4-22 

4.6.1 Supply Side of the Industry.................................................................... 4-22 

4.6.1.1 Production Processes .............................................................. 4-22 

4.6.1.2 Types of Output ...................................................................... 4-23 

4.6.1.3 Major By-Products and Co-Products...................................... 4-24 

4.6.1.4 Costs of Production................................................................. 4-24 

4.6.1.5 Capacity Utilization ................................................................ 4-24 

4.6.2 Demand Side of the Industry ................................................................. 4-25 

4.6.3 Organization of the Industry .................................................................. 4-25 

4.6.4 Markets and Trends................................................................................ 4-26 

4.7 Electric Services (SIC 4911/NAICS 22111) ..................................................... 4-27 

4.7.1 Electricity Production ............................................................................ 4-27 

4.7.1.1 Generation............................................................................... 4-27 

4.7.1.2 Transmission........................................................................... 4-28 

4.7.1.3 Distribution ............................................................................. 4-29 

4.7.2 Cost of Production ................................................................................. 4-30 

4.7.3 Organization of the Industry .................................................................. 4-30 

4.7.3.1 Utilities.................................................................................... 4-31 

4.7.3.2 Nonutilities.............................................................................. 4-33 

4.7.4 Demand Side of the Industry ................................................................. 4-33 

4.7.4.1 Electricity Consumption ......................................................... 4-33 

4.7.4.2 Trends in the Electricity Market ............................................. 4-35 

5 Economic Analysis Methodology................................................................................. 5-1 

5.1 Background on Economic Modeling Approaches............................................... 5-1 

5.1.1 Modeling Dimension 1: Scope of Economic Decisionmaking................ 5-1 

5.1.2 Modeling Dimension 2: Interaction Between Economic Sectors............ 5-3 
vi 

5.2 Selected Modeling Approach for Boilers and Process Heaters Analysis............ 5-4 

5.2.1 Directly Affected Markets ....................................................................... 5-6 

5.2.1.1 Electricity Market ..................................................................... 5-6 

5.2.1.2 Petroleum Market ..................................................................... 5-7 

5.2.1.3 Goods and Services Markets: Agriculture, 

Manufacturing, Mining, Commercial, and Transportation....... 5-8 

5.2.2 Indirectly Affected Markets................................................................... 5-10 

5.2.2.1 Market for Coal....................................................................... 5-10 

5.2.2.2 Natural Gas Market................................................................. 5-11 

5.2.2.3 Goods and Services Markets................................................... 5-11 

5.2.2.4 Impact on Residential Sector .................................................. 5-11 

5.3 Operationalizing the Economic Impact Model.................................................. 5-11 

5.3.1 Computer Model .................................................................................... 5-13 

5.3.2 Calculating Changes in Social Welfare ................................................. 5-16 

6 Economic Impact Analysis Results .............................................................................. 6-1 

6.1 Social Cost Estimates .......................................................................................... 6-1 

6.2 National Market-Level Impacts........................................................................... 6-3 

6.3 Executive Order 13211 (Energy Effects) ............................................................ 6-5 

6.4 Conclusions ......................................................................................................... 6-6 

7 Small Entity Impacts..................................................................................................... 7-1 

7.1 Background on Small Entity Screenings ............................................................. 7-1 

7.2 Identifying Small Entities with Affected Sources in the Inventory 

Database............................................................................................................... 7-2 

7.3 Analysis of Facility-Level and Parent-Level Data .............................................. 7-4 

7.4 Small Entity Impacts ........................................................................................... 7-9 

7.5 Affected Government Entities: Supplemental Analysis.................................... 7-10 

7.6 Small Utility and Nonutility Entities: Data and Screening Analysis Results.... 7-13 

7.7 Assessment of SBREFA Screening................................................................... 7-14 

References..............................................................................................................................R-1 
vii 

Appendixes 

A Estimating Economic Impacts in Markets Affected by the Boilers and 

Process Heaters MACT ...................................................................................... A-1 

B Assumptions and Sensitivity Analysis ................................................................B-1 

C Economic Analysis of Regulatory Alternative: Option 1A.................................C-1 

D Impacts from Application of Risk-Based Alternatives....................................... D-1 
viii 

LIST OF FIGURES 

Number Page

2-1 Generating Electricity: Steam Turbines........................................................................ 2-3 

3-1 Characteristics of Units Affected................................................................................ 3-38 

4-1 Traditional Electric Power Industry Structure ............................................................ 4-28 

4-2 Utility and Nonutility Generation and Shares by Class, 1988 and 1998 .................... 4-32 

4-3 Annual Electricity Sales by Sector ............................................................................. 4-35 

5-1 Links Between Energy and Goods and Services Markets ............................................ 5-5 

5-2 Market Effects of Regulation-Induced Costs................................................................ 5-7 

5-3 Fuel Market Interactions with Facility-Level Production Decisions............................ 5-9 

5-4 Operationalizing the Estimation of Economic Impact................................................ 5-12 

5-5 Changes in Economic Welfare with Regulation......................................................... 5-17 

7-1 Parent Size by Employment Range............................................................................... 7-6 

7-2 Number of Parents by Sales Range............................................................................... 7-7 
ix 

LIST OF TABLES 

Number Page

3-1 Emission Limits for Boilers and Process Heaters (lb/MMBtu).................................... 3-5 

3-2 Units and Facilities Affected by the Final Rule by Industry ...................................... 3-36 

3-3 Testing and Monitoring Costs for Units Covered....................................................... 3-43 

3-4 Cost Effectiveness (C/E) of Industrial Boiler and Process Heater MACT on 

Existing Units and Subcategories ............................................................................... 3-46 

3-5 New Unit Projections by Industry, MACT Floor ....................................................... 3-48 

3-6 Unit Cost and Population Estimates for the Final Rule by Industry, 2005................. 3-50 

4-1 Lumber and Wood Products Markets Likely to Be Affected by the Regulation.......... 4-2 

4-2 Value of Shipments for the Lumber and Wood Products Industry 

(SIC 24/NAICS 321), 1987–1996................................................................................. 4-2 

4-3 Inputs for the Lumber and Wood Products Industry (SIC 24/NAICS 321), 

1987–1996..................................................................................................................... 4-5 

4-4 Capacity Utilization Ratios for Lumber and Wood Products Industry, 1991–

1996............................................................................................................................... 4-5 

4-5 Size of Establishments and Value of Shipments for the Lumber and Wood 

Products Industry (SIC 24/NAICS 321) ....................................................................... 4-7 

4-6 Measures of Market Concentration for Lumber and Wood Products Markets............. 4-8 

4-7 Paper and Allied Products Industry Markets Likely to Be Affected by 

Regulation..................................................................................................................... 4-9 

4-8 Value of Shipments for the Paper and Allied Products Industry 

(SIC 26/NAICS 322), 1987–1996............................................................................... 4-10 

4-9 Inputs for the Paper and Allied Products Industry (SIC 26/NAICS 322), 1987–

1996............................................................................................................................. 4-12 

4-10 Capacity Utilization Ratios for the Paper and Allied Products Industry, 1991–

1996............................................................................................................................. 4-13 

4-11 Size of Establishments and Value of Shipments for the Paper and Allied 

Products Industry (SIC 26/NAICS 322) ..................................................................... 4-14 

4-12 Measurements of Market Concentration for Paper and Allied Products Markets...... 4-15 

4-13 Value of Shipments for the Medicinals and Botanicals and Pharmaceutical 

Preparations Industries, 1987–1996............................................................................ 4-16 

4-14 Inputs for Medicinal Chemicals and Botanical Products Industry 

(SIC 2833/NAICS 32451), 1987–1996....................................................................... 4-18 

4-15 Inputs for the Pharmaceutical Preparations Industry (SIC 2834/NAICS 32451), 

1987–1996................................................................................................................... 4-18 

4-16 Capacity Utilization Ratios for the Medicinal Chemicals and Botanical Products 

(SIC 2833/NAICS 32451) and Pharmaceutical Preparations 

(SIC 2834/NAICS 32451) Industries, 1991–1996...................................................... 4-19 
x 

4-17 Size of Establishments and Value of Shipments for the Medicinal Chemicals 

and Botanical Products (SIC 2833/NAICS 32451) and Pharmaceutical 

Preparations (SIC 2834/NAICS 32451) Industries..................................................... 4-20 

4-18 Measures of Market Concentration for the Medicinal Chemicals and Botanical 

Products (SIC 2833/NAICS 32451) and Pharmaceutical Preparations (SIC 

2834/NAICS 32451) Industries .................................................................................. 4-21 

4-19 Value of Shipments for the Industrial Organic Chemicals, N.E.C. Industry (SIC 

2869/NAICS 3251), 1987–1996 ................................................................................. 4-23 

4-20 Inputs for the Industrial Organic Chemicals Industry (SIC 2869/NAICS 3251), 

1987–1996................................................................................................................... 4-25 

4-21 Capacity Utilization Ratios for the Industrial Organic Chemicals Industry (SIC 

2869/NAICS 3251), 1991–1996 ................................................................................. 4-25 

4-22 Size of Establishments and Value of Shipments for the Industrial Organic 

Chemicals Industry (SIC 2869/NAICS 3251) ............................................................ 4-26 

4-23 Net Generation by Energy Source, 1995 .................................................................... 4-29 

4-24 Total Expenditures in 1996 ($103).............................................................................. 4-30 

4-25 Number of Electricity Suppliers in 1999 .................................................................... 4-31 

4-26 U.S. Electric Utility Retail Sales of Electricity by Sector, 1989 Through 1998 

(106 kWh).................................................................................................................... 4-34 

4-27 Key Parameters in the Cases....................................................................................... 4-36 

5-1 Comparison of Modeling Approaches.......................................................................... 5-2 

5-2 Supply and Demand Elasticities ................................................................................. 5-14 

5-3 Fuel Price Elasticities.................................................................................................. 5-16 

6-1 Social Cost Estimates ($1998 106

): Final Rule............................................................. 6-1 

6-2 Distribution of Social Costs by Sector/Market: Final Rule ($1998 106

) ...................... 6-2 

6-3 Market-Level Impacts: Final Rule................................................................................ 6-4 

7-1 Summary of Small Entity Impacts................................................................................ 7-1 

7-2 Facility-Level and Parent-Level Data by Industry........................................................ 7-5 

7-3 Small Parent Entities by Industry ................................................................................. 7-8 

7-4 Summary Statistics for SBREFA Screening Analysis................................................ 7-10 

7-5 Regional Distribution of Municipal Systems.............................................................. 7-11 

7-6 Selected Municipal Utilities’ Capacity, Usage, and Consumer Types ....................... 7-12 

7-7 Comparison of Screening Analysis Results for Small Governmental 

Jurisdictions ................................................................................................................ 7-13 

7-8 Industry Distribution of Small Commercial Electric Utility and Nonutility 

Entities ........................................................................................................................ 7-14 

7-9 Supplemental Screening Analysis for Small Governmental Jurisdictions ................. 7-14 

7-10 Profit Margins for Industry Sectors with Affected Small Businesses ........................ 7-15 
1-1 

SECTION 1 

INTRODUCTION 

The U.S. Environmental Protection Agency (referred to as EPA or the Agency) is 

developing regulations under Section 112 of the Clean Air Act (CAA) or the Act for industrial, 

commercial, and institutional (ICI) boilers and process heaters. These combustion devices are 

used in the production processes of numerous industries in the U.S. The hazardous air pollutants 

(HAPs) are generated by the combustion of fossil fuels and biomass in boilers and process 

heaters. The primary HAPs emitted by ICI boilers and process heaters include arsenic, beryllium, 

cadmium, lead, hydrochloric acid, mercury, and other HAPs. In addition, ICI boilers and process 

heaters also emit non-HAP pollutants such as sulfur dioxide and particulate matter. To inform 

this rulemaking, the Air Benefits and Costs Group (ABCG) of EPA’s Office of Air Quality 

Planning and Standards (OAQPS) has developed an economic impact analysis (EIA) to estimate 

the potential social costs of the regulation. 

This report presents the results of this analysis in which a market model was used to 

analyze the impacts of the air pollution rule on society. It is a corrected version of a final report 

prepared in February 2004 in support of the promulgation of this final rule. Corrections and 

revisions to the small entity analysis were made in response to data and statements provided as 

part of a lawsuit filed by several Ohio municipalities against EPA’s promulgation of this MACT 

standard. The effect of these corrections and revisions are found in Section 7 of this report. 

1.1 Agency Requirements for an EIA 

Congress and the Executive Office have imposed statutory and administrative 

requirements for conducting economic analyses to accompany regulatory actions. Section 317 of 

the CAA specifically requires estimation of the cost and economic impacts for specific 

regulations and standards under the authority of the Act. In addition, Executive Order (EO) 

12866 requires a more comprehensive analysis of benefits and costs for significant regulatory 

actions.1

 Other statutory and administrative requirements include examination of the composition 

and distribution of benefits and costs. For example, the Regulatory Flexibility Act (RFA), as 

amended by the Small Business Regulatory Enforcement and Fairness Act of 1996 (SBREFA), 

requires EPA to consider the economic impacts of regulatory actions on small entities. The 

Agency’s OAQPS Economic Analysis Resource Document provides detailed instructions and 

expectations for economic analyses that support rulemaking (EPA, 1999). 

 

1

 Current Office of Management and Budget (OMB) guidance under EO 12866 stipulates that a full benefit-cost 

analysis is required only when the regulatory action has an annual effect (benefits + costs) on the economy of 

$100 million or more. 
1-2 

1.2 Scope and Purpose 

The CAA’s purpose is to protect and enhance the quality of the nation’s air resources 

(Section 101(b)). Section 112 of the CAA Amendments of 1990 establishes the authority to set 

national emissions standards for HAPs. This report evaluates the economic impacts of pollution 

control requirements placed on ICI boilers and process heaters under these amendments. These 

control requirements are designed to reduce releases of HAPs into the atmosphere. 

To reduce emissions of HAPs, the Agency establishes maximum achievable control 

technology (MACT) standards. The term “MACT floor” refers to the minimum control 

technology on which MACT standards can be based. For existing major sources,2 the MACT 

floor is the average emissions limitation achieved by the best performing 12 percent of sources 

(if there are 30 or more sources in the category or subcategory). For new sources, the MACT 

floor must be no less stringent than the emissions control achieved in practice by the best 

controlled similar source. The MACT can also be chosen to be more stringent than the floor, 

considering the costs and the health and environmental impacts. 

The MACT floor will affect approximately 5,600 existing and new units. EPA developed 

annual compliance costs for model units in each of 83 different model unit types. EPA then 

linked the annualized compliance costs from the model units to the estimated existing population 

of boilers and process heaters to obtain national impact estimates. In addition, the Agency 

projected entrance of new boilers and process heaters through the year 2005, and linked the 

annualized compliance costs to these projected new units. 

The economic impacts of national compliance costs, including both existing and new 

units, on affected markets was then estimated using a computerized market model. EPA used 

changes in prices and quantities in energy markets and final product markets to estimate the 

firm-, industry-, market-, and societal-level impacts associated with the regulation. 

1.3 Organization of the Report 

The remainder of this report is divided into six sections that describe the methodology 

and presents the analysis results: 

 Section 2 provides background information on ICI boiler and process heater 

technologies. 

 

2

 A major source is defined as a stationary source or group of stationary sources located within a contiguous area 

and under common control that emits, or has the potential to emit considering control, 10 tons or more of any 

one HAP or 25 tons or more of any combination of HAPs. 
1-3 

 Section 3 profiles existing ICI boilers and process heaters by capacity, fuel type, and 

industry and presents projections of the future population of units in 2005. National 

compliance cost estimates are also presented in this section. 

 Section 4 profiles the industries with the largest number of affected facilities. 

Included are profiles of the lumber and wood products (SIC 24/NAICS 321), paper 

and allied products (SIC 26/NAICS 322), and electrical services (SIC 49/NAICS 221) 

industries. 

 Section 5 describes the methodology for assessing the economic impacts of the 

National Emission Standard for Hazardous Air Pollutants (NESHAP). 

 Section 6 presents the results of the economic analysis, including market, industry, 

and social cost impacts. 

 Section 7 provides the Agency’s analysis of the regulation’s impact on small entities. 

In addition to these sections, Appendix A details the economic model used to predict the 

economic impacts of the NESHAP, Appendix B presents the results of sensitivity analyses on 

key model assumptions, Appendix C presents results of analyses for regulatory alternative 

Option 1A., and Appendix D provides results of a sensitivity analysis based on considering riskbased compliance alternatives included in the final MACT standard. 

2-1 

SECTION 2 

BOILER AND PROCESS HEATER TECHNOLOGIES 

The three categories of combustion devices affected under the regulations are industrial, 

commercial, and institutional (ICI) boilers and process heaters. Although their primary function 

is to transfer heat generated from fuel combustion to materials used in the production process, 

the applications for boilers and process heaters are somewhat different. As a result, the primary 

industries using boilers may not be the same as those using process heaters. It is important to 

note that throughout this report the terms “boilers and process heaters,” and “units” are 

synonymous with “ICI boilers and process heaters.” Utility boilers primarily engaged in 

generating electricity are not covered by the NESHAP under analysis and are therefore excluded 

from this analysis. 

Boilers are combustion devices used to produce steam or heat water. Steam is produced 

in boilers by heating water until it vaporizes. The steam is then channeled to applications within 

a facility or group of facilities via pipes. Steam is an important power and heating source for the 

U.S. economy. It is used in the preparation or manufacturing of many key products, such as 

paper, petroleum products, furniture, and chemicals. Steam is also used to heat buildings and to 

generate the majority of the electricity consumed in this country. There are literally thousands of 

boilers currently being used in the United States throughout a wide variety of industries. 

Process heaters are primarily used as heat transfer units in which heat from fuel 

combustion is transferred to process fluids, although they may also be used to transfer heat to 

other nonfluid materials or to heat transfer materials for use in a process unit (not including 

generation of steam). Process heaters are generally used in heat transfer applications where 

boilers are inadequate. Often these are uses in which heat must be transferred at temperatures in 

excess of 90° to 204°C (200° to 400°F). Process heaters are used in the petroleum refining and 

petrochemical industries, with minor applications in the asphalt concrete, gypsum, iron and steel, 

and wood and forest products industries. 

Since one of the main uses of boilers is to generate steam, some of the characteristics of 

steam are discussed in this section. This section also provides an overview of the various types of 

boiler and process heater characteristics and designs. 

2.1 Characteristics of Steam 

Steam, an odorless, invisible gas of vaporized water, may be interspersed with water 

droplets, which gives it a cloudy appearance. It is produced naturally when underground water is 
2-2 

heated by volcanic processes and mechanically using boilers and other heating processes. When 

water is heated at atmospheric pressure, it remains in liquid form until its temperature exceeds 

212°F, the boiling point of water. Additional heat does not raise the water’s temperature but 

rather vaporizes the water, converting it into steam. However, if water is heated under pressure, 

such as in a boiler, the boiling point is higher than 212°F and more heat is required to generate 

steam. Once all the water has been vaporized into steam, the addition of heat causes the 

temperature and volume to increase. Steam’s heating and work capabilities increase as it is 

produced under greater pressure coupled with higher temperatures. As steam escapes from the 

boiler, it can be directed through pipes to drive mechanical processes or to provide heat. 

The steam used in most utility, industrial, and commercial applications is referred to as 

“clean steam.” Clean steam encompasses steam purities ranging from pure, solid-free steam used 

in critical processes to filtered steam for less demanding applications. The various types of clean 

steam differ in steam purity and steam quality. Steam purity is a quantitative measure of 

contamination of steam caused by dissolved particles in the vapor or by tiny droplets of water 

that may remain in the steam. Steam quality is a measure of how much liquid water is mixed in 

with the dry steam (Fleming, 1992). Firms select the levels of steam quality and steam purity for 

their applications based on the sensitivity of their equipment to impurities, water droplet size, 

and condensation as well as the requirements for their production process. Using clean steam 

minimizes the risk of product contamination and prolongs equipment life. Although there are 

infinite possible levels of water purity and quality, the term “clean steam” generally refers to 

three basic types of steam: 

 filtered steam—produced by filtering plant steam using high-efficiency filters. 

Filtered steam is generally of high steam quality because most large water droplets 

and other contaminants will be filtered out. 

 clean steam—steam that is frequently produced from deionized and distilled water. 

Deionized and distilled water is free of dissolved solids and ions, which may corrode 

pipework. 

 pure steam—similar to clean steam except that it is always produced from deionized 

and distilled water. 

Steam applications can be categorized by the amount of pressure required: hot water, low 

pressure, and high pressure. Low pressure is 0 to 15 pounds per square inch (psi) and high 

pressure steam is above 15 psi (Plant Engineering, 1991). Hot water systems, which generate 

little steam, are primarily used for comfort applications, such as hot water for a building. Low 

pressure applications include process heat and space heating. High pressure steam applications 

are more frequently used in industrial and utility applications. Some high pressure applications 
2-3 

require that the steam be superheated, a process which ensures that the steam is free of water 

droplets, to avoid damaging sensitive equipment. 

Electric cogenerators, such as large factories and processing facilities, use steam to drive 

turbines to generate electricity. A conventional steam electric power plant burns fossil fuels 

(coal, gas, or oil) in a boiler, releasing heat that boils water and converts it into high-pressure 

steam (see Figure 2-1). The steam enters a turbine where it expands and pushes against blades to 

turn the generator shaft and create electric current. In this way, the thermal energy of steam 

becomes mechanical energy, which is converted into electricity. Steam used to drive turbines 

generates most of the electric power in the United States (TXU, 2000). 

Figure 2-1. Generating Electricity: Steam Turbines 

Source: Texas Utilities (TXU). 2000. “Generating Electricity: Steam Turbines.” As obtained in September 2000. 

<http://www.txu.com/knowledge/energy_lib/generating01.html>. 

Industrial operations use steam to perform work such as powering complex machinery 

operations, in the same way that electric utilities use steam to rotate turbines. Textile mills, pulp 

and paper mills, and other manufacturing outfits are examples of facilities that use steam to run 

machinery. Steam also provides heat and pressure for manufacturing processes. Industrial 

establishments use steam to provide heat for drying or to heat and separate materials. For 

example, the paper industry uses steam to heat rollers that dry paper during the final stages of the 
2-4 

production process. Petroleum refineries and chemical producers use steam to heat petroleum, 

raw materials, and other inputs to separate inputs into their constituent components or to 

facilitate chemical interactions. In addition to these applications, steam is employed in many 

other industrial processes, including textile production, wood working, furniture making, metal 

working, food preparation, and the manufacture of chemicals. Substitutes for using steam as 

process heat include electrical heating equipment, infrared, and other radiant drying techniques. 

Electricity may be used to power machinery, as well. However, switching from steam-powered 

to electricity-powered machinery would require significant equipment retrofits or replacement. 

Other steam applications include heating, sanitation, food processing and preparation, 

and cleaning. In addition to using boilers to heat water, factories, hospitals, government 

buildings, schools and other large buildings use boiler-generated steam to provide space heating. 

Substitutes for boilers in heating air and water include electrical water and space heaters; 

furnaces; and other heating, ventilation, and air conditioning equipment. 

2.2 Fossil-Fuel Boiler Characterization 

Section 2.2 discusses the different classes of fossil-fuel boilers, the most common heat 

transfer configurations, and the major design types. The discussion indicates the type(s) of fuel 

that each design can use to operate. 

2.2.1 Industrial, Commercial, and Institutional Boilers 

Industrial, commercial, and institutional boilers are primarily used for process heating, 

electrical or mechanical power generation, and/or space heating. Industrial boilers are used in all 

major industrial sectors but primarily by the paper products, chemical, food, and petroleum 

industries. It is estimated that the heat input capacity for these boilers is typically between 10 and 

250 MMBtu/hr; however, larger industrial boilers do exist and are similar to utility boilers (EPA, 

1997b). Commercial/institutional boilers are generally smaller than the industrial units, with heat 

input capacities generally below 10 MMBtu/hr. These units normally supply the steam and hot 

water for space heating in a wide range of locations, including wholesale and retail trade, office 

buildings, hotels, restaurants, hospitals, schools, museums, government buildings, and airports. 

A boiler system includes the boiler itself, associated piping and valves, operation and 

safety controls, water treatment system, and peripheral equipment such as pollution control 

devices, economizers, or superheaters (Plant Engineering, 1991). Most boilers are made of steel, 

cast iron, or copper. The primary fuels used by boilers are coal, oil, and natural gas, but some use 

electricity, waste gases, or biomass. 
2-5 

Boilers may either be erected onsite (field-erected boilers) or assembled at a factory 

(packaged boilers). Packaged boilers are typically lower in initial cost and more simple to install. 

However, field-erected boilers may have lower operating costs, less maintenance, and greater 

flexibility because the furnace or convection pattern chosen to meet required steam pressure, 

capacity, and fuel specifications is tailored to the boiler’s potential use (Plant Engineering, 

1991). Applications requiring more than 100,000 pounds of steam per hour are usually equipped 

with a field-erected boiler. 

2.2.2 Heat Transfer Configurations 

The heat transfer configuration of a boiler refers to the method by which heat is 

transferred to the water. The four primary boiler configurations are watertube, firetube, cast iron, 

and tubeless. Most industrial users tend to rely on either watertube or firetube configurations. 

In a watertube boiler, combustion heat is transferred to water flowing through tubes 

lining the furnace walls and boiler passes. The furnace watertubes absorb primarily radiative 

heat, while the watertubes in the boiler passes gain heat by convective heat transfer. These units 

have a wide range of heat input capacities (ICI units range from 0.4 to 1,500 MMBtu/hr) and can 

be either field erected or packaged.3

 Watertube boilers with heat input capacities greater than 200 

MMBtu/hr are typically field erected. 

Because firetube, cast iron, and tubeless heat transfer configurations typically have heat 

input capacities below 10 MMBtu/hr, they will not generally be covered by the NESHAP. 

Therefore, this profile focuses on those boiler types that use watertube heat transfer 

configurations. 

2.2.3 Major Design Types 

This section summarizes the five major design types for fossil fuel industrial boilers that 

will be covered by the NESHAP. It also discusses, where possible, the fuels used, capacity, and 

assembly method of each of these types of boilers. 

2.2.3.1 Stoker-Fired Boilers (Coal) 

These units use underfeed air to combust the coal char on a stationary grate, combined 

with one or more levels of overfire air introduced above the grate. There are three types of stoker 

units: 

 

3

 Office of Management and Budget (OMB) guidance under EO 12866 stipulates that a full benefit-cost analysis is 

required only when the regulatory action has an annual effect on the economy of $100 million or more. 
2-6 

 spreader stokers, 

 underfeed stokers, and 

 overfeed stokers. 

Stokers generally burn all types of coal, with the exception of overfeed stokers, which do 

not burn coking bituminous coals. Stokers can also burn other types of solid fuel, such as wood, 

wood waste, and bagasse. Spreader stokers are the most common of these boiler types and have 

heat input capacities that typically range from 5 to 550 MMBtu/hr. However, some of these 

boilers have capacities as high as 1,500 MMBtu/hr. Smaller stoker units (i.e., those with heat 

input capacities less than 100 MMBtu/hr) are generally packaged, while larger units are usually 

field erected. 

2.2.3.2 Pulverized Coal Boilers (Coal) 

Combustion in pulverized coal-fired units takes place almost entirely while the coal is 

suspended, unlike in stoker units in which the coal burns on a grate. Finely ground coal is 

typically mixed with primary combustion air and fed to the burner or burners, where it is ignited 

and mixed with secondary combustion air. Depending on the location of the burners and the 

direction of coal injection into the furnace, pulverized coal-fired boilers can be classified into 

three different firing types: 

 single and opposed wall, 

 tangential, and 

 cyclone. 

Of these types, wall and tangential configurations are the most common. These firing 

methods are described further in Sections 2.2.3.4 and 2.2.3.5. 

2.2.3.3 Fluidized Bed Combustion (FBC) Boilers (Coal) 

FBC is an integrated technology for reducing sulfur dioxide (SO2) and NOx emissions 

during the combustion of coal. In a typical FBC boiler, crushed coal and inert material (sand, 

silica, alumina, or ash) and/or a sorbent (limestone) are maintained in a highly turbulent 

suspended state by the upward flow of primary air from the windbox located directly below the 

combustion floor. This fluidized state provides a large amount of surface contact between the air 

and solid particles, which promotes uniform and efficient combustion at lower furnace 

temperatures than conventional coal-fired boilers. Once the hot gases leave the combustion 

chamber, they pass through the convective sections of the boiler, which are similar or identical to 

components used in conventional boilers. 
2-7 

For the FBCs currently in use in all sectors, coal is the primary fuel source, followed in 

descending order by biomass, coal waste, and municipal waste. The heat input capacities of all 

ICI FBC units generally range from 1.4 to 1,075 MMBtu/hr. 

2.2.3.4 Tangentially Fired Boilers (Coal, Oil, Natural Gas) 

The tangentially fired boiler is based on the concept of a single flame zone within the 

furnace. The fuel-air mixture projects from the four corners of the furnace along a line tangential 

to an imaginary cylinder located along the furnace centerline. As fuel and air are fed to the 

burners and the fuel is combusted, a rotating “fireball” is formed. Primarily because of their 

tangential firing pattern, which leads to larger flame volumes and flame interaction, uncontrolled 

tangentially fired boilers generally emit relatively lower NOx than other uncontrolled boiler 

designs. 

Utilities primarily use this type of boiler. Coal is the most common fuel used by these 

units. Tangentially fired boilers operated by utilities are typically larger than 400 MW, while 

industrial ones almost always have heat input capacities over 100 MMBtu/hr. In general, most 

units with heat input capacities over 100 MMBtu/hr are field erected. 

2.2.3.5 Wall-fired Boilers (Coal, Oil, Natural Gas) 

Wall-fired boilers are characterized by multiple individual burners located on a single 

wall or on opposing walls of the furnace. In contrast to tangentially fired boilers, each of the 

burners in a wall-fired boiler has a relatively distinct flame zone, and the burners in wall-fired 

boilers do not tilt. Superheated steam temperatures are instead controlled by excess air levels, 

heat input, flue gas recirculation, and/or steam attemperation (water spray). Depending on the 

design and location of the burners, wall-fired boilers are referred to as single wall or opposed 

wall. 

Wall-fired boilers are used to burn coal, oil, or natural gas, and some designs feature 

multifuel capability. Almost all industrial wall-fired boilers have heat input capacities greater 

than 100 MMBtu/hr. Opposed-wall boilers in particular are usually much larger than 250 

MMBtu/hr heat input capacity and are much more common in utility rather than in industrial 

operations. Because of their size, most wall-fired units are field erected. Field-erected watertube 

boilers strictly designed for oil firing are more compact than coal-fired boilers with the same heat 

input, because of the more rapid combustion characteristics of fuel oil. Field-erected watertube 

boilers fired by natural gas are even more compact because of the rapid combustion rate of the 

gaseous fuel, the low flame luminosity, and the ash-free content of natural gas. 
2-8 

2.3 Process Heater Characterization

Process heaters are heat transfer units in which heat from fuel combustion is transferred 

to materials used in a production process. The process fluid stream is heated primarily for one of 

two reasons: to raise the temperature for additional processing or to make chemical reactions 

occur. This section describes the different classes of process heaters and major design types. 

2.3.1 Classes of Process Heaters 

The universe of process heaters is divided into two categories: 

 indirect-fired process heater—any process heater in which the combustion gases do 

not mix with or exhaust to the atmosphere from the same stack(s) or vent(s) with any 

gases emanating from the process or material being processed. 

 direct-fired process heater—any process heater in which the combustion gases mix 

with and exhaust to the atmosphere from the same stack(s) or vent(s) with gases 

originating from the process or material being processed. 

Indirect-fired units are used in situations where direct flame contact with the material 

being processed is undesirable because of problems with contamination and ignition of the 

process material. Direct-fired units are used where such problems are not an important factor. 

Emissions of indirect-fired units consist solely of the products of combustion (including those of 

incomplete combustion). On the other hand, direct-fired units will generate emissions consisting 

not only of the products of combustion, but also the process material(s). This means that the 

emissions from indirect-fired process heaters will be generic to the fuel in use and are common 

across industries while emissions from direct-fired process heaters are unique to a given process 

and may vary widely depending on the process material. Only indirect-fired process heaters are 

considered under this regulation. Many direct-fired process heaters are being considered under 

separate MACT-development projects. 

In addition to the distinction between direct- and indirect-fired heaters, process heaters 

may also be considered either heated feed or reaction feed. Heated feed process heaters are used 

to heat a process fluid stream before additional processing. These types of process heaters are 

used as preheaters for various operations in the petroleum refining industry such as distillation, 

catalytic cracking, hydroprocessing, and hydroconversion. In addition, heated feed process 

heaters are used widely in the chemical manufacturing industry as fired reactors (e.g., steamhydrocarbon reformers and olefins pyrolysis furnaces), feed preheaters for nonfired reactors, 

reboilers for distillation operations, and heaters for heating transfer oils. Reaction feed process 

heaters are used to provide enough heat to cause chemical reactions to occur inside the tubes 

being heated. Many chemical reactions do not occur at room temperature and require the 
2-9 

application of heat to the reactants to cause the reaction to take place. Applications include 

steam-hydrocarbon reformers used in ammonia and methanol manufacturing, pyrolysis furnaces 

used in ethylene manufacturing, and thermal cracking units used in refining operations. 

2.3.2 Major Design Types 

Process heaters may be designed and constructed in a number of ways, but most process 

heaters include burner(s), combustion chamber(s), and tubes that contain process fluids. 

Sections 2.3.2.1 through 2.3.2.4 describe combustion chambers setups, combustion air supply, 

tube configurations, and burners, respectively. 

2.3.2.1 Combustion Chamber Set-Ups 

Process heaters contain a radiant heat transfer area in the combustion chamber. This area 

heats the process fluid stream in the tubes by flame radiation. Equipment found in this area 

includes the burner(s) and the combustion chamber(s). Most heat transfer to the process fluid 

stream occurs here, but these tubes do not necessarily constitute a majority of the tubes in which 

the process fluid flows. 

Most process heaters also use a convective heat transfer section to recover residual heat 

from the hot combustion gases by convective heat transfer to the process fluid stream. This 

section is located after the radiant heat transfer section and also contains tubes filled with process 

fluid. The first few rows of tubes in this section are called shield tubes and are subject to some 

radiant heat transfer. Typically, the process fluid flows through the convective section prior to 

entering the radiant section to preheat the process fluid stream. The temperature of the flue gas 

upon entering the convective section usually ranges from 800°C to 1,000°C (1,500°F to 

2,000°F). Preheating in the convective section improves the efficiency of the process heater, 

particularly if the tube design includes fins or other extended surface areas. An extended tube 

surface area can improve efficiency by 10 percent. Extended tubes can reduce flue gas 

temperatures from 800°C to 1,000°C to (1,500°F to 2,000°F) to 120°C to 260°C (250°F to 

500°F). 

2.3.2.2 Combustion Air Supply 

Air for combustion is supplied to the burners via either natural draft (ND) or mechanical 

draft (MD) systems. Natural draft heaters use ductwork systems to route air, usually at ambient 

conditions, to the burners. MD heaters use fans in the ductwork system to supply air, usually 

preheated, to the burners. The combustion air supply must have sufficient pressure to overcome 

the burner system pressure drops caused by ducting, burner registers, and dampers. The pressure 

inside the firebox is generally a slightly negative draft of approximately 49.8 to 125 Pascals (Pa) 
2-10 

at the radiant-to-convective section transition point. The negative draft is achieved in ND 

systems via the stack effect and in MD systems via fans or blowers. 

ND combustion air supply uses the stack effect to induce the flow of combustion air in 

the heater. The stack effect, or thermal buoyancy, is caused by the density difference between the 

hot flue gas in the stack and the significantly cooler ambient air surrounding the stack. 

Approximately 90 percent of all gas-fired heaters and 76 percent of all oil-fired heaters use ND 

combustion air supply (EPA, 1993). 

There are three types of MD combustion air supply: forced draft, induced draft, and 

balanced draft. The draft types are named according to the position, relative to the combustion 

chamber, of the fans used to create the pressure difference in the process heater. All three types 

of MD heaters rely on the fans to supply combustion air and remove flue gas. In forced draft 

combustion air supply systems, the fan is located upstream from the combustion chamber, 

supplying combustion air to the burners. The air pressure supplied to the burners in a forced draft 

heater is typically in the range of 0.747 to 2.49 kilopascals (kPa). Though combustion air is 

supplied to the burners under positive pressure, the remainder of the process heater operates 

under negative pressure caused by the stack effect. In induced draft combustion air systems, the 

fan is located downstream of the combustion chamber, creating negative pressure inside the 

combustion chamber. 

This negative pressure draws, or induces, combustion air into the burner registers. 

Balanced draft combustion air systems use fans placed both upstream and downstream (forced 

and induced draft) of the combustion chamber. 

There are advantages and disadvantages for both ND and MD combustion air supply. 

One advantage to natural draft heaters is that they do not require the fans and equipment 

associated with MD combustion air supply. However, control over combustion air flow is not as 

precise in ND heaters as in MD heaters. MD heaters, unlike ND heaters, provide the option of 

using alternate sources of combustion oxygen, such as gas turbine exhaust. They also allow the 

use of combustion air preheat. Combustion air preheat has limited application in ND heaters due 

to the pressure drops associated with combustion air preheaters. 

Combustion air preheaters are often used to increase the efficiency of MD process 

heaters. The maximum thermal efficiency obtainable with current air preheat equipment is 92 

percent. Preheaters allow heat to be transferred to the combustion air from flue gas, steam, 

condensate, hydrocarbon, or other hot streams. The preheater increases the efficiency of the 
2-11 

process heater because some of the thermal energy is reclaimed that would have been exhausted 

from the hot streams via cooling towers. If the thermal energy is from a hot stream other than the 

flue gas, the entire plant’s efficiency is increased. The benefit of higher thermal efficiency is that 

less fuel is required to operate the heater. 

2.3.2.3 Tube Configurations 

The orientation of the tubes through which a process fluid stream flows is also taken into 

consideration when designing a process heater. The tubes in the convective section are oriented 

horizontally in most process heaters to allow cross-flow convection. However, the tubes in the 

radiant area may be oriented either horizontally or vertically. The orientation is chosen on a caseby-case basis according to the design specifications of the individual process heater. For 

example, the arbor, or wicket, type of heater is a specialty design to minimize the pressure drop 

across the tubes. 

2.3.2.4 Burners 

Many different types of burners are used in process heaters. Burner selection depends on 

several factors including process heat flux requirements, fuel type, and draft type. The burner 

chosen must provide a radiant heat distribution that is consistent with the configuration of the 

tubes carrying process fluid. Also, the number and location of the burner(s) depend on the 

process heater application. 

Many burner flame shapes are possible, but the most common types are flat and conical. 

Flat flames are generally used in applications that require high temperatures such as ethylene 

pyrolysis furnaces, although some ethylene furnaces use conical flames to achieve uniform heat 

distribution. Long conical flames are used in cases where a uniform heat distribution is needed in 

the radiant section. 

Fuel compatibility is also important in burner selection. Burners may be designed for 

combustion of oil, gas, or a gas/oil mixture. Gas-fired burners are simpler in operation and 

design than oil-fired burners and are classified as either premix or raw gas burners. In premix 

burners, 50 to 60 percent of the air necessary for combustion is mixed with the gas prior to 

combustion at the burner tip. This air is induced into the gas stream as the gas expands through 

orifices in the burner. The remainder of the air necessary for combustion is provided at the 

burner tip. Raw gas burners receive fuel gas without any premixed combustion air. Mixing 

occurs in the combustion zone at the burner tip. 
2-12 

Oil-fired burners are classified according to the method of fuel atomization used. 

Atomization is needed to increase the mixing of fuel and combustion air. Three types of fuel 

atomization commonly used are mechanical, air, and steam. Steam is the most widely used 

method because it is the most economical, provides the best flame control, and can handle the 

largest turndown ratios. Typical steam requirements are 0.07 to 0.16 kilogram (kg) steam/kg of 

oil. 

Combination burners can burn 100 percent oil, 100 percent gas, or any combination of oil 

and gas. A burner with this capability generally has a single oil nozzle in the center of a group of 

gas nozzles. The air needed for combustion can be controlled separately in this type of burner. 

Another option is to base load the burners with one fuel and to add the other fuel to meet 

increases in load demand. Combination burners add flexibility to the process heater, especially 

when the composition of the fuel is variable. 

The location and number of burners needed for a process heater are also determined on 

an individual basis. Burners can be located on the ceiling, walls, or floor of the combustion 

chamber. Floor- and wall-fired units are the most common burner types found in process heaters 

because they are both efficient and flexible. In particular, floor-mounted burners integrate well 

with the use of combustion air preheat, liquid fuels, and alternate sources of combustion oxygen 

such as turbine exhaust. 

The number of burners in a heater can range from 1 to over 100. In the refinery industry, 

the average number of burners is estimated at 24 in ND heaters with an average design heat 

release of 69.4 million Btu per hour (MMBtu/hr). The average number of burners is estimated at 

20 in MD heaters with ambient combustion air and an average design heat release of 103.6 

MMBtu/hr. The average number of burners is estimated at 14 in MD heaters with combustion air 

preheat and an average design heat release of 135.4 MMBtu/hr. In general, the smaller the 

number of burners, the simpler the heater will be. However, multiple burners provide a more 

uniform temperature distribution. 
3-1 

SECTION 3 

PROFILE OF AFFECTED UNITS AND FACILITIES, AND COMPLIANCE COSTS 

The floor-level MACT for the regulation will affect existing and new ICI boilers and 

process heaters that have input capacity greater than 10 million Btus and are fueled by fossil and 

nonfossil fuel solids and liquids. The economic impact estimates presented in Section 6 and the 

small entity screening analysis presented in Section 7 are based on the estimated stock of 

existing units and the projection of new units through the year 2005. They are also based on the 

compliance costs associated with applying the final rule to these units. This section begins with a 

review of the industry distribution and technical characteristics of existing boilers and process 

heaters contained in the Agency’s Inventory Database. It also presents projected growth 

estimates for boilers and process heaters through the year 2005, a description of how costs are 

estimated, and the national engineering cost estimates and cost-effectiveness (cost/ton) estimates 

by pollutant controlled. 

3.1 Regulatory Alternatives 

Section 112 of the CAA requires EPA to promulgate regulations for the control of HAP 

emissions from each source category listed under section 112(c). The statute requires the 

regulations to reflect the maximum degree of reductions in emissions of HAP that is achievable 

taking into consideration the cost of achieving emissions reductions, any nonair quality health 

and environmental impacts, and energy requirements. This level of control is commonly referred 

to as MACT. The MACT regulation can be based on the emissions reductions achievable 

through application of measures, processes, methods, systems, or techniques including, but not 

limited to: (1) reducing the volume of, or eliminating emissions of, such pollutants through 

process changes, substitutions of materials, or other modifications; (2) enclosing systems or 

processes to eliminate emissions; (3) collecting, capturing, or treating such pollutants when 

released from a process, stack, storage or fugitive emission point; (4) design, equipment, work 

practices, or operational standards as provided in subsection 112(h); or (5) a combination of the 

above. 

For new sources, MACT standards cannot be less stringent than the emission control 

achieved in practice by the best-controlled similar source. The MACT standards for existing 

sources can be less stringent than standards for new sources, but they cannot be less stringent 

than the average emission limitation achieved by the best-performing 12 percent of existing 

sources for categories and subcategories with 30 or more sources, or the best-performing 5 

sources for categories or subcategories with fewer than 30 sources. 
3-2 

In essence, these MACT standards would ensure that all major sources of air toxic 

emissions achieve the level of control already being achieved by the better-controlled and loweremitting sources in each category. This approach provides assurance to citizens that each major 

source of toxic air pollution will be required to effectively control its emissions. A major source 

of HAP emissions is any stationary source or group of stationary sources located within a 

contiguous area and under common control that emits or has the potential to emit any single 

HAP at a rate of 9.07 Mg (10 tons) or more per year or any combination of HAPs at a rate of 

22.68 Mg (25 tons) or more a year. At the same time, this approach provides a level economic 

playing field, ensuring that facilities that employ cleaner processes and good emission controls 

are not disadvantaged relative to competitors with poorer controls. 

3.1.1 Regulatory Background 

In September 1996, EPA chartered the Industrial Combustion Coordinated Rulemaking 

(ICCR) advisory committee under the Federal Advisory Committee Act (FACA). The 

committee’s objective was to develop recommendations for regulations for several combustion 

source categories under sections 112 and 129 of the CAA. The ICCR advisory committee, 

known as the Coordinating Committee, formed Source Work Groups for the various combustion 

types covered under the ICCR. One of the work groups was formed to research issues related to 

boilers. Another was formed to research issues related to process heaters. The Boiler and Process 

Heater Work Groups submitted recommendations, information, and data analysis results to the 

Coordinating Committee, which in turn considered them and submitted recommendations and 

information to EPA. The Committee’s recommendations were considered by EPA in developing 

these proposed standards for boilers and process heaters. The Committee’s 2-year charter expired 

in September 1998. 

Following the expiration of the ICCR FACA charter, EPA decided to combine boilers 

with units in the process heater source category covering indirect fired units, and to regulate both 

under this NESHAP. This was done because indirect fired process heaters and boilers are similar 

devices, burn similar fuel, have similar emission characteristics, and emissions from each can be 

controlled using similar control devices or techniques. 

3.1.2 Regulatory Authority 

Section 112 of the CAA requires that EPA promulgate regulations requiring the control 

of HAP emissions from major sources and certain area sources. The control of HAP is achieved 

through promulgation of emission standards under sections 112(d) and (f) and, in appropriate 

circumstances, work practice standards under section 112(h) of the CAA. 
3-3 

An initial list of categories of major and area sources of HAP selected for regulation in 

accordance with section 112(c) of the CAA was published in the Federal Register on July 16, 

1992 (57 FR 31576). Industrial boilers, commercial and institutional boilers, and process heaters 

are three of the listed 174 categories of sources. The listing was based on the Administrator’s 

determination that they may reasonably be anticipated to emit several of the 188 listed HAP in 

quantities sufficient to designate them as major sources. 

This rule affects industrial boilers, institutional and commercial boilers, and process 

heaters. In this rule process heaters are defined as units in which the combustion gases do not 

directly come into contact with process gases in the combustion chamber (e.g., indirect fired). 

Boiler means an enclosed device using controlled flame combustion and having the primary 

purpose of recovering thermal energy in the form of steam or hot water. A waste heat boiler (or 

heat recovery steam generator) is a device that recovers normally unused energy and converts it 

to usable heat. Waste heat boilers are excluded from this rule. A hot water heater is a closed 

vessel in which water is heated by combustion of gaseous fuel and is withdrawn for use external 

to the vessel at pressures not exceeding 160 psig. Hot water heaters are excluded from this rule. 

Boilers and process heaters emit particulate matter, volatile organic compounds, and 

hazardous air pollutants, depending on the material burned. Solid and liquid fuel-fired units emit 

metals, halogenated compounds and organic compounds. Gas fuel-fired units emit mostly 

organic compounds. 

The affected source is each individual industrial, commercial, or institutional boiler or 

process heater located at a major facility. The affected source does not include units that are 

municipal waste combustors (40 CFR part 60, subparts AAAA, BBBB or Cb), medical waste 

incinerators (40 CFR part 60, subpart Ce and Ec), fossil fuel fired electric utility steam 

generating units, commercial and industrial solid waste incineration units (40 CFR part 60 

subparts CCCC or DDDD), recovery boilers or furnaces (40 CFR part 63, subpart MM), or 

hazardous waste combustion units required to have a permit under section 3005 of the Solid 

Waste Disposal Act or are subject to 40 CFR part 63, subpart EEE. 

The rule applies to an owner or operate a boiler or process heater at a major source 

meeting the requirements in section II.C. A major source of HAP emissions is any stationary 

source or group of stationary sources located within a contiguous area and under common 

control that emits or has the potential to emit any single HAP at a rate of 9.07 Mg (10 tons) or 

more per year or any combination of HAP at a rate of 22.68 Mg (25 tons) or more a year. 
3-4 

An affected operator must meet the emission limits for the subcategories in Table 3-1 of 

this preamble for each of the pollutants listed. Emission limits were developed for new and 

existing sources; and for large, small, and limited use solid, liquid, and gas fuel fired units. Large 

units are those with heat input capacities greater than 10 MMBtu/hr. Small units are those with 

heat input capacities less than or equal to 10 MMBtu/hr. Limited use units are those with 

capacity utilizations less than or equal to 10 percent as required in a federally enforceable permit. 

If your new or existing boiler or process heater is permitted to burn a solid fuel, or any 

combination of solid fuel with liquid or gaseous fuel, the unit is in one of the solid subcategories. 

If your new or reconstructed boiler or process heater burns a liquid fuel, or a liquid fuel in 

combination with a gaseous fuel, the unit is in one of the liquid subcategories. If your new or 

existing boiler or process heater burns a gaseous fuel only, the unit is in the gas subcategory and 

is not required to meet any emission limit. 

For solid fuel-fired boilers or process heaters, we are allowing sources to choose one of 

two emission limit options: (1) existing and new affected sources may choose to limit PM 

emissions to the level listed in Table 3-1 or (2) existing and new affected sources may choose to 

limit total selected metals emissions to the level listed in Table 3-1 of this preamble. 

If you do not use an add-on control or use an add-on control other than a wet scrubber, 

you must maintain opacity level to less than or equal to the level established during the 

compliance test for mercury and PM or total selected metals, and maintain the fuel chlorine 

content to less than or equal to the operating level established during the HCl compliance test. 

If you use a wet scrubber, you must maintain the minimum pH, pressure drop and liquid 

flowrate above the operating levels established during the performance tests. 

If you use a dry scrubber, you must maintain opacity level and the minimum sorbent 

injection rate established during the performance test. 

If you use an ESP in combination with a wet scrubber and cannot monitor the opacity, 

you must maintain the average secondary current and voltage or total power input established 

during the performance test. 
3-5 

Table 3-1. Emission Limits for Boilers and Process Heaters (lb/MMBtu) 

Source Subcategory PM or

Total 

Selected 

Metals HC1

Mercury 

(Hg) 

Carbon 

Monoxide 

(CO-ppm @ 

3% oxygen) 

Solid Fuel, Large Unit 0.04 or 0.00007 0.016 0.0000026 200 

Solid Fuel, Small Unit 0.04 or 0.00007 0.032 0.0000026 — 

Solid Fuel, Limited Use 0.04 or 0.00007 0.032 0.0000026 200 

Liquid Fuel, Large Unit 0.068 — 0.00045 200 

Liquid Fuel, Small Unit 0.068 — 0.0009 — — 

Liquid Fuel, Limited Use 0.068 — 0.0009 — 200 

New 

Boiler or 

Process 

Heater 

Gaseous Fuel, Large Unit — — — — 200 

 Gaseous Fuel, Small Unit — — — — 

 Gaseous Fuel, Limited Use — — — — 200 

Solid Fuel, Large Unit 0.062 or 0.001 0.048 0.000004 — 

Solid Fuel, Small Unit — — — — — 

Solid Fuel, Limited Use 0.21 or 0.001 — — — 

Liquid Fuel, Large Unit — — — — — 

Liquid Fuel, Small Unit — — — — — 

Liquid Fuel, Limited Use — — — — — 

Existing 

Boiler or 

Process 

Heater 

Gaseous Fuel — — — — — 

There is an alternative compliance procedure and operating limit for meeting the total 

selected metals emission limit option. If you have no control or do not want to take credit of 

metals reductions with your existing control device, and can show that total metals in the fuel 

would be less than the metals emission level, then you can monitor the metals fuel analysis to 

meet the metals emissions limitations. Similarly, if you have no control or do not want to take 

credit of mercury reduction with your existing control device, and can show that mercury in the 

fuel would be less than the mercury emission level, then you can monitor the mercury fuel 

analysis to meet the mercury emission limitations. 
3-6 

3.1.3 Regulatory Alternatives and Control Technologies 

3.1.3.1 MACT Floor Development 

We considered several approaches to identifying MACT floor for existing industrial, 

commercial, and institutional boilers and process heaters. First, we considered using emissions 

data on boilers and process heaters to set the MACT floor. However, after review of the data 

available, we determined that emissions information was inadequate to set MACT floors. We 

then considered using State regulations and permits to set the MACT floors. However, we found 

no State regulations or State permits which specifically limit HAP emissions from these sources. 

Consequently, we concluded that the only reasonable approach for determining MACT 

floors is to base it on control technology. Information was available on the control technologies 

employed by the population of boilers identified by the EPA. We considered several possible 

control technologies (i.e., factors that influence emissions), including fuel substitution, process 

changes and work practices, and add-on control technologies. 

We first considered whether fuel switching would be an appropriate control option for 

sources in each subcategory. Both fuel switching to other fuels used in the subcategory and fuels 

from other subcategories were considered. This consideration included determining whether 

switching fuels would achieve lower HAP emissions. A second consideration was whether fuel 

switching could be technically done on boilers and process heaters in the subcategory 

considering the existing design of boilers and process heaters. We also considered the 

availability of the alternative fuel. 

After considering these factors, we determined that fuel switching was not an appropriate 

control technology to be included in determining the MACT floor level of control for any 

subcategory. This decision was based on the overall effect of fuel switching on HAP emissions, 

technical and design considerations discussed in section III.A of this preamble, and concerns 

about fuel availability. 

Based on the data available in the emissions database, we determined that while fuel 

switching from solid fuels to gaseous or liquid fuels would decrease PM and some metals 

emissions, emissions of some organic HAP would also increase, resulting in uncertain benefits. 

We determined that it would be inappropriate in a MACT rulemaking, that is technology based, 

to consider a technology that potentially will result in an increase in a HAP regardless of its 

potential to reduce other HAP without determining the overall benefit. Determining the benefits 

of fuel switching would require an assessment of the risk associated which each HAP emitted 
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and a determination of which fuel results in the overall lower risk taking into account the 

available control technology for each fuel. This assessment will be performed in a future 

rulemaking. 

A similar determination was made when considering fuel switching to “cleaner” fuels 

within a subcategory. For example, the term “clean coal” refers to coal that is lower in sulfur 

content and not necessarily lower in HAP content. Data gathered by EPA also indicates that 

within specific coal types HAP content can vary significantly. Switching to a “clean coal” may 

increase emissions of some HAP. Therefore, fuel switching to a “cleaner” coal would not be an 

appropriate option. Fuel switching from coal to biomass would result in similar impacts on HAP 

emissions. While metallic HAP emissions would be reduced, emissions of organics would 

increase based on information in the emissions database. 

Another factor considered was the availability of alternative fuels. Natural gas pipelines 

are not available in all regions of the U.S., and natural gas is simply not available as a fuel for 

many industrial, commercial, and institutional boilers and process heaters. Moreover, even where 

pipelines provide access to natural gas, supplies of natural gas may not be adequate. For 

example, it is common practice in cities during winter months (or periods of peak demand) to 

prioritize natural gas usage for residential areas before industrial usage. Requiring EPA regulated 

combustion units to switch to natural gas would place an even greater strain on natural gas 

resources. Consequently, even where pipelines exist some units would not be able to run at 

normal of full capacity during these times if shortages were to occur. Therefore, under any 

circumstances, there would be some units that could not comply with a requirement to switch to 

natural gas. 

Similar problems for fuel switching to biomass could arise. Existing sources burning 

biomass generally are combusting a recovered material from the manufacturing or agriculture 

process. Industrial, commercial, and institutional facilities that are not associated with the wood 

products industry or agriculture may not have access to a sufficient supply of biomass materials 

to replace their fossil fuel. 

There are many concerns with switching fuels on sources designed and operated to burn 

specific fuels. Changes to the fuel type (solid, liquid, or gas) will require extensive changes to 

the fuel handling and feeding system (e.g., a stoker using wood as fuel would need to be 

redesigned to handle fuel oil or gaseous fuel). Additionally, burners and combustion chamber 

designs are generally not capable of handling different fuel types, and generally cannot 

accommodate increases or decreases in the fuel volume and shape. Design changes to allow 
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different fuel use, in some cases, may reduce the capacity and efficiency of the boiler or process 

heater. Reduced efficiency may result in a greater degree of incomplete combustion and, thus, an 

increase in organic HAP emissions. For the reasons discussed above, we decided that fuel 

switching to “cleaner” solid fuels or to liquid or gaseous fuels would not be appropriate or 

available as a MACT floor level. 

We also determined that using process changes or work practices were not appropriate in 

developing MACT floors. HAP emissions from boilers and process heaters are primarily 

dependent upon the composition of the fuel. Fuel dependent HAP are metals, including mercury, 

and acid gases. Fuel dependent HAP are typically controlled by removing them from the flue gas 

after combustion. Therefore, they are not affected by the operation of the boiler or process 

heater. Consequently, process changes would be ineffective in reducing these fuel-related HAP 

emissions. 

On the other hand, organic HAP can be formed from incomplete combustion of the fuel. 

Data are not available that definitively show that organic HAP emissions are related to the 

operation of the boiler or process heater. Some studies indicate that organic HAP are greatly 

influence by time, turbulence and temperature. Other studies indicate that organic HAP 

emissions are not affected by the operation of the unit. The measurement of CO is generally an 

indicator of incomplete combustion since CO will burn to carbon dioxide if adequate oxygen is 

available. Correcting incomplete combustion may be accomplished through providing more 

combustion air. Therefore, we consider monitoring and maintaining CO emission levels to be 

associated with minimizing organic HAP emission levels and, thus, CO monitoring would be a 

good indicator of combustion efficiency and organic HAP emissions. 

In summary, we determined that considering process changes and work practices would 

not be appropriate in developing MACT floors for existing units. We are requesting comment, 

and information on emission reductions, on whether there are other GCP practices that would be 

appropriate for minimizing organic HAP emissions from industrial, commercial, and institutional 

boilers and process heaters. 

Consequently, we concluded that add-on control technology is the only factor that 

significantly controls HAP emissions. 

In order to determine the MACT floor based on add-on control technologies, we first 

examined the population database of existing sources. Units not meeting the definition of an 

industrial, commercial, or institutional boiler or process heater, and units located at area sources 
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were removed from the database. The remaining units were divided first into three subcategories 

based on fuel state: gaseous fuel-fired, liquid fuel-fired, and solid fuel-fired units. Each of these 

three subcategories was then further divided into subcategories based on capacity: (1) large 

boilers and process heaters (units with heat inputs greater than 10 MMBtu/hr); (2) small units 

(with a maximum rated heat input capacity of 10 MMBtu/hr or less); and (3) limited use units 

with capacity utilization less than 10 percent. 

We identified the types of air pollution control techniques currently used by existing 

boilers and process heaters in each subcategory. We ranked those controls according to their 

effectiveness in removing the different categories of pollutants; including metallic HAP and PM, 

inorganic HAP such as acid gases, mercury, and organic HAP. The EPA ranked these existing 

control technologies by incorporating recommendations made by the ICCR, and by reviewing 

emissions test data, previous EPA studies, and other literature, as well as by using engineering 

judgment. 

Based upon the emissions reduction potential of existing air pollution control techniques, 

we listed all the boilers and process heaters in the population database in order of decreasing 

control device effectiveness for each subcategory. Then the technology basis of the existing 

source MACT floor was determined for each pollutant category by identifying the bestperforming 12 percent of units. We then selected the technology used by the median unit in the 

best performing 12 percent of units (i.e., the boiler or process heater unit representing the 94th 

percentile) as the technology associated with the MACT floor level of control for each 

subcategory. As previously described, emissions data for this category is insufficient to identify 

the best-performing units. The most appropriate way to identify the average emission limitation 

achieved by the best-performing 12 percent of existing sources is to identify the technology used 

by the unit in the middle of the range of the best performing 12 percent of units, i.e., the median 

unit). 

After establishing the technology basis for the existing source MACT floor for each 

subcategory and each type of pollutant, the EPA examined the emissions data available for 

boilers and process heaters controlled by these technologies to determine achievable emission 

levels. The resulting emission levels associated with the existing source MACT floors for each 

pollutant are based on the average of the lowest three run average test data from units using the 

technology associated with the MACT floor level of control, and by incorporating operational 

variability using results from multiple tests on these best performing units. This approach 

reasonably ensures that the emission limit selected as the MACT floor represents a level of 

control that can be consistently achieved by a unit in the subcategory using the control 
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technology associated with the MACT floor. This approach is reasonable because the most 

informative way to predict the worst reasonably foreseeable performance of the best-controlled 

units, with available data, is to examine the available long-term performance of the best 

performing units that had multiple test results. In other words, the EPA considers all units with 

the same control technology that is properly designed and operated to be equally well controlled, 

even if the emission test results from such units vary considerably. 

The level of control “achieved” by the average of the top performing 12 percent of units 

is best represented by the average emissions observed from all units using the same technology 

as that employed by the unit representing the median of the top 12 percent. 

The EPA’s review of emissions data indicates that some boilers and process heaters 

within each subcategory may be able to meet the floor emission levels without using the air 

pollution control technology that is associated with the MACT floor. This is to be expected, 

given the variety of fuel types, fuel input rates, and boiler designs included within each 

subcategory and the resulting variability in emission rates. Thus, for instance, boilers or process 

heaters within the large unit solid fuel subcategory that burn lower percentages of solid fuels 

may be able to achieve the emission levels for the large unit solid fuel subcategory without the 

need for additional control devices. 

Furthermore, solid fuels, especially coal, are very heterogeneous and can vary in 

composition by location. Coal analysis data obtained from the electric utility industry in another 

rulemaking contained information on the mercury, chlorine, and ash content of various coals. A 

preliminary review of this data indicate that the composition can vary greatly from location to 

location, and also within location. Based on the range of variation of mercury, chlorine, and ash 

content in coal, it is possible for a unit with a lower performing control system to have emission 

levels lower than a unit considered to be included in the best performing 12 percent of the units. 

This situation is reflected in the emissions information used to set the MACT floor 

emission limits. In some instances there are boilers with ESP’s or other controls that achieve 

similar, or lower, outlet emission levels of non-mercury metallic HAP, PM, or mercury to fabric 

filters. In most cases, this is due to concentrations entering these other control devices being 

lower, even though the percent reduction achieved is lower than fabric filters. 

Additionally, the design of some control devices may have a substantial effect on the 

their emission reduction capability. For example, fabric filters are largely insensitive to the 

physical characteristics of the inlet gas stream. Thus, their design does not vary widely, and 
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emissions reductions are expected to be similar (e.g., 99 percent reduction of PM). However, 

ESP design can vary significantly. 

Consequently, since fuel substitution has been determined not to be an appropriate 

MACT floor control technology, EPA still considers the fabric filter to be the best-performing 

control for non-mercury metallic HAPs, PM, and mercury and only emissions information for 

fabric filters was used to develop emission limits. A detailed discussion of the MACT floor 

methodology is presented in the memorandum “MACT Floor Analysis for New and Existing 

Sources in the Industrial, Commercial, and Institutional Boilers and Process Heaters Source 

Categories” in the docket. 

Existing Solid Fuel Boilers and Process Heaters Large Units-Heat Inputs Greater than 

10 MMBtu/hr. The most effective control technologies identified for removing non-mercury 

metallic HAP and PM are fabric filters. About 14 percent of solid fuel-fired boilers and process 

heater use fabric filters. Because this is the technology used by the 94th percentile (the median of 

the best-performing 12 percent), the EPA considers a fabric filter to be the technology basis for 

the MACT floor for non-mercury metallic HAP control for existing boilers and process heaters 

in this subcategory. 

The most effective control technologies identified for removing inorganic HAP that are 

acid gases, such as hydrogen chloride, are wet scrubbers and packed bed scrubbers. These 

technologies are used by about 12 percent of the boilers and process heaters in the solid fuel 

subcategory. About 10 percent of solid-fired boilers and process heaters use wet scrubbers, and 

approximately 1 percent use packed bed scrubbers. Because wet scrubbers are the technology 

used by the 94th percentile (median of the best-performing 12 percent), the EPA considers a wet 

scrubber to be the technology basis for the MACT floor for acid gas control for existing boilers 

and process heaters in the solid fuel subcategory. The MACT floor emission level based on wet 

scrubbers and incorporating operational variability is 0.048 lb HCl/MMBtu. 

Based on test information on utility boilers, we have concluded that fabric filters are most 

effective in controlling mercury, and units having them would constitute the best controlled 

mercury sources. As discussed previously, more than 6 percent of sources in the subcategory 

have fabric filters. The MACT floor emission level based on fabric filters and incorporating 

operational variability is 0.000004 lb mercury/MMBtu. 

For organic HAP, we assessed whether maintaining and monitoring CO levels would be 

part of the MACT floor, and determined that less than 6 percent of the units in this subcategory 
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do so. Therefore, we concluded the MACT floor for existing sources in this subcategory is no 

emissions reductions for organic HAP. 

Therefore, the EPA determined that the combination of fabric filter and wet scrubber 

control technologies forms the basis for the MACT floor level of control for existing solid fuel 

boilers or process heaters in this subcategory. We recognize that some boilers and process 

heaters that use technologies other than those used as the basis of the MACT floor can achieve 

the MACT floor emission levels. For example, emission test data show that many boilers with 

well-designed and operated ESP can meet the MACT floor emission levels for non-mercury 

metallic HAP and PM, even though the floor emission level for these pollutants is based on a 

fabric filter (however, we would not expect that all units using ESP would be able to meet the 

proposed rule). 

Small Units—Heat Inputs Less than or Equal to 10 MMBtu/hr. Less than 6 percent of the 

units in this subcategory used control techniques that would reduce non-mercury metallic HAP 

and PM, mercury, and inorganic HAP, such as HCl. Also, maintaining and monitoring CO levels 

was used by less than 6 percent of the units in the subcategory. 

Therefore, we determined that the MACT floor emission level for existing units for any 

of the pollutant categories in this subcategory is no emissions reductions. 

Limited Use Units—Capacity Utilizations Less than or Equal to 10 Percent. The most 

effective control technologies identified for removing non-mercury metallic HAP and PM are 

ESP and fabric filters. Less than 2 percent of solid fuel-fired boilers and process heater in this 

subcategory use fabric filters, and 14 percent use ESP. Because ESP are the technology used by 

the 94th percentile (the median of the best-performing 12 percent), the EPA considers an ESP to 

be the technology basis for the MACT floor for non-mercury metallic HAP control for existing 

boilers and process heaters in the solid fuel subcategory. A PM level is set as a surrogate for nonmercury metallic HAP control. The MACT floor emission level based on ESPs, considering 

operational variability, is 0.021 lb PM/MMBtu. We are also providing an alternative metals limit 

of 0.001 lb metals/MMBtu which can be used to show compliance in cases where metal HAP 

emissions are low in proportion to PM emissions. 

Similar control technology analyses were done for the boilers and process heaters in this 

subcategory for the other pollutant groups of interest, including inorganic HAP, organic HAP 

and mercury. Less than 6 percent of the units in this subcategory have controls that would reduce 

emissions of organic HAP, mercury, and inorganic HAP, so the existing source MACT floor for 
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those pollutants is no emissions reductions. Therefore, we determined that ESP control 

technology, which achieves non-mercury metallic HAP and PM control forms the basis for the 

MACT floor level of control for existing solid fuel boilers and process heaters in this 

subcategory. 

Existing Liquid Fuel Boilers and Process Heaters. Emissions data for liquid 

subcategories was inadequate to identify the best-performing sources for reasons described in 

section D of the preamble. We also found no State regulations or permits which specifically limit 

HAP emissions from these sources. Therefore, we examined control technology data to identify a 

MACT floor. We found that less than 6 percent of the units in each of the liquid subcategories 

used control techniques that would reduce non-mercury metallic HAP and PM, mercury, organic 

HAP, or inorganic HAP (such as HCl). Therefore, we determined that the control technique 

associated with the 94th percentile (the median of the best-performing 12 percent) could not be 

identified. 

Therefore, we are unable to identify the best performing 12 percent of units in the 

subcategories. In light of this analysis, we concluded the MACT floor for existing sources in 

these liquid subcategory is no emissions reductions for non-mercury metallic HAP, mercury, 

inorganic HAP, and organic HAP. 

Existing Gaseous Fuel Boilers and Process Heaters. Emissions data for gas subcategories 

was inadequate to identify the best-performing sources for reasons described in section D of the 

preamble. We also found no State regulations or permits which specifically limit HAP emissions 

from these sources. Therefore, we examined control technology data to identify a MACT floor. 

We found that no existing units in the gaseous fuel-fired subcategories were using control 

technologies that achieve consistently lower emission rates than uncontrolled sources for any of 

the pollutant groups of interest. Therefore, we are unable to identify the best performing 12 

percent of units in the subcategories. Consequently, the EPA determined that no existing source 

MACT floor based on control technologies could be identified for gaseous fuel-fired units. 

Therefore, we concluded the MACT floor for existing sources in this subcategory is no 

emissions reductions for non-mercury metallic HAP, mercury, inorganic HAP, and organic HAP. 

3.1.3.2 Consideration of Options Beyond the Floor for Existing Units 

Once the MACT floor determinations were done for each subcategory, the EPA 

considered various regulatory options more stringent than the MACT floor level of control (i.e., 

technologies or other work practices that could result in lower emissions) for the different 

subcategories. 
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Maintaining and monitoring CO levels was identified as a possible control for organic 

HAPs. However, less than 6 percent of the sources in the existing source subcategories used this 

control method and it was not considered the MACT floor control technology. We then looked at 

it as an above-the-floor option. However, information was not available to estimate the HAP 

emissions reductions that would be associated with CO monitoring and emission limits. This 

option would also require a high cost to install and operate CO monitors. Given the cost and the 

uncertain emissions reductions that might be achieved, we chose to not require CO monitoring 

and emission limits as MACT. 

The following sections discuss the above-the-floor options analyzed to control emissions 

of metallic HAP, mercury, and inorganic HAP. Based on the analysis described in these sections, 

the EPA decided to not go beyond the MACT floor level of control for the proposed rule for any 

of the subcategories of existing sources. 

Existing Solid Fuel Units. Large Units—Heat Inputs Greater than 10 MMBtu/hr. Besides 

fuel switching (see section III.D of this preamble), we identified a better designed and operated 

fabric filter (the MACT floor for new units) as a control technology that could achieve greater 

emissions reductions of metallic HAP and PM emissions than the MACT floor level of control 

(i.e., a typical existing fabric filter). Consequently, the EPA analyzed the emissions reductions 

and additional cost of adopting an emission limit representative of the performance of a unit with 

a better designed and operated fabric filter. The additional annualized cost to comply with this 

emission limit was estimated to be approximately $500 million with an additional emission 

reduction of approximately 100 tons of metallic HAP. The results indicated that while additional 

emissions reductions would be realized, the costs would be too high to consider it a feasible 

above the floor option. Non-air quality health, environmental impacts, and energy effects were 

not significant factors, because there would be little difference in the non-air quality health and 

environmental impacts of replacing existing fabric filters with improved performance fabric 

filters. Therefore, we did not select these controls as MACT. Fuel switching was not considered 

a feasible beyond-the-floor option for the same reasons described in section III.E of the proposal 

preamble. 

We identified packed bed scrubbers as a control technology that could achieve greater 

emissions reductions of inorganic HAP, like HCl, than the MACT floor level of control (i.e., a 

wet scrubber). Consequently, the EPA analyzed the emissions reductions and additional cost of 

adopting an emission limit representative of the performance of a unit with a packed bed 

scrubber. The additional annualized cost to comply with this emission limit (using a packed bed 

scrubber) was estimated to be approximately $900 million with an additional emission reduction 
3-15 

of approximately 20,000 tons of HCl. The results indicated that while additional emissions 

reductions would be realized, the costs would be too high to consider it a feasible above the floor 

option. Non-air quality health, environmental impacts, and energy effects were not significant 

factors, because there would be little difference in the non-air quality health and environmental 

impacts between packed bed scrubbers and wet scrubbers. Therefore, we did not select these 

controls as MACT. 

In reviewing potential regulatory options for existing sources, the EPA identified one 

existing industrial boiler that was using a technology, carbon injection, used in other industries to 

achieve greater control of mercury emissions than the MACT floor level of control. However, 

emission data indicated that this unit was not achieving mercury emission reductions. The EPA 

does not have information that would show carbon injection is effective for reducing mercury 

emissions from industrial, commercial, and institutional boilers and process heaters. Therefore, 

carbon injection was not evaluated as a regulatory option. 

However, the EPA requests comments on whether carbon injection should be considered 

as a beyond-the-floor option and whether existing industrial, commercial, or institutional boilers 

and process heaters could use carbon injection technology, or other control techniques to 

consistently achieve mercury emission levels that are lower than levels from similar sources with 

the MACT floor level of control. The EPA is aware that research continues on ways to improve 

mercury capture by PM controls, sorbent injection, and the development of novel techniques. 

The EPA requests comment and information on the effectiveness of such control technologies in 

reducing mercury emissions. 

Small Units—Heat Inputs Less than or Equal to 10 MMBtu/hr. The EPA could not 

identify a technology-based level of control for the MACT floor for this subcategory. To control 

non-mercury metallic HAP and mercury, we analyzed the above the floor option of a fabric filter 

which was identified as the most effective control device for non-mercury metallic HAP and 

mercury. To control inorganic HAP such as hydrogen chloride, we analyzed the above the floor 

option of a wet scrubber since it was identified as the least cost option. 

The total annualized cost of complying with the fabric filter option was estimated to be 

$10 million, with an estimated emission reduction of 1.9 tons per year of non-mercury metallic 

HAP and 0.003 tons of mercury. The annualized cost of complying with the wet scrubber option 

was estimated to be $11 million, with an emission reduction of 48 per year of HCl. The results of 

this analysis indicated that while additional emissions reductions could be realized, the costs 

would be too high to consider them feasible options. Therefore, we did not select these controls 
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as MACT. Non-air quality health, environmental impacts, and energy effects were not significant 

factors. 

Limited Use Units—Capacity Utilizations Less than or Equal to 10 Percent. The MACT 

floor level of control for this subcategory for non-mercury metallic HAP control is an ESP. 

Although fabric filters were identified as being more effective, many ESP can achieve similar 

levels. Any additional emission reduction from using a fabric filter would be minimal and costly 

considering retrofit costs for existing units that already have ESP. Therefore, an above-the-floor 

option for metallic HAP was not analyzed in detail, and we did not select fabric filters as MACT. 

However, an above the floor option of a fabric filter was analyzed for mercury control. The total 

annualized costs of the fabric filter option was estimated to be an additional $21 million, with an 

estimated emission reduction of 0.04 tons of mercury. 

The EPA could not identify a technology-based level of control for the MACT floor for 

inorganic HAP in this subcategory. To control inorganic HAP, we analyzed the above-the-floor 

option of a wet scrubber since it was identified as the least cost option. The total annualized costs 

of the wet scrubber option was estimated to be $49 million, with an estimated emission reduction 

of 463 tons per year of HCl. 

The results of the above the floor options analyses indicated that while additional 

emissions reductions could be realized, the costs would be too high to consider them feasible 

options. Therefore, we did not select these controls as MACT. Non-air quality health, 

environmental impacts, and energy effects were not significant factors. 

Existing Liquid Fuel Units. For the liquid fuel subcategories, the EPA could not identify a 

technology-based level of control for the MACT floor. For beyond-the-floor options for the 

liquid subcategory, the EPA identified several PM controls (e.g., fabric filters, electrostatic 

precipitators, and venturi scrubbers) that would reduce non-mercury metallic HAP emissions. 

For the above-the-floor analysis, we analyzed the cost and emission reduction of applying a high 

efficiency PM control device, such as a fabric filter, since these would be more likely to be 

installed for units firing liquid fuel. We identified wet scrubbers as a technology option beyond 

the floor for reduction of inorganic HAP, such as HCl. We identified fabric filters as a 

technology option beyond the floor for reduction of mercury. Consequently, the EPA analyzed 

the emissions reductions and additional cost of applying high efficiency PM controls and wet 

scrubbers on liquid fuel-fired units. The additional total annualized cost of a high efficiency PM 

control device (such as a fabric filter) was estimated to be $460 million, with an additional 

estimated emission reduction of 1,500 tons per year for non-mercury metallic HAP and 3 tons 
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per year for mercury. The annualized cost of a wet scrubbers was estimated to be an additional 

$480 million, with an additional HCl reduction of 30 tons per year. The results indicated that 

while additional emissions reductions would be realized, the costs would be too high to consider 

them feasible options. Non-air quality health, environmental impacts, and energy effects were 

not significant factors. Therefore, the EPA chose to not select these controls as MACT for 

existing liquid units. 

Existing Gas-fired Units. For the gaseous fuel subcategories, the EPA could not identify a 

technology-based level of control for the MACT floor. The great majority, if not all, of the 

emissions from gas-fired units are organic HAP. As discussed in section III.E of the preamble, 

CO monitoring and emission limits were considered as an above the floor option but was not 

selected as MACT given the costs and uncertain reductions achieved. Therefore, no above the 

floor control technique was analyzed for organic HAPs, and MACT is no emission reduction of 

non-mercury metallic HAP and mercury, inorganic HAP, and organic HAP. 

Fuel Switching as a Beyond-the-floor Option. For the solid fuel and liquid fuel 

subcategories, fuel switching to natural gas is a regulatory option more stringent than the MACT 

floor level of control that would reduce mercury, metallic HAP, and inorganic HAP emissions. 

We determined that fuel switching was not an appropriate above-the-floor option for the reasons 

discussed in sections III.A and III.D of this proposal preamble. In some cases, organic HAP 

would be increased by fuel switching. Additionally, the estimated emissions reductions that 

would be achieved if solid and liquid fuel units switched to natural gas were compared with the 

estimated cost of converting existing solid fuel and liquid fuel units to fire natural gas. The 

annualized cost of fuel switching was estimated to be $12 billion. The additional emission 

reduction associated with it was estimated to be 1,500 tons per year for metallic HAP, 11 tons 

per year for mercury, and 13,000 tons per year for inorganic HAP. Additional detail on the 

calculation procedures is provided in the memorandum “Development of Fuel Switching Costs 

and Emissions reductions for Industrial, Commercial, and Institutional Boilers and Process 

Heaters” in the docket. 

3.1.3.3 EPA Response to Recent Court Decisions in Developing the Emission Limitations 

In developing the emission limitations, we tried to be responsive to the recent court 

decisions from National Lime Association v. EPA and Cement Kiln Recycling Coalition v. EPA, 

regarding the methodology used for determining the MACT floor. In response, we determined 

that the most acceptable and appropriate approach for determining the MACT floor appears to be 

using only emission data. As discussed and explained in section II.E of the proposal preamble, 
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we determined that for these source categories and the subcategories established the use of only 

the available emission data would be inappropriate for determining the MACT floor for existing 

and new units. If only the available emission data (from a population of units that is deemed 

unrepresentative) is used, the resulting MACT floor emission levels would be, in most many 

cases, unachievable. This is because the concentration of HAP (metals, HCl, mercury) vary 

greatly within each fuel type. Some even have fuel analysis levels below the detection limit. 

Therefore, some units without any add-on controls have emission levels below those with add-on 

controls. Section III.E of the proposal preamble explains in more detail the approach used to 

develop the MACT floors for each subcategory and why the approach is appropriate for the 

subcategories regulated by this rule and why the mandating of fuel choice (using low HAPcontaining fuel) is also inappropriate. 

In terms of subcategorizing, the main difficulty of establishing a separate subcategory for 

each specific fuel type is that many industrial boilers burn a combination of fuels. Determining 

which subcategory applies if the mixture varies would be problematic. Would the applicable 

emission limits change each time the fuel mixture changes? How would compliance be 

determine and how would continuous compliance be monitored? Because of these concerns, 

EPA chose not to further subcategorize sources by each specific fuel type. 

However, if we were to further subcategorize solid-fuel units into separate fossil and nonfossil subcategories, we would first determine if the MACT floor could be developed, for either 

subcategory, based on emissions information. If not, then we would look at developing MACT 

floors based on control technologies. First we would determine if fuel switching or work 

practices could be used. Based on the MACT floor analysis for solid-fuel fired boilers, it is 

expected that emissions information and fuel switching would not be appropriate to develop the 

MACT floors for a solid fossil or solid non-fossil subcategory. Similarly, there would be an 

insufficient number of boilers or process heaters that would be meeting CO limits to set a level 

for existing units. However, new units would likely be subject to a CO limit and monitoring. 

In order to determine the MACT floor based on add-on control technologies, we would 

follow similar procedures described in section III.E of the preamble. We would examine the 

population database of existing sources and subcategorize solid fossil and non-fossil fuel fired 

boilers into each of the following three subcategories based on capacity: (1) large boilers and 

process heaters (units with heat inputs greater than 10 MMBtu/hr); (2) small units (with a 

maximum rated heat input capacity of 10 MMBtu/hr or less); and (3) limited use units with 

capacity utilization less than 10 percent. 
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We would identify the types of air pollution control techniques currently used by existing 

boilers and process heaters in each subcategory. Then we would rank those controls according to 

their effectiveness in removing the different categories of pollutants; including metallic HAP and 

PM, inorganic HAP such as acid gases, mercury, and organic HAP. 

Based upon the emissions reduction potential of existing air pollution control techniques, 

we would list all the boilers and process heaters in the population database in order of decreasing 

control device effectiveness for each subcategory. Then the technology basis of the existing 

source MACT floor would be determined for each pollutant category by identifying the bestperforming 12 percent of units. We would then selected the technology used by the median unit 

in the best performing 12 percent of units (i.e., the boiler or process heater unit representing the 

94th percentile) as the technology associated with the MACT floor level of control for each 

subcategory. 

After establishing the technology basis for the existing source MACT floor for each 

subcategory and each type of pollutant, we would examine the emissions data available for 

boilers and process heaters controlled by these technologies to determine achievable emission 

levels. The resulting emission levels associated with the existing source MACT floors for each 

pollutant would be based on the average of the lowest three run average test data from units 

using the technology associated with the MACT floor level of control, and by incorporating 

operational variability using results from multiple tests on these best performing units. 

The preliminary MACT floor control technology for solid fossil-fuel fired units would be 

a combination of a fabric filter and a scrubber. The preliminary MACT floor control technology 

for solid non-fossil-fuel fired units would be a combination of an ESP and a scrubber. 

3.1.3.4 How did EPA Determine the Emission Limitations for New Units? 

All standards established pursuant to section 112 of the CAA must reflect MACT, the 

maximum degree of reduction in emissions of air pollutants that the Administrator, taking into 

consideration the cost of achieving such emissions reductions, and any non-air quality health and 

environmental impacts and energy requirements, determines is achievable for each category. The 

CAA specifies that the degree of reduction in emissions that is deemed achievable for new 

boilers and process heaters must be at least as stringent as the emissions control that is achieved 

in practice by the best-controlled similar unit. However, the EPA may not consider costs or other 

impacts in determining the MACT floor. The EPA may require a control option that is more 

stringent than the floor (beyond-the-floor) if the Administrator considers the cost, environmental, 

and energy impacts to be reasonable. 
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Determining the MACT floor for New Units. Similar to the MACT floor process used for 

existing units, we considered several approaches to identifying MACT floors for new industrial, 

commercial, and institutional boilers and process heaters. First, we considered using emissions 

data on boilers and process heaters to set the MACT floor. However, after review of the data 

available, we determined that emissions information was inadequate to set MACT floors. We 

also reviewed State regulations and permits for these sources, but found no State regulations or 

State permits which specifically limit HAP emissions from industrial, commercial, and 

institutional boilers and process heaters. 

Consequently, we concluded that the only reasonable approach for determining MACT 

floors is to base it on control technology. Data were available on the control technologies 

employed by the population of boilers identified by the EPA. We considered several possible 

control technologies (i.e., factors that influence emissions), including fuel substitution, process 

changes and work practices, and add-on control technologies. 

We first considered whether fuel switching would be an appropriate control option for 

sources in each subcategory. Both fuel switching to other fuels used in the subcategory and fuels 

from other subcategories were considered. This consideration included determining whether 

switching fuels would achieve lower HAP emissions. A second consideration was whether fuel 

switching could be technically done on boilers and process heaters in the subcategory 

considering the existing design of boilers and process heaters. We also considered the 

availability of the alternative fuel. 

As discussed in section III.D of the proposal preamble, based on the data available in the 

emissions database, we determined that while fuel switching would decrease some HAPs, 

emissions of some organic HAPs would increase, resulting in uncertain benefits. We determined 

that it would be inappropriate in a MACT rulemaking, that is technology based, to consider a 

technology that potentially will result in an increase in a HAP regardless of its potential to reduce 

other HAP without determining the overall benefit. A detailed discussion of the consideration of 

fuel switching is discussed in proposal preamble section III.D. 

We also determined that using process changes or work practices were not appropriate in 

most cases for developing MACT floors. HAP emissions from boilers and process heaters are 

primarily dependent upon the composition of the fuel. Fuel dependent HAP are metals, including 

mercury, and acid gases. Fuel dependent HAP are typically controlled by removing them from 

the flue gas after combustion. Therefore, they are not affected by the operation of the boiler or 

process heater. Consequently, process changes would be ineffective in reducing their emissions. 
3-21 

The exception to this conclusion is monitoring and maintaining CO levels. The measurement of 

CO is generally an indicator of incomplete combustion since CO will burn to carbon dioxide if 

adequate oxygen is available. Correcting incomplete combustion may be accomplished through 

providing more combustion air. Therefore, we consider monitoring and maintaining CO 

emission levels to be associated with minimizing organic HAP emission levels and, thus, CO 

monitoring would be a good indicator of combustion efficiency and organic HAP emissions. As 

discussed in the final preamble, CO is considered a surrogate for organic HAP emissions in this 

rule. 

To determine if CO monitoring would be the basis of the new source MACT floor for 

organic emissions control, we examined available information. The population databases did not 

contain information on existing units monitoring CO emissions. We reviewed State regulations 

applicable to boilers and process heaters that required the use of CO monitoring to maintain a 

specific CO limit. The analysis of the State regulations indicated that at least one of the boilers 

and process heaters in the large and limited use subcategories for solid fuel, liquid fuel, and 

gaseous fuel were required to monitor CO emissions and meet a CO limit of 200 parts per 

million. Therefore, the new source MACT floor level of control includes a CO emission limit of 

200 parts per million for large and limited use units. 

We concluded that, except for CO monitoring for organic HAP, add-on control 

technology is the only factor that significantly controls emissions. To determine the MACT floor 

for new sources, the EPA reviewed the population database of existing major sources. 

Based upon the emission reduction potential of existing air pollution control devices, the 

EPA listed all the boilers and process heaters in the population database in order of decreasing 

control device effectiveness for each subcategory and each type of pollutant. Once the ranking of 

all existing boilers and process heaters was completed for each subcategory and type of 

pollutant, the EPA determined the technology basis of the new source MACT floor by 

identifying the best-controlled source using the air pollution control rankings. 

After establishing the technology basis for the new source MACT floor for each 

subcategory and each type of pollutant, the EPA examined the emissions data available for 

boilers and process heaters controlled by these technologies to determine achievable emission 

levels for PM (as a surrogate for non-mercury metallic HAP), total selected non-mercury 

metallic HAP, mercury, HCl (as a surrogate for inorganic HAP), and CO (as a surrogate for 

organic HAP). This approach is reasonable because the most informative way to predict the 

worst reasonably foreseeable performance of the best-controlled unit, with available data, is to 
3-22 

examine the performance of other units that use the same technology. In other words, the EPA 

considers all units with the same control technology to be equally well controlled, and each unit 

with the best control technology is a “best controlled similar unit” even if the emission test 

results from such units vary considerably. 

Accordingly, we selected as the floor for new units the level of control that was being 

achieved in practice by the best-controlled similar source, that is, the source with emissions 

representing the performance of the most effective control technology under the worst 

reasonably foreseeable circumstances. A detailed description of the MACT floor determination is 

in the memorandum “MACT Floor Analysis for New and Existing Sources in the Industrial, 

Commercial, and Institutional Boilers and Process Heaters Source Categories” in the docket. 

New Solid Fuel-fired Units. Large Units—Heat Inputs Greater than 10 MMBtu/hr. The 

most effective control technology identified for removing PM from boilers in this subcategory is 

fabric filters. Therefore, the EPA considers a fabric filter to be the technology basis for the new 

source MACT floor for non-mercury metallic HAP emissions. The MACT floor emission level 

based on fabric filters is 0.04 lb PM/MMBtu. This PM emission level was selected from a subset 

of fabric filters contained in the database. This subset includes fabric filters assumed to be 

subject or achieving the NSPS for industrial boilers. The NSPS (40 CFR 60.40b), which 

represent best demonstrated technology for criteria pollutants, is based on the use of a fabric 

filter for PM and requires the use of a scrubber for sulfur dioxide. Therefore, fabric filters 

subjected to the NSPS are assumed to be better designed, and operated than those built prior to 

the NSPS. 

We are also providing an alternative metals limit of 0.00007 lb metals/MMBtu which can 

be used to show compliance in cases where metal HAP emissions are low in proportion to PM 

emissions. The emissions database indicates that some biomass units have low metals content but 

high PM emissions. The emission level for metals was selected from metals test data associated 

with PM emission tests from fabric filters that met the MACT floor PM emission level. The most 

effective control technologies identified for removing inorganic HAP including acid gases, such 

as HCl, are wet scrubbers and packed bed scrubbers. Wet scrubbers is a generic term that is most 

often used to describe venturi scrubbers, but can include packed bed scrubbers, impingement 

scrubbers, etc. One percent of boilers and process heaters in this subcategory reported using a 

packed bed scrubber. Emission test data from other industries suggests that packed bed scrubbers 

achieve consistently lower emission levels than wet scrubbers. Therefore, the EPA considers a 

packed bed scrubber to be the technology basis for the new source MACT floor for acid gas 
3-23 

control for boilers and process heaters in the solid fuel subcategory. The MACT floor emission 

level based on packed scrubbers is 0.016 lb HCl/MMBtu. 

For mercury control, one technology, carbon injection, that has demonstrated mercury 

reductions in other source categories (i.e., municipal waste combustors), was identified as being 

used on one existing industrial boiler. However, test data on this carbon injection system 

indicated that this unit was not achieving mercury emissions reductions. Therefore, we did not 

consider carbon injection to be a MACT floor control technology for industrial, commercial, and 

institutional boilers and process heaters. Data from electric utility boilers indicate that fabric 

filters can achieve mercury emissions reductions. Therefore, the EPA considers a fabric filter to 

be the control technology basis for controlling mercury in this subcategory. The MACT floor 

emission level based on fabric filters is 0.0000026 lb mercury/MMBtu. 

Similar control technology analysis was done for the boilers and process heaters in this 

subcategory for organic HAP. One control technique, controlling inlet temperature to the PM 

control device, that has demonstrated controlling downstream formation of dioxins in other 

source categories (e.g., municipal waste combustors) was analyzed for industrial boilers. Inlet 

and outlet dioxins test data were available on four boilers controlled with PM control devices. In 

all cases, no increase in dioxins emissions were indicated across the PM control device even at 

high inlet temperatures. However, we are requesting comment on controls that would achieve 

reductions of organic HAP, including any additional data that might be available. The EPA did 

find that CO monitoring can reduce organic HAP emissions, and has included it in the new 

source MACT floors as described under section III.F. of this preamble. 

In light of this analysis, the EPA determined that the combination of a fabric filter, a 

packed bed scrubber, and CO monitoring forms the control technology basis for the new source 

MACT floor for boilers and process heaters in this subcategory. 

Small Units—Heat Inputs Less than or Equal to 10 MMBtu/hr. The most effective 

control technologies identified for removing non-mercury metallic HAP used by units in this 

subcategory are fabric filters. Therefore, the EPA considers fabric filters to be the technology 

basis for the new source MACT floor for non-mercury metallic HAP control in this subcategory. 

The most effective control technology identified for units in this subcategory for removing acid 

gases, such as HCl, are wet scrubbers. The most effective control technologies identified for 

removing mercury used by units in this subcategory are fabric filters. 
3-24 

The EPA identified no control technology being used in the existing population of boilers 

and process heaters that consistently achieved lower emission rates than uncontrolled levels, 

such that a best-controlled similar source for organic HAP could be identified. We concluded the 

MACT floor for new sources in this subcategory is no emissions reductions for organic HAP. 

Furthermore, CO monitoring is not required for small boilers and process heaters by any State 

rules. 

Thus, the EPA determined that the combination of a fabric filter and a wet scrubber forms 

the control technology basis for the new source MACT floor for boilers and process heaters in 

this subcategory. 

The emissions test database did not contain test data for boilers and process heaters less 

than 10 MMBtu/hr heat input. In order to develop emission levels for this subcategory, we 

decided to use information from units in the large solid subcategory. We considered this to be an 

appropriate methodology because although the units in this subcategory are different enough to 

warrant their own subcategory (i.e., different designs and emissions), emissions of the specific 

HAP for which limits are being proposed (HCl, PM and metals) are expected to be related more 

to the type of fuel burned and the type of control used than to the unit design. Consequently, we 

determined that emissions information from units greater than 10 MMBtu/hr heat input could be 

used to establish the MACT floor levels for this subcategory for HCl, non-mercury metallic HAP 

(using PM as a surrogate), and mercury because the fuels and controls are similar. 

The MACT floor emission level based on emissions data for fabric filters on solid fuelfired boilers is 0.04 lb PM/MMBtu or 0.00007 lb selected non-mercury metals/MMBtu, and 

0.0000026 mercury/MMBtu. The MACT floor emission level based on wet scrubbers is 0.032 lb 

HCl/MMBtu. We are requesting comment on using emission data from another subcategory to 

develop emission levels for this subcategory. We are also requesting any available emissions 

information for this subcategory. 

Limited Use Units—Capacity Utilizations Less than or Equal to 10 Percent. The most 

effective control technologies identified for removing non-mercury metallic HAP and mercury 

used by units in this subcategory are fabric filters. Therefore, the EPA considers fabric filters to 

be the technology basis for the new source MACT floor for non-mercury metallic HAP and 

mercury control in this subcategory. The most effective control technology identified for units in 

this subcategory for removing acid gases, such as hydrogen chloride, are wet scrubbers. 
3-25 

The EPA did find that monitoring CO is used by at least one unit and can reduce organic 

HAP emissions, and has included it in the new source MACT floor for this subcategory as 

described under section III.F of this preamble. 

Therefore, based on this analysis, the EPA determined that the combination of a fabric 

filter, a wet scrubber, and CO monitoring forms the control technology basis for the new source 

MACT floor for boilers and process heaters in this subcategory. 

Consequently, we determined that emissions information from units greater than 10 

MMBtu/hr heat input could be used to establish MACT floor levels for this subcategory because 

the fuels and controls are similar. The MACT floor emission level based on fabric filters is 0.04 

lb PM/MMBtu or 0.00007 lb metals/MMBtu, and 0.0000026 mercury/MMBtu. The MACT floor 

emission level based on wet scrubbers is 0.032 lb HCl/MMBtu. We are requesting comment on 

using emission data from another subcategory to develop emission levels for this subcategory. 

We are also requesting any available emissions information for this subcategory. 

New Liquid Fuel-fired Units. Large Units—Heat Inputs Greater than 10 MMBtu/hr. The 

most effective control technologies identified for removing non-mercury metallic HAP and PM 

from units in this subcategory are fabric filters. Therefore, the EPA considers a fabric filter to be 

the technology basis for the new source MACT floor for non-mercury metallic HAP. A PM level 

is set as a surrogate for non-mercury metallic HAP control. The MACT floor emission level 

based on emission data for fabric filters on liquid fuel fired boilers is 0.068 lb PM/MMBtu. 

Unlike for solid fuel subcategories, we are not aware of any liquid fuels that are low in metals 

but would have high PM emissions. Therefore, we are not proposing an alternative metals 

standard for the liquid subcategories. 

The most effective control technologies identified for removing inorganic HAP that are 

acid gases, such as HCl, are packed bed scrubbers. Therefore, the EPA considers a packed bed 

scrubber to be the technology basis for the new source MACT floor for acid gas control for 

boilers and process heaters in the liquid fuel subcategory. The MACT floor emission level based 

on packed scrubbers is 0.00045 lb HCl/MMBtu. 

Similar control technology analyses were done for the boilers and process heaters in this 

subcategory for mercury and organic HAP. 

Information in the emissions database or from other source categories does not show that 

control technologies, such as fabric filters or wet scrubbers, achieve reductions in mercury 

emissions from liquid fuel-fired industrial, commercial, and institutional boilers and process 
3-26 

heaters. Therefore, EPA identified no control technology being used in the existing population of 

boilers and process heaters in these subcategories that consistently achieved lower emission rates 

than uncontrolled levels, such that a best-controlled similar source for organic HAP could be 

identified. However, we did find that monitoring CO is a good combustion practice that can 

reduce organic HAP emissions, and has included it in the new source MACT floor as described 

under section III.D of this preamble. We concluded the MACT floor for new sources in this 

subcategory is no emissions reductions for mercury. 

In light of this analysis, the EPA determined that the combination of a fabric filter, a 

packed bed scrubber, and CO monitoring forms the control technology basis for the new source 

MACT floor for boilers and process heaters in this subcategory. 

Small Units—Heat Inputs Less than or Equal to 10 MMBtu/hr. The most effective 

control technologies identified for removing non-mercury metallic HAP used by units in this 

subcategory are fabric filters. Therefore, the EPA considers fabric filters to be the technology 

basis for the new source MACT floor for non-mercury metallic HAP control in this subcategory. 

The most effective control technology identified for units in this subcategory for removing acid 

gases, such as hydrogen chloride, are wet scrubbers. 

Information in the emissions database or from other source categories does not show that 

other control technologies, such as fabric filters or wet scrubbers, achieve reductions in mercury 

emissions from liquid fuel-fired industrial, commercial, and institutional boilers and process 

heaters. Therefore, EPA could not identify a control technology being used in the existing 

population of boilers and process heaters that consistently achieved lower emission rates than 

uncontrolled levels, such that a best-controlled similar source for mercury or organic HAP could 

be identified. We concluded the MACT floor for new sources in this subcategory is no emissions 

reductions for mercury or organic HAP. 

Thus, the EPA determined that the combination of a fabric filter and a wet scrubber forms 

the control technology basis for the new source MACT floor for boilers and process heaters in 

this subcategory. 

The emissions test database did not contain test data for boilers and process heaters less 

than 10 MMBtu/hr heat input. In order to develop emission levels for this subcategory, we 

decided to use information from units in the large liquid subcategory. We considered this to be 

an appropriate methodology because although the units in this subcategory are different enough 

to warrant their own subcategory (i.e., different designs and emissions), emissions of the specific 
3-27 

types of HAP for which limits are being proposed (HCl and metals) are expected to be more 

related to the type of fuel burned and the type of control than to unit design. Consequently, we 

determined that emissions information from units greater than 10 MMBtu/hr heat input could be 

used to establish MACT floor levels for this subcategory because the fuels and controls are 

similar. The MACT floor emission level based on fabric filters is 0.068 lb PM/MMBtu. The 

MACT floor emission level based on wet scrubbers is 0.0009 lb HCl/MMBtu. 

Limited Use Units—Capacity Utilizations Less than or Equal to 10 Percent. The most 

effective control technologies identified for removing non-mercury metallic HAP used by units 

in this subcategory are fabric filters. Therefore, the EPA considers fabric filters to be the 

technology basis for the new source MACT floor for non-mercury metallic HAP control in this 

subcategory. The most effective control technology identified for units in this subcategory for 

removing acid gases, such as hydrogen chloride, are wet scrubbers. 

Information in the emissions database or from other source categories does not show that 

other control technologies, such as fabric filters or wet scrubbers, achieve reductions in mercury 

emissions from liquid fuel-fired industrial, commercial, and institutional boilers and process 

heaters. The EPA identified no control technology being used in the existing population of 

boilers and process heaters that consistently achieved lower emission rates than uncontrolled 

levels, such that a best-controlled similar source for mercury could be identified. We concluded 

the MACT floor for new sources in this subcategory is no emissions reductions for mercury. 

We did find that monitoring CO can reduce organic HAP emissions and is used by at 

least one unit in this subcategory, and have included it in the new source MACT floor as 

described under section III.D of this preamble. Therefore, based on this analysis, the EPA 

determined that the combination of a fabric filter, a wet scrubber, and CO monitoring forms the 

control technology basis for the new source MACT floor for boilers and process heaters in this 

subcategory. 

The emissions test database did not contain test data for limited use liquid-fired boilers 

and process heaters. In order to develop emission levels for this subcategory, we decided to use 

information from units in the large liquid subcategory. Consequently, we determined that 

emissions information from units greater than 10 MMBtu/hr heat input could be used to establish 

MACT floor levels for this subcategory because the fuels and controls are similar. The MACT 

floor emission level based on fabric filters is 0.068 lb PM/MMBtu. The MACT floor emission 

level based on wet scrubbers is 0.0009 lb HCl/MMBtu. We are requesting comment on using 
3-28 

emission data from another subcategory to develop emission levels for this subcategory. We are 

also requesting any available emissions information for this subcategory. 

Gaseous Fuel Subcategories. No existing units were using control technologies that 

achieve consistently lower emission rates than uncontrolled sources for any of the pollutant 

groups of interest, except organic HAP. At least one unit in the population database in the large 

and limited use gaseous fuel subcategories is required to monitor CO. Therefore, the MACT 

floor for gaseous fuel-fired units includes a CO monitoring requirement and emission limit, as 

described in section III.D of this preamble, but it does not include any emission limits for PM, 

metallic HAP, mercury, or inorganic HAP based on the utilization of add-on control technology. 

How EPA Considered Beyond the Floor Options for New Units. The MACT floor level 

of control for new units is based on the emission control that is achieved in practice by the best 

controlled similar source within each of the subcategories. No technologies were identified that 

would achieve non-mercury metals reduction greater than the new source floors (i.e., fabric 

filters) for the liquid and solid subcategories or CO monitoring for the solid, liquid, and gaseous 

subcategories. For inorganic HAP control, we determined that packed bed scrubbers achieve 

higher emissions reductions than MACT floors consisting of a wet scrubber. Packed bed 

scrubbers are the technology basis of the MACT floor for the large unit subcategory, but wet 

scrubbers were the technology basis of the floors for the small unit and limited unit 

subcategories. Therefore, we examined the cost and emission reductions of applying a packed 

bed scrubber as a beyond the floor option for new solid and liquid units within the small and 

limited use subcategories. We determined that costs were excessive for the limited emission 

reduction that would be achieved. Non-air quality health, environmental impacts, and energy 

effects were not significant factors, because there would be little difference in the non-air quality 

health and environmental impacts between packed bed scrubbers and wet scrubbers. Therefore, 

the EPA did not select this beyond-the-floor option, and the proposed new source MACT level of 

control for PM, metallic HAP, and inorganic HAP (HCl) is the same as the MACT floor level of 

control for all of the subcategories. 

In reviewing potential regulatory options beyond the new source MACT floor level of 

control, the EPA identified one existing solid fuel-fired industrial boiler that was using carbon 

injection technology for mercury control. However, emission data obtained from this unit 

indicated that it was not achieving mercury emission reductions from the uncontrolled levels. 

Moreover, we do not have information to otherwise show that carbon injection is effective for 

reducing mercury emissions from industrial, commercial, and institutional boilers and process 

heaters. Information in the emissions database or from other source categories does not show that 
3-29 

other control technologies, such as fabric filters or wet scrubbers, achieve reductions in mercury 

emissions from liquid fuel-fired industrial, commercial, and institutional boilers and process 

heaters. Therefore, carbon injection, for solid fuel units, and other control techniques, for liquid 

fuel units, were not evaluated as regulatory options. 

For the solid fuel and liquid fuel subcategories, fuel switching to natural gas is a potential 

regulatory option beyond the new source floor level of control that would reduce mercury and 

metallic HAP emissions. However, based on current trends within the industry, the EPA projects 

that the majority of new boilers and process heaters will be built to fire natural gas as opposed to 

solid and liquid fuels such that the overall emissions reductions associated with this option would 

be minimal. Furthermore, organic HAP may be increased by fuel switching. Limited emissions 

reductions in combination with the high cost of fuel switching and considerations about the 

availability and technical feasibility of fuel switching makes this an unreasonable regulatory 

option that was not considered further. Non-air quality health, environmental impacts, and 

energy effects were not significant factors. No beyond-the-floor options for gas-fired boilers 

were identified. 

Based on the analysis discussed above, the EPA decided to not go beyond the MACT 

floor level of control for new sources for MACT in the rule. 

3.1.4 Considerations of Possible Risk-Based Alternatives to Reduce Impacts to Sources 

The Agency has made every effort in developing this rule to minimize the cost to the 

regulated community and allow maximum flexibility in compliance options consistent with our 

statutory obligations. However, we recognize that the rule may still require some facilities to take 

costly steps to further control emissions even though their emissions may not result in exposures 

which could pose an excess individual lifetime cancer risk greater than one in one million or 

which exceed thresholds determined to provide an ample margin of safety for protecting public 

health and the environment from the effects of hazardous air pollutants. We therefore solicited 

comment on whether there are further ways to structure the rule to focus on the facilities which 

pose significant risks and avoid the imposition of high costs on facilities that pose little risk to 

public health and the environment. 

Representatives of the plywood and composite wood products industry provided EPA 

with descriptions of three mechanisms that they believed could be used to implement more costeffective reductions in risk. The docket for today’s rule contains “white papers” prepared by 

industry that outline their proposed approaches (see docket number A-98-44, Item # II-D-525). 

These approaches could be effective in focusing regulatory controls on facilities that pose 
3-30 

significant risks and avoiding the imposition of high costs on facilities that pose little risk to 

public health or the environment, and we sought public comment on the utility of each of these 

approaches with respect to this rule. 

One of the approaches, an applicability cutoff for threshold pollutants, would be 

implemented under the authority of CAA section 112(d)(4); the second approach, 

subcategorization and delisting, would be implemented under the authority of CAA sections 

112(c)(1) and 112(c)(9); and, the third approach, would involve the use of a concentration-based 

applicability threshold. We sought comments on whether these approaches are legally justified 

and asked for information that could be used to support such approaches. 

The approach the Agency has chosen to include in the final rule is the first approach—an 

applicability cutoff for threshold pollutants. The threshold pollutants for which an applicability 

cutoff is applied are hydrochloric acid (HCl) and a series of eight metals known as the total 

selected metals (TSM). 

3.1.4.1 Applicability Cutoffs for Threshold Pollutants Under Section 112(d)(4) of the CAA 

This approach is an “applicability cutoff” for threshold pollutants that is based on EPA’s 

authority under CAA section 112(d)(4). A “threshold pollutant” is one for which there is a 

concentration or dose below which adverse effects are not expected to occur over a lifetime of 

exposure. For such pollutants, section 112(d)(4) allows EPA to consider the threshold level, with 

an ample margin of safety, when establishing emissions standards. Specifically, section 

112(d)(4) allows EPA to establish emission standards that are not based upon the maximum 

achievable control technology (MACT) specified under section 112(d)(2) for pollutants for 

which a health threshold has been established. Such standards may be less stringent than MACT. 

Historically, EPA has interpreted 112(d)(4) to allow us to avoid further regulation of categories 

of sources that emit only threshold pollutants, if those emissions result in ambient levels that do 

not exceed the threshold, with an ample margin of safety.4

In the past, EPA routinely treated carcinogens as non-threshold pollutants. The EPA 

recognizes that advances in risk assessment science and policy may affect the way EPA 

differentiates between threshold and non-threshold HAP. The EPA’s draft Guidelines for 

Carcinogen Risk Assessment (EPA, 1999) suggest that carcinogens be assigned non-linear doseresponse relationships where data warrant. Moreover, it is possible that dose-response curves for 

some pollutants may reach zero risk at a dose greater than zero, creating a threshold for 

 

4

 See 63 FR 18754, 18765-66 (April 15, 1998) (Pulp and Paper Combustion Sources Proposed NESHAP). 
3-31 

carcinogenic effects. It is possible that future evaluations of the carcinogens emitted by this 

source category would determine that one or more of the carcinogens in the category is a 

threshold carcinogen or is a carcinogen that exhibits a non-linear dose-response relationship but 

does not have a threshold. 

The dose-response assessments for formaldehyde and acetaldehyde are currently 

undergoing revision by the EPA. As part of this revision effort, EPA is evaluating formaldehyde 

and acetaldehyde as potential non-linear carcinogens. The revised dose-response assessments 

will be subject to review by the EPA Science Advisory Board, followed by full consensus 

review, before adoption into the EPA Integrated Risk Information System (IRIS). At this time, 

EPA estimates that the consensus review will be completed sometime in 2004. The revision of 

the dose-response assessments could affect the potency factors of these HAP, as well as their 

status as threshold or non-threshold pollutants. At this time, the outcome is not known. In 

addition to the current reassessment by EPA, there have been several reassessments of the 

toxicity of and carcinogenicity of formaldehyde in recent years, including work by the World 

Health Organization and the Canadian Ministry of Health. 

3.1.4.2 Applicability Cutoffs for Hydrogen Chloride Controls Under Section 112(d)(4) of the 

CAA 

HCl Compliance Alternative. As an alternative to the requirement for each large solid 

fuel-fired boiler to demonstrate compliance with the HCl emission limit in the final rule, you 

may demonstrate compliance with a health-based facility-wide HCl equivalent allowable 

emission limit. 

The procedures for demonstrating eligibility for the HCl compliance alternative (as 

outlined in appendix A of the final rule) are: 

(1) You must include in your demonstration every emission point within the facility that 

emits a respiratory toxicant included on EPA’s list of hazardous air pollutants. 

(2) You must conduct HCl and chlorine emissions tests for every emission point covered 

under subpart DDDDD. 

(3) You must obtain either through emission testing or through the development and 

documentation of best engineering estimates of maximum emissions of respiratory 

toxicants from all emission points at the facility not covered under subpart DDDDD 

of part 63 from which a respiratory toxicant might reasonably be emitted. 

(4) You must determine the total maximum hourly mass HCl-equivalent emission rate for 

your facility by summing the maximum hourly toxicity-weighted emission rates of all 

appropriate respiratory toxicants (calculated using the maximum rated capacities of 

the units) for each of the units at your facility. 
3-32 

(5) Use the look-up table in the appendix A of subpart DDDDD to determine if your 

facility is in compliance with health-based HCl-equivalent emission limit. 

(6) Select the maximum allowable HCl-equivalent emission rate from the look-up table 

in appendix A of subpart DDDDD of part 63 for your facility using the average stack 

height of your subpart DDDDD emission units as your stack height and the minimum 

distance between any respiratory toxicant emission point at the facility and the closest 

boundary of the nearest residential (or residentially zoned) area as your fenceline 

distance. 

(7) Your facility is in compliance if your maximum HCl-equivalent emission rate does 

not exceed the value specified in the look-up table in appendix A of subpart DDDDD. 

(8) As an alternative to using the look-up table, you may conduct a site-specific 

compliance demonstration (as outlined in appendix A of subpart DDDDD of part 63) 

which demonstrate that your facility cannot cause an individual chronic inhalation 

exposure from respiratory toxicants which can exceed a Hazard Index (HI) value of 

1.0. 

3.1.4.3 Applicability Cutoffs for Total Selected Metals Controls Under Section 112(d)(4) of the 

CAA 

In lieu of complying with the emission standard for TSM in subpart DDDDD of part 63 

based on the sum of emissions for the selected metals (arsenic, cadmium, chromium, mercury, 

manganese, nickel, and lead) you may demonstrate eligibility for complying with the TSM 

standard based on excluding manganese emissions from the summation of TSM emissions for 

the affected source unit. 

The procedures for demonstrating eligibility for the TSM compliance alternative (as 

outlined in appendix A of the subpart DDDDD) are: 

(1) You must include in your demonstration every emission point within the facility that 

emits a CNS toxicant included on EPA’s list of hazardous air pollutants. 

(2) You must conduct manganese emissions tests for every emission point covered under 

subpart DDDDD that emits manganese. 

(3) You must obtain either through emission testing or through the development and 

documentation of best engineering estimates of maximum emissions of CNS 

toxicants from all emission points at the facility not covered under subpart DDDDD 

from which a CNS toxicant might reasonably be emitted. 

(4) You must determine the total maximum hourly manganese equivalent emission rate 

from your facility by summing the maximum hourly toxicity-weighted emission rates 

of all appropriate CNS toxicants (calculated using the maximum rated heat input 

capacities) for each of the units at your facility. 
3-33 

(5) Use the look-up table in appendix A of subpart DDDDD to determine if your facility 

is eligible for complying with the TSM limit based on the sum of emissions for seven 

metals (excluding manganese) for the affected source units. 

(6) Select the maximum allowable manganese-equivalent emission rate from the look-up 

table in appendix A of subpart DDDDD for your facility using the average stack 

height of your subpart DDDDD emission units as your stack height and the minimum 

distance between any CNS toxicant emission point at the facility and the closest 

boundary of the nearest residential (or residentially zoned) area as your fenceline 

distance. 

(7) Your facility is eligible if your maximum manganese-equivalent emission rate does 

not exceed the value specified in the look-up table in appendix A of subpart DDDDD. 

(8) As an alternative to using look-up table to determine if your facility is eligible for the 

TSM compliance alternative, you may conduct a site-specific compliance 

demonstration (as outlined in appendix A of subpart DDDDD) which demonstrates 

that your facility cannot cause an individual chronic inhalation exposure from CNS 

toxicants which can exceed a HI value of 1.0. 

If you elect to demonstrate eligibility for either of the health-based compliance 

alternatives, you must submit certified documentation supporting compliance with the 

procedures at least 1 year before the compliance date. 

You must submit supporting documentation including documentation of all maximum 

capacities, existing control devices used to reduce emissions, stack parameters, and property 

boundary distances to each on-site source of HCl-equivalent and/or manganese-equivalent 

emissions. 

You must keep records of the information used in developing the eligibility 

demonstration for your affected source. 

To be eligible for either health-based compliance alternative, the parameters that defined 

your affected source as eligible for the health-based compliance alternatives (including, but not 

limited to, fuel type, type of control devices, process parameters documented as worst-case 

conditions during the emissions testing used for your eligibility demonstration) must be 

incorporated as Federally enforceable limits into your title V permit. If you do not meet these 

criteria, then your affected source is subject to the applicable emission limits, operating limits, 

and work practice standards in Subpart DDDDD. 

If you intend to change key parameters (including distance of stack to the property 

boundary) that may result in lower allowable health-based emission limits, you must recalculate 
3-34 

the limits under the provisions of this section, and submit documentation supporting the revised 

limits prior to initiating the change to the key parameter. 

If you intend to install a new solid fuel-fired boiler or process heater or change any 

existing emissions controls that may result in increasing HCl-equivalent and/or manganeseequivalent emissions, you must recalculate the total maximum hourly HCl-equivalent and/or 

manganese-equivalent emission rate from your affected source, and submit certified 

documentation supporting continued eligibility under the revised information prior to initiating 

the new installation or change to the emissions controls. 

Facilities that could not demonstrate that they are eligible to be included in the low-risk 

subcategory would be subject to MACT and possible future residual risk standards. 

3.2 Profile of Existing Boiler and Process Heaters Units 

This section profiles existing boilers and process heaters, collectively referred to as 

“units,” with respect to business applications, industry of parent company, and fuel use. The unit 

population database in combination with the model units that helped in preparing that database 

were used to determine which types of boilers, fuel, and control devices were in the existing unit 

population so that corresponding emission factors could be developed for all combinations. 

3.2.1 Development of the Unit Inventory Database 

The development of the population database and the model units are discussed in the 

memoranda, “Development of the Population Database for the Industrial, Commercial, and 

Institutional Boiler and Process Heater National Emission Standard for Hazardous Air Pollutants 

(NESHAP)” and “Development of the Model Units for the Industrial, Commercial, and 

Institutional Boiler and Process Heater National Emission Standard for Hazardous Air Pollutants 

(NESHAP).” The units contained in the Inventory Database are based on information from the 

Aerometric Information Retrieval System (AIRS) and Ozone Transport Assessment Group 

(OTAG) databases, state and local permit records, and the combustion source Information 

Collection Request (ICR) conducted by the Agency in 1997. The list of units contained in the 

Inventory Database was reviewed and updated by industry and environmental stakeholders as 

part of the Industrial Combustion Coordinated Rulemaking (ICCR), chartered under the Federal 

Advisory Committee Act (FACA). 

The entire Inventory Database contains more than 58,000 ICI boilers and process heaters; 

however only 3,730 units in the database are estimated to be affected by the final rule. Of these 

existing units, a little over half had sufficient information on operating parameters to be included 
3-35 

in the floor-level EIA. The number of potentially affected units included in the profile for the 

final rule was 2,186. 

3.2.2 Distribution of Existing Boilers and Facilities by Industry 

Table 3-2 presents the number of existing boilers and process heaters and the number of 

facilities owning units by two-digit SIC code and three-digit NAICS code that may be affected 

by the final rule. For the final rule, the industries with the largest number of potentially affected 

units are the furniture, paper, lumber, and electrical services industries. These four industries 

alone account for nearly 60 percent of affected units. Almost all the process heaters are in the 

lumber industry. (Section 4 presents industry profiles for the lumber and wood products, 

electrical services, and paper industries, among others.) The remaining units are primarily 

distributed across the manufacturing sector and service industries. 

3.2.3 Technical Characteristics of Existing Boilers 

Figure 3-1 characterizes the population of 2,186 units identified in the Inventory 

Database by capacity range, fuel type, and level of preexisting control. 

3.2.3.1 Final Rule 

 Capacity Range: Unit input capacities in the population are expressed in four ranges: 

0–10, 10–100, 100–250, and >250 MMBtu/hr. About 52 percent of the units affected 

for this alternative have capacities between 10 and 100 MMBtu/hr. The two largest 

capacity ranges each contain approximately one quarter of the population. Only 1 

percent of units have input capacities less than 10 MMBtu/hr. 

 Fuel Type: About half of these units consume coal as their primary fuel (1,074 units). 

After coal, the next most common fuel type is wood (479 units). 

 Control Level: About 83 percent of units have some type of control device already 

installed. Only 289 units do not. Typical control devices include fabric filters, wet 

scrubbers, and electrostatic precipitators. 
3-36 

Table 3-2. Units and Facilities Affected by the Final Rule by Industrya

SIC 

Code

NAICS 

Code Description Boilers Heaters

Total 

Units Facilities

01 111 Agriculture—Crops 3 0 3 3 

02 112 Agriculture—Livestock 0 0 0 0 

07 115 Agricultural Services 0 0 0 0 

10 212 Metal Mining 9 0 9 4 

12 212 Coal Mining 2 0 2 1 

13 211 Oil and Gas Extraction 0 0 0 0 

14 212 Mining/Quarrying—Nonmetallic Minerals 8 0 8 4 

17 235 Construction—Special Trade Contractors 0 0 0 0 

20 311 Food and Kindred Products 138 0 138 60 

21 312 Tobacco Products 11 0 11 7 

22 313 Textile Mill Products 135 0 135 71 

23 315 Apparel and Other Products from Fabrics 2 0 2 2 

24 321 Lumber and Wood Products 335 25 360 262 

25 337 Furniture and Fixtures 234 0 234 154 

26 322 Paper and Allied Products 321 0 321 194 

27 511 Printing, Publishing, and Related Industries 0 0 0 0 

28 325 Chemicals and Allied Products 171 3 174 70 

29 324 Petroleum Refining and Related Industries 11 0 11 8 

30 326 Rubber and Miscellaneous Plastics Products 17 0 17 13 

31 316 Leather and Leather Products 1 0 1 1 

32 327 Stone, Clay, Glass, and Concrete Products 9 0 9 7 

33 331 Primary Metal Industries 41 0 41 16 

34 332 Fabricated Metal Products 16 0 16 10 

35 333 Industrial Machinery and Computer Equipment 23 0 23 12 

36 335 Electronic and Electrical Equipment 5 0 5 5 

37 336 Transportation Equipment 102 0 102 41 

38 334 Scientific, Optical, and Photographic Equip. 8 0 8 4 

39 339 Miscellaneous Manufacturing Industries 2 0 2 2 

40 482 Railroad Transportation 4 0 4 1 

(continued) 
3-37 

Table 3-2. Units and Facilities Affected by the Final Rule by Industrya

 (continued) 

SIC 

Code

NAICS 

Code Description Boilers Heaters

Total 

Units Facilities

42 484 Motor Freight and Warehousing 5 0 5 1 

46 486 Pipelines, Except Natural Gas 0 0 0 0 

49 221 Electric, Gas, and Sanitary Services 318 0 318 160 

50 421 Wholesale Trade—Durable Goods 3 0 3 2 

51 422 Wholesale Trade—Nondurable Goods 2 0 2 1 

55 441 Automotive Dealers and Gasoline Service Stations 0 0 0 0 

58 722 Eating and Drinking Places 0 0 0 0 

60 522 Depository Institutions 0 0 0 0 

59 445–454 Miscellaneous Retail 0 0 0 0 

70 721 Hotels and Other Lodging Places 1 0 1 1 

72 812 Personal Services 0 0 0 0 

76 811 Miscellaneous Repair Services 2 0 2 1 

80 621 Health Services 37 0 37 18 

81 541 Legal Services 0 0 0 0 

82 611 Educational Services 105 0 105 45 

83 624 Social Services 2 0 2 1 

86 813 Membership Organizations 0 0 0 0 

87 541 Engineering, Accounting, Research, Management 

and Related Services 

2 0 2 2 

89 711/514 Services, N.E.C. 2 0 2 1 

91 921 Executive, Legislative, and General Administration 1 0 1 1 

92 922 Justice, Public Order, and Safety 29 0 29 9 

94 923 Administration of Human Resources 1 0 1 1 

96 926 Administration of Economic Programs 4 0 4 3 

97 928 National Security and International Affairs 29 0 29 11 

NA SIC Information Not Available 7 0 7 4 

 2,158 28 2,186 1,214 

a

 Based on the Inventory Database. 
3-38 

>250

23% 10 to 100

52%

100 to 250

25%

Input Capacity

(million Btu)

Preexisting Control

Technology

Fuel Type

Cyclone

36%

No Control

13%

Wet

Scrubber

12%

Fabric Filter

16% ESP

23%

Coal

49%

Coal and

Wood

7%

Wood

22%

Other

4%

Other

Biomass

14%

Bagasse

4%

0 to 10

1%

Floor Alternative (n=2,186)

Figure 3-1. Characteristics of Units Affected 

3.3 Methodology for Estimating Cost Impacts 

The predominant type of control measure that is considered in the analysis of emission 

reductions needed for sources to achieve the MACT floor is add-on control technologies. Add-on 

control techniques are those technologies that are applied to the vent gas stream of the boiler or 

process heater to reduce emissions. The boiler and process heaters population database includes 

information on all control techniques that are applied to industrial, commercial, institutional 

boilers and process heaters. Generally, they can be grouped into PM control or acid gas control. 

The most common technologies, and the ones analyzed for the impacts analysis, include fabric 

filters, ESP’s, packed scrubbers, venturi scrubbers, and spray dryers. In addition, when add-on 

technologies are used, the cost of ductwork and associated equipment also needed to be 

considered. 

Components of capital cost include 

 purchased equipment cost of the primary device and auxiliary equipment, 

 instrumentation, 

 sales tax and freight, and 

 installation costs. Installation costs include foundations and support, handling and 

erection, electrical, piping, insulation, and painting, engineering, construction and 

field expenses, contractor fees, start-up, performance tests, and contingencies. 
3-39 

Components of annual cost include 

 raw materials, 

 utilities (electricity, fuel, steam, air, water), 

 waste treatment and disposal, 

 labor (operating, supervisory, maintenance), 

 maintenance materials, 

 replacement parts, 

 overhead, 

 property taxes, 

 insurance, 

 administration charges, and 

 capital recovery costs. 

For this analysis, costs were estimated in 1999 dollars. Capital recovery was calculated assuming 

7 percent interest rate over the life of the equipment. The use of this interest rate is based on 

Office of Management and Budget (OMB) guidance (Circular A-94, October 29, 1992). 

The algorithms used to estimate these costs were obtained from previous EPA studies. 

These cost algorithms are included as appendices to the cost methodology memorandum in the 

public docket. Inputs for the algorithms used in the impacts analysis are also presented in this 

memorandum. 

Fabric Filter 

The algorithms used to estimate capital and annual costs of fabric filters were obtained 

from EPA’s EPA Air Pollution Control Cost Manual. Algorithms were provided for 4 types of 

fabric filters: shaker, reversed air, pulse-jet modular, and pulse-jet common. The cost algorithms 

for estimating capital costs reduced to basic equations for each are provided in Appendix A-1 of 

the cost methodology memorandum (henceforth called the “cost memo”). Capital costs are based 

on the gross cloth area of the fabric filter, which is a function of the gas inlet flow rate. 

Algorithms for calculating annual costs are provided in Appendix A-2 of the cost memo. Annual 

costs include dust disposal, electricity, maintenance, labor, bag replacement, maintenance labor, 

compressed air, overhead, administrative, property taxes, and insurance. Capital recovery is 

annualized over 20 years at 7 percent interest. Appendix A-3 of the cost memo presents the 

values for the inputs used in this analysis and the reasons for their use. 
3-40 

Electrostatic Precipitator 

The algorithms used to estimate capital and annual costs of ESPs were obtained from 

EPA’s Air Pollution Control Cost Manual. Capital costs are based on the total collection plate 

area, which is calculated from the gas inlet flow rate and the required removal efficiency. The 

cost algorithms for estimating capital costs of ESPs reduced to basic equations are provided in 

Appendix B-1 of the cost memo. Algorithms for calculating annual costs are provided in 

Appendix B-2 of the cost memo. Annual costs include dust disposal, electricity, maintenance, 

labor, maintenance labor, overhead, administrative, property taxes, and insurance. Capital 

recovery is annualized at 7 percent interest. Appendix B-3 of the cost memo presents the values 

for the inputs used in this analysis and the reasons for their use. 

Venturi Scrubber 

The algorithms used to estimate capital and annual costs of venturi scrubbers were 

obtained from EPA cost algorithms on EPA’s Web site (http://www.epa.gov/ttn/catc/ 

products.html#cccinfo.) Capital costs include not only the cost of the venturi scrubber but also a 

pump to provide motive force for the solvent. Capital costs are based on the gas flow rate and 

saturation temperature of the gas-solvent. The cost algorithms for estimating capital costs of each 

piece of equipment were reduced to basic equations in Appendix C-1 of the cost memo. The cost 

algorithms for estimating annual costs were reduced to basic equations in Appendix C-2 of the 

same memorandum. Annual costs include wastewater disposal, solvent, electricity, maintenance, 

labor, maintenance labor overhead, administrative, property taxes, and insurance. Capital 

recovery is an annualized cost estimated using a 7 percent interest rate. Appendix C-3 of the cost 

memo presents the values for the inputs used in this analysis and the reasons for their use. 

Packed Bed Scrubber 

The algorithms used to estimate capital and annual costs of packed bed scrubbers were 

obtained from EPA’s Air Pollution Control Cost Manual. The capital costs are comprised of the 

scrubber tower, packing, pumps, and fans. Capital costs are based primarily on gas flow rate and 

removal efficiency. The cost algorithms for estimating capital costs of packed scrubber 

equipment reduced to their basic equations for each are provided in Appendix D-1 of the cost 

memo. The cost algorithms for estimating annual costs of packed scrubbers are provided in 

Appendix D-2 of the cost memo. Annual costs include caustic, wastewater disposal, water, 

electricity, maintenance, labor, overhead, administrative, property taxes, and insurance. Capital 

recovery is an annualized cost estimated using a 7 percent interest rate. Appendix D-3 of the cost 

memo presents the values for the inputs used in this analysis and the reasons for their use. 
3-41 

Spray Dryer 

The algorithms used to estimate capital and annual costs of spray dryers were obtained 

from previous EPA studies. Capital costs include the cost of the spray dryer and pumps. Capital 

costs are based on the gas flow rate. The cost algorithms for estimating capital costs of spray 

dryer equipment reduced to basic equations are provided in Appendix E-1 of the cost memo. The 

cost algorithms for estimating annual costs for spray dryers are provided in Appendix E-2 of the 

cost memo. Annual costs include lime, water, electricity, maintenance, labor, maintenance labor, 

overhead, administrative, property taxes, and insurance. Capital recovery is an annualized cost 

estimated using a 7 percent interest rate. Appendix E-3 of the cost memo presents the values for 

the inputs used in this analysis and the reasons for their use. 

Ductwork 

The algorithms used to estimate capital and annual costs of ductwork were obtained from 

EPA’s Air Pollution Control Cost Manual. Capital costs include 500 feet of ductwork, elbows, 

and fans. The 500 feet of ductwork was based on engineering judgment and previous experience 

on the distance between emission points and control devices in chemical facilities and the 

availability of space for retrofitting controls. Costs are based on ductwork diameter, which is 

calculated from the gas flow rate. The cost algorithms for estimating capital costs and annual 

costs reduced to basic equations are provided in Appendix F-1 of the cost memo. Annual costs 

include electricity, maintenance, maintenance labor, overhead, administrative, property taxes, 

and insurance. Capital recovery is an annualized cost estimated using a 7 percent interest rate. 

Required inputs to the ductwork algorithms are provided in the input tables provided in 

Appendices A-3, B-3, C-3, D-3, and E-3 of the cost memo. 

Good Combustion Practices 

Few sources in the population database specifically reported using good combustion 

practices. Boilers and process heaters within each subcategory might use any of a wide variety of 

different work practices, depending on the characteristics of the individual unit. 

Consequently, any uniform requirements or set of work practices that would 

meaningfully reflect the use of good combustion practices, or that could be meaningfully 

implemented across any subcategory of boilers and process heaters could not be identified. 

Additionally, few of the GCP’s have been documented to reduce organic HAP emissions, 

and they could not be considered in the MACT analysis. One GCP that may effect organic HAP 

emissions is maintaining CO emission levels. CO is generally an indicator of incomplete 

combustion because CO will burn to carbon dioxide if adequate oxygen is available. Controlling 
3-42 

CO emissions is a mechanism for ensuring combustion efficiency, and therefore may be viewed 

as a kind of GCP. 

Capital and annual costs for CO monitoring is presented in Appendix G of the cost 

memo. The costing information was obtained from a previous EPA study. Capital costs are 

comprised of the initial cost of the equipment. Annual costs include operating and maintenance 

costs, annual and quarterly checks, recordkeeping and reporting, taxes, insurance, and 

administrative costs. Annualized costs such as capital recovery costs are calculated assuming an 

equipment life of 20 years and an interest rate of 7 percent. 

Testing and Monitoring Costs 

The final rule includes emission limits for HCl, PM, metallic HAP, and mercury. 

Additionally, as mentioned in Section 1 of this EIA and the preamble, the rule allows sources to 

meet requirements by monitoring fuel content instead of emissions. Consequently, testing and 

monitoring costs of meeting the standards were incorporated into the cost estimates. Capital costs 

for testing include initial stack tests for PM, HCl, and metals for fossil fuels, and materials and 

fuel analysis for biomass. Capital cost components include operation and maintenance costs and 

capital recovery assuming the initial capital investment is annualized over a 5 year period at 7 

percent interest. Monitoring costs are included for opacity monitoring, HCl monitoring, and 

scrubber parametric monitoring.5

 Monitoring costs include the capital cost of monitoring 

equipment, and the annual costs of capital recovery assuming the initial capital investment is 

annualized over a 20 year period at 7 percent interest. Annual monitoring costs also include 

operation and maintenance as well as other additional costs. The testing and monitoring costs are 

shown in Table 3-3. Appendix G of the cost memo includes further details on these costs. 

Information used to estimate testing and monitoring costs were obtained from previous EPA 

studies. 

 

5

 The monitoring costs reported for existing units are not the cost of continuous emission monitors (CEM), but the 

costs associated with monitoring the process parameters of the control device. Installation of these process 

monitors are integral to the control device and would be installed with or without the monitoring requirements of 

the MACT. Therefore, even though we present these monitoring costs separately, they are included in the overall 

reported control costs and should not be considered as an additional cost for emission monitoring. 
3-43 

Table 3-3. Testing and Monitoring Costs for Units Covered 

Material or Fuel

No. of 

Industrial 

Boilers

No. of 

Process 

Heaters

Total Capital 

Investment of 

Testing and 

Monitoring ($)

Total Annual 

Costs of 

Testing ($)

Total Annual 

Costs of 

Monitoring ($)

Annual Capita

Recovery—Test

and Monitorin

(1999$)

Regular Use Units 

Coal 2,328 0 123,759,254 63,608,655 59,828,340 8,265,169 

Coal/Wood/NFFa

Liquid/NFF Solid 

169 0 8,847,579 2,444,456 1,302,784 280,698 

Gas 30,473 13,481 0 0 0 0 Gas/Wood/Other Biomass/Liquid FF 

201 0 9,831,749 2,909,994 2,327,840 447,120 

Distillate Liquid FF 2,921 353 0 0 0 0 NFF Liquid/NFF Solid/Gas 115 11 7,452,131 3,074,918 2,930,348 404,077 Wood 663 42 5,545,669 5,268,614 6,392,240 1,411,706 Wood/Other Biomass/NFF Liquid/NFF Solid 

147 0 8,180,852 3,003,146 2,001,492 299,112 

Residual Liquid FF 2,036 674 0 0 0 0 Bagasse/Other 132 0 5,821,106 490,000 2,891,728 412,546 Total for Regular Use Units 39,185 14,561 169,438,340 80,799,783 77,674,772 11,520,428 
3-44 

Table 3-3. Testing and Monitoring Costs for Units Covered (continued) 

Material or Fuel

No. of 

Industrial 

Boilers

No. of 

Process 

Heaters

Total Capital 

Investment of 

Testing and 

Monitoring ($)

Total Annual 

Costs of 

Testing ($)

Total Annual 

Costs of 

Monitoring ($)

Annual Capita

Recovery—Test

and Monitorin

(1999$)

Limited Use Units 

Coal 198 0 6,427,715 1,584,000 1,716,416 457,169 

Coal/Wood/NFF Liquid/NFF Solid 

4 0 119,600 32,000 29,772 8,268 

Gas 2,314 624 0 0 0 0 Gas/Wood/Other Biomass/Liquid FF 

8 0 290,366 64,000 105,020 21,366 

Distillate Liquid FF 672 31 0 0 0 0 NFF Liquid/NFF Solid/Gas 4 1 156,800 40,000 39,696 11,024 Wood 28 0 1,074,549 224,000 331,200 80,279 Wood/Other Biomass/NFF Liquid/NFF Solid 

6 0 194,000 48,000 49,620 13,780 

Residual Liquid FF 533 31 0 0 0 0 Total for Limited Use Units 3,767 687 8,263,030 1,992,000 2,271,724 591,886 

Grand Total 42,952 15,248 177,701,370 82,791,783 79,946,496 12,112,314 

a NFF = costs for units that are not fossil fueled; FF = units that are fossil fueled. 
3-45 

Costs to Control Non-Air Effects Related to Rule Implementation 

The Agency estimated the additional water usage that would result from the MACT floor 

level of control to be 110 million gallons per year for existing sources and 0.6 million gallons per 

year for new sources. In addition to the increased water usage, an additional 3.7 million gallons 

per year of wastewater would be produced for existing sources and 0.6 million gallons per year 

for new sources. The Agency estimated the additional solid waste that would result from the 

MACT floor level of control to be 102,000 tons per year for existing sources and 1 ton per year 

for new sources. The costs ($900,000) of handling the additional solid waste generated from 

applying MACT floor technology are accounted for in the control cost estimates for ESP and 

fabric filter applications. The costs ($20,000) of treating wastewater from venturi and packed bed 

scrubber are also accounted for in the control cost estimates. 

Cost Effectiveness 

To provide additional information on the magnitude of the cost estimates, Table 3-4 

shows the cost-effectiveness (cost/ton reduced estimates) for the HAP and non-HAP pollutants 

whose emissions are reduced by this rule. 

Cost Uncertainties 

The primary limitation to the cost estimates developed for the rule is that costs were 

calculated for model units rather than each individual boiler or process heater. Consequently, the 

costs do not characterize any “real” unit. This was done for practical reasons. Because there are 

over 60,000 units in the U.S., it would not be possible to gather unit-specific information for 

each unit necessary for estimating costs, such as flue gas temperatures and flow rates. 

Additionally, emission information was only available for less than 1 percent of the units. In 

order to estimate costs and emission reductions of the rule, model units were developed to 

represent the population of boilers and process heaters in the U.S. While sufficient information 

was not available for characterizing each unit, sufficient emissions and process information were 

available to develop model units. Each unit in the U.S. was then assigned to a model based on 

their size and fuel burned. It also should be noted that the costing methodology is the cost 

algorithms for the control devices provide a cost range of +/- 30 percent. This aspect of the 

costing methodology reflects the degree of variability typically found in study-level cost 

estimates. This is also the degree of variability found in the cost methodology employed in the 

EPA Air Pollution Control Cost Manual, which is an important reference for the cost estimates 

supplied in the RIA. Cost information available to owners and operators of boilers and process 

heaters will be more specific and accurate. Consequently, the cost estimates may overestimate or 

underestimate costs. 
3-46 

Table 3-4. Cost Effectiveness (C/E) of Industrial Boiler and Process Heater MACT on 

Existing Units and Subcategories 

Total 

Annualized 

Costs

Large Solid 

Fuel 

Subcategory

Large Solid Fuel 

Subcategory—

Coal Only

Large Solid Fuel 

Subcategory—

Wood Only

Limited Use 

Solid Fuel 

Subcategory

Control Costs ($) 720,577,200b 697,619,328 585,932,309 111,687,020 22,957,871 

PM Emissions 

Reduction 

(Tons/Year) 

565,900 563,060 359,920 203,140 2,840 

C/E ($/ton PM) 1,273a

 1,239 1,628 550 8,084 

Metals Emissions 

Reduction 

(Tons/Year) 

1,093 1,087 591 496 6 

C/E ($/ton metals) 659,266a

 641,784a 991,425a 225,175a 3,826,312a

HCl Emissions 

Reduction 

(Tons/Year) 

46,515 46,515 45,136 1,379 — 

C/E ($/ton HCl) 15,491a

 14,998a 12,981a 80,991a — 

HAP Emissions 

Reduction 

(Tons/Year) 

47,608 47,602 45,727 1,875 6 

C/E ($/ton HAP) 15,136 14,655 12,814 59,566 3,826,312 

a

 The cost-effectiveness value is based on the total annualized cost of the rule and not on the cost for controlling the 

specific pollutant, and, thus, overstates the cost/ton for the specific HAP or other pollutant. 

b

 Costs are in 1999 dollars. Emission reductions are calculated for 2005. 

3.4 Projection of New Boilers and Process Heaters 

Energy Information Administration fuel consumption forecasts were used in conjunction 

with existing model boiler population data to project the number and type of new boilers to be 

installed by 2005. EPA used the following steps to calculate new boiler population estimates: 

1. Calculate the percentage change in industrial fuel consumption. Energy Information 

Administration data were used to obtain industrial and commercial fuel use 

projections. The percentage change in consumption (1998 to 2005) in the industrial 

and commercial sectors was calculated for the following fuel categories using 1998 as 

the base year (the same year that the model boiler algorithms are based on): steam 

coal (2.6 percent), natural gas (6.3 percent), residual fuel oil (–7.4 percent), distillate 

fuel oil (12.0 percent), and biomass (11.5 percent). It should be noted that 1998 was a 

year of below average energy prices, and that current and potential future energy 

prices are higher than the historical average. If real fuel prices increase faster than the 

EIA’s projections, then conservation measures may lead to fewer projected boilers 

and process heaters. This trend would lead to an overestimate (upward bias) of the 

impact estimates presented in this report. 
3-47 

2. Estimate the number of new boilers by model number-fuel type. To predict the 

number of new boilers in operation by 2005, EPA applied the percentage difference 

for each fuel category to the 1998 fuel consumption of boilers represented by the 

boiler models to calculate total energy consumed by boilers in 2005 for each model 

number. The number of new boilers per model was calculated by dividing the model 

fuel forecasts by the annual fuel consumption of one unit and then subtracting the 

number of units present in 1998, as follows: 

Number of

New Units = ⎝

⎜

⎛

⎠

⎟ Total energy consumed (2005) [MMBtu/yr]⎞

Avg capacity [MMBtu/hr] x 8,760 [hr/yr] – Number of

Units (1998) 

Following these steps, EPA projects that 1,458 boilers and 374 process heaters to be 

installed between 1998 and 2005 will be affected by the new source MACT floor. The only new 

ICI boilers and process heaters that will be unaffected are those natural gas and distillate fuel 

units that have input capacities less than 10 MMBtu/hr. These projections were developed by 

model unit type, not by industry. 

To assess the distribution of the boilers and process heaters estimated to be operating in 

2005 across industries, EPA attached unit-level weights by model number to each unit in the 

Inventory Database. These weights allow each unit in the Inventory Database to represent a 

number (or fraction) of units that are predicted to be in use by the end of 2005. The weights were 

then summed by two-digit SIC code to estimate the distribution of units by industry. 

Table 3-5 presents the projected number of new boilers and process heaters for the 

MACT floor. Industries with the estimated greatest concentrations of new units include 

chemicals and allied products (295), petroleum refining (198), electric services (134), and paper 

and allied products (96). 

3.5 National Engineering Population, Cost Estimates, and Cost-Effectiveness Estimates 

The Agency estimates that in 2005, 5,562 units (existing units and new units) may be affected by 

the final rule. This population was used to estimate national engineering costs. As discussed 

previously, the distribution of units by industry shown in Tables 3-5 and 3-6 was determined by 

weighting 2,186 units with SIC code information to represent all 5.562 existing and new units, 

and then tallying weighted units by SIC code. The weights assigned to each existing unit in the 

Inventory Database were derived by comparing the existing unit’s configuration (e.g., fuel type, 

control type, size) with the 2005 estimated population of units with the same configuration. The 

average cost of control by unit configuration was multiplied by the weighted number of units to 

determine industry-level control cost estimates. 
3-48 

Table 3-5. New Unit Projections by Industry, MACT Floor 

SIC 

Code

NAICS 

Code Description New Units Cost

01 111 Agriculture—Crops — — 

02 112 Agriculture—Livestock — — 

07 115 Agricultural Services — — 

10 212 Metal Mining 6 $47,040 

12 212 Coal Mining 1 $7,840 

13 211 Oil and Gas Extraction 89 $697,760 

14 212 Mining/Quarrying—Nonmetallic Minerals 6 $87,740 

17 235 Construction—Special Trade Contractors — — 

20 311 Food and Kindred Products 63 $801,836 

21 312 Tobacco Products 7 $54,880 

22 313 Textile Mill Products 73 $1,329,391 

23 315 Apparel and Other Products from Fabrics — — 

24 321 Lumber and Wood Products 61 $1,748,655 

25 337 Furniture and Fixtures 47 $1,354,701 

26 322 Paper and Allied Products 96 $1,526,704 

27 511 Printing, Publishing, and Related Industries 19 $148,960 

28 325 Chemicals and Allied Products 295 $3,793,738 

29 324 Petroleum Refining and Related Industries 198 $1,552,320 

30 326 Rubber and Miscellaneous Plastics Products 44 $385,660 

31 316 Leather and Leather Products 5 $39,200 

32 327 Stone, Clay, Glass, and Concrete Products 37 $549,975 

33 331 Primary Metal Industries 80 $2,873,492 

34 332 Fabricated Metal Products 53 $496,920 

35 333 Industrial Machinery and Computer Equipment 35 $396,500 

36 335 Electronic and Electrical Equipment 40 $313,600 

37 336 Transportation Equipment 80 $1,133,423 

38 334 Scientific, Optical, and Photographic Equipment 11 $86,240 

39 339 Miscellaneous Manufacturing Industries 9 $162,323 

40 482 Railroad Transportation — — 

42 484 Motor Freight and Warehousing 1 $48,540 

46 486 Pipelines, Except Natural Gas 1 $7,840 

49 221 Electric, Gas, and Sanitary Services 134 $2,094,546 

50 421 Wholesale Trade—Durable Goods — — 

51 422 Wholesale Trade—Nondurable Goods — — 

(continued) 
3-49 

Table 3-5. New Unit Projections by Industry, MACT Floor (continued) 

SIC 

Code NAICS Code Description New Units Cost

55 441 Automotive Dealers and Gasoline Service Stations — — 

58 722 Eating and Drinking Places — — 

59 445–454 Miscellaneous Retail — — 

60 522 Depository Institutions — — 

70 721 Hotels and Other Lodging Places — — 

72 812 Personal Services 1 $7,840 

76 811 Miscellaneous Repair Services — — 

80 621 Health Services 6 $209,840 

81 541 Legal Services — — 

82 611 Educational Services 19 $815,855 

83 624 Social Services — — 

86 813 Membership Organizations — — 

87 541 Engineering, Accounting, Research, Management and 

Related Services 

2 $388,350 

89 711/514 Services, N.E.C. — — 

91 921 Executive, Legislative, and General Administration — — 

92 922 Justice, Public Order, and Safety 4 $153,460 

94 923 Administration of Human Resources — — 

96 926 Administration of Economic Programs — — 

97 928 National Security and International Affairs 2 $97,080 

NA SIC Information Not Available 307 $2,497,327 

State Parent is a State Government — — 

 1,832 $25,909,574 

Table 3-6 presents industry-level population and cost estimates for boilers and process 

heaters. The distribution of weighted units across industries mirrors that of the analysis 

population even though it was determined by weighting units by configuration, not industry-level 

growth estimates. The floor cost of control for the estimated 5,562 boilers and process heaters is 

$746.5 million, with an average per-unit additional control cost of $134,212. 
3-50 

Table 3-6. Unit Cost and Population Estimates for the Final Rule by Industry, 2005 

Total Units Total Cost

SIC 

Code

NAICS 

Code Description Floor Units Percent

Floor Costs 

(by Unit) Percent

01 111 Agriculture—Crops 5 0.08 $628,943 0.08 

02 112 Agriculture—Livestock — 0.00 — 0.00 

07 115 Agricultural Services — 0.00 — 0.00 

10 212 Metal Mining 27 0.48 $6,651,678 0.89 

12 212 Coal Mining 6 0.10 $235,107 0.03 

13 211 Oil and Gas Extraction 89 1.60 $697,760 0.09 

14 212 Mining/Quarrying—Nonmetallic Minerals 25 0.46 $8,253,479 1.11 

17 235 Construction—Special Trade Contractors — 0.00 — 0.00 

20 311 Food and Kindred Products 312 5.60 $28,641,029 3.84 

21 312 Tobacco Products 28 0.51 $5,460,065 0.73 

22 313 Textile Mill Products 360 6.47 $67,982,598 9.11 

23 315 Apparel and Other Products from Fabrics 4 0.08 $472,691 0.06 

24 321 Lumber and Wood Products 483 8.68 $31,368,106 4.20 

25 337 Furniture and Fixtures 311 5.59 $17,723,831 2.37 

26 322 Paper and Allied Products 565 10.15 $118,213,485 15.84 

27 511 Printing, Publishing, and Related Industries 19 0.34 $148,960 0.02 

28 325 Chemicals and Allied Products 644 11.58 $101,104,523 13.54 

29 324 Petroleum Refining and Related Industries 217 3.91 $3,806,027 0.51 

30 326 Rubber and Miscellaneous Plastics Products 73 1.32 $5,972,514 0.80 

31 316 Leather and Leather Products 7 0.13 $607,530 0.08 

32 327 Stone, Clay, Glass, and Concrete Products 57 1.02 $4,772,789 0.64 

33 331 Primary Metal Industries 159 2.85 $23,403,883 3.14 

34 332 Fabricated Metal Products 87 1.56 $7,405,792 0.99 

35 333 Industrial Machinery and Computer 

Equipment 

84 1.51 

$9,655,328 1.29 

36 335 Electronic and Electrical Equipment 52 0.93 $3,744,828 0.50 

37 336 Transportation Equipment 300 5.39 $44,905,003 6.02 

38 334 Scientific, Optical, and Photographic 

Equipment 

26 0.46 

$3,277,844 0.44 

39 339 Miscellaneous Manufacturing Industries 12 0.22 $826,346 0.11 

40 482 Railroad Transportation 9 0.16 $1,251,062 0.17 

42 484 Motor Freight and Warehousing 12 0.22 $1,507,689 0.20 

46 486 Pipelines, Except Natural Gas 1 0.02 $7,840 0.00 

49 221 Electric, Gas, and Sanitary Services 718 12.91 $134,204,401 17.98 

50 421 Wholesale Trade—Durable Goods 6 0.12 $2,154,760 0.29 

51 422 Wholesale Trade—Nondurable Goods 4 0.07 $1,673,511 0.22 

55 441 Automotive Dealers and Gasoline Service 

Stations 

— 0.00 — 0.00 

(continued)
3-51 

Table 3-6. Unit Cost and Population Estimates for the Final Rule by Industry, 2005 

(continued) 

Total Units Total Cost

SIC 

Code

NAICS 

Code Description Floor Units Percent

Floor Costs 

(by Unit) Percent

58 722 Eating and Drinking Places — 0.00 — 0.00 

59 445–454 Miscellaneous Retail — 0.00 — 0.00 

60 522 Depository Institutions — 0.00 — 0.00 

70 721 Hotels and Other Lodging Places 2 0.04 $567,811 0.08 

72 812 Personal Services 1 0.02 $7,840 0.00 

76 811 Miscellaneous Repair Services 4 0.08 $625,531 0.08 

80 621 Health Services 86 1.55 $13,015,265 1.74 

81 541 Legal Services — 0.00 — 0.00 

82 611 Educational Services 251 4.52 $54,837,468 7.35 

83 624 Social Services 5 0.08 $820,191 0.11 

86 813 Membership Organizations — 0.00 — 0.00 

87 541 Engineering, Accounting, Research, 

Management and Related Services 

38 0.68 

$2,240,544 0.30 

89 711/514 Services, N.E.C. 2 0.04 $918,360 0.12 

91 921 Executive, Legislative, and General 

Administration 

2 0.04 

$312,765 0.04 

92 922 Justice, Public Order, and Safety 69 1.23 $13,087,190 1.75 

94 923 Administration of Human Resources 2 0.04 $107,496 0.01 

96 926 Administration of Economic Programs 8 0.15 $1,746,157 0.23 

97 928 National Security and International Affairs 64 1.16 $16,355,556 2.19 

NA SIC Information Not Available 326 5.86 $5,085,199 0.68 

State Parent is a state government — 0.00 — 0.00 

 5,562 $746,486,774 

4-1 

SECTION 4 

PROFILES OF AFFECTED INDUSTRIES 

This section contains profiles of the major industries affected by the MACT for boilers 

and process heaters. Included are profiles of the following industries: 

 Textile Mill Products (SIC 22/NAICS 313) 

 Lumber and Wood Products (SIC 24/NAICS 321) 

 Furniture and Related Product Manufacturing (SIC 25/NAICS 337) 

 Paper and Allied Products (SIC 26/NAICS 322) 

 Medicinal Chemicals and Botanical Products and Pharmaceutical Preparations (SICs 

2833, 2834/NAICS 32451) 

 Industrial Organic Chemicals (SIC 2869/NAICS 3251) 

 Electric Services (SIC 4911/NAICS 22111) 

4.1 Textile Mill Products (SIC 22/NAICS 313) 

The textile industry is one of the few industries found throughout the world, from the 

most industrialized countries to the poorest. This industry includes firms producing the following 

products: broadwoven fabric; weft, lace, and warp knit fabrics; carpets and rugs; spun yarn 

products; and man-made fibers. The United States has typically run a trade deficit in the textiles 

sector in recent years, importing about $1.3 billion more than was exported in 1995. Although 

trade has become an increasingly important part of this industry, trade in this segment is 

relatively small compared with trade in the downstream apparel segment. In 1996, the total value 

of shipments for the textile industry was $80,242 million. 

4.2 Lumber and Wood Products (SIC 24/NAICS 321) 

The lumber and wood products industry comprises a large number of establishments 

engaged in logging; operating sawmills and planing mills; and manufacturing structural wood 

panels, wooden containers, and other wood products. Table 4-1 lists the lumber and wood 

products markets that are likely to be affected by the regulation on boilers. Most products are 

produced for the domestic market, but exports increasingly account for a larger proportion of 

sales (Haltmaier, 1998). The largest consumers of lumber and wood products are the remodeling 

and construction industries. 
4-2 

Table 4-1. Lumber and Wood Products Markets Likely to Be Affected by the Regulation 

SIC NAICS Description

2421 321113 Sawmills and Planing Mills, General 

2434 33711 Wood Kitchen Cabinets 

2449 32192 Wood Containers, N.E.C. 

2491 32114 Wood Preserving 

2493 321219 Reconstituted Wood Products 

2499 321999 Wood Products, N.E.C. 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 

In 1996, the lumber and wood products industry’s total value of shipments was 

$85,724.0 million. As seen in Table 4-2, shipment values increased steadily through the late 

1980s before declining slightly through the early 1990s as new construction starts and furniture 

purchases declined (Haltmaier, 1998). Shipment values recovered, however, as the economy 

expanded in the mid-1990s. 

Table 4-2. Value of Shipments for the Lumber and Wood Products Industry 

(SIC 24/NAICS 321), 1987–1996 

Year Value of Shipments (1992 $106)

1987 85,383.4 

1988 85,381.2 

1989 85,656.8 

1990 86,203.0 

1991 81,666.0 

1992 81,564.8 

1993 74,379.6 

1994 79,602.0 

1995 87,574.6 

1996 85,724.0 

Sources: U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures 

[Multiple Years]. Washington, DC: Government Printing Office. 
4-3 

4.2.1 Supply Side of the Industry 

This section describes the lumber industry’s production processes, output, costs of 

production, and capacity utilization. 

4.2.1.1 Production Processes 

Sawn lumber. Sawn lumber is softwood or hardwood trimmed at a sawmill for future 

uses in construction, flooring, furniture, or other markets. Softwoods, such as Douglas fir and 

spruce, are used for framing in residential or light-commercial construction. Hardwoods, such as 

maple and oak, are used in flooring, furniture, crating, and other applications. 

Lumber is prepared at mills using a four-step process. First, logs are debarked and 

trimmed into cants, or partially finished lumber. The cants are then cut to specific lengths. Logs 

are generally kept wet during storage to prevent cracking and to keep them supple. However, 

after being cut, the boards undergo a drying process, either in open air or in a kiln, to reduce the 

moisture content. The drying process may take several months and varies according to the 

plant’s climate and the process used. Finally, the lumber may be treated with a surface protectant 

to prevent sap stains and prepare it for export (EPA, 1995a). 

Reconstituted wood products. Reconstituted wood products, such as particleboard, 

medium density fiberboard, hardboard, and oriented strandboard, are made from raw wood that 

is combined with resins and other additives and processed into boards. The size of the wood 

particles used varies from sawdust to strands of wood. Once combined, the ingredients are 

formed into a mat and then, at high temperatures, pressed into a board. A final finishing process 

prepares the boards for delivery. 

Wood preserving. Wood is treated with preservative to protect it from mechanical, 

physical, and chemical influences (EPA, 1995a). Treatment agents are either water-based 

inorganics, such as copper arsenate (78 percent), or oil-borne organics, such as creosote 

(21 percent) (EPA, 1995a). Wood preservatives are usually applied using a pressure treatment 

process or a dipping tank. Producers achieve the best results when the lumber’s moisture content 

is reduced to a point where the preservative can be easily soaked into the wood. Treated wood is 

then placed in a kiln or stacked in a low-humidity climate to dry. 

4.2.1.2 Types of Output 

The lumber and wood products industry produces essential inputs into the construction, 

remodeling, and furniture sectors. Lumber and reconstituted wood products are produced in an 

array of sizes and can be treated to enhance their value and shelf-life. These products are 
4-4 

intermediate goods; they are purchased by other industries and incorporated into higher valueadded products. In addition to sawmills, the lumber and wood products industry includes kitchen 

cabinets, wood containers, and other wooden products used for fabricating finished goods for 

immediate consumption. 

4.2.1.3 Major By-Products and Co-Products 

Shavings, sawdust, and wood chips are the principal co-products of sawn lumber. Paper 

mills and makers of reconstituted wood products frequently purchase this material as an input. 

By-products are limited to emissions from the drying process and from use of preservatives. 

Very little solid waste is generated by reconstituted wood products manufacturing. 

Because the production process incorporates all parts of the sawn log, little is left over as waste. 

However, air emissions from dryers are a source of emissions. 

Wood preserving results in two types of by-products: air emissions and process debris. 

As preservatives dry, either in a kiln or outside, they emit various chemicals into the air. At 

plants with dipping processes, wood chips, stones, and other debris build up in the dipping tank. 

The debris is routinely collected and disposed of. 

4.2.1.4 Costs of Production 

The costs of production for the wood products industry fluctuate with the demand for the 

industry’s products. Most notably, the costs of production steadily declined during the early 

1990s as recession stifled furniture purchases and new housing starts (see Table 4-3). Overall, 

employment in the lumber and wood products industry increased approximately 6 percent from 

1987 to 1996. During this same period, payroll costs decreased 12 percent, indicating a decrease 

in average annual income per employee. New capital investment and costs of materials generally 

moved in tandem over the 10-year period, increasing from 1987 to 1990 and 1994 to 1996 and 

decreasing from 1991 to 1993. 

4.2.1.5 Capacity Utilization 

Full production capacity is broadly defined as the maximum level of production an 

establishment can obtain under normal operating conditions. The capacity utilization ratio is the 

ratio of the actual production level to the full production level. Table 4-4 presents the historical 

trends in capacity utilization for the lumber and wood products industry. The varying capacity 

utilization ratios reflect adjusting production levels and new production facilities going on- or 

off-line. The capacity utilization ratio for the industry in 1996 was 78; the average over the last 6 

years was 79 percent. 
4-5 

Table 4-3. Inputs for the Lumber and Wood Products Industry (SIC 24/NAICS 321), 1987–

1996 

Labor

Year Quantity 

(103

) 

Payroll 

(1992 $106

)

Materials 

(1992 $106

) 

New Capital Investment 

(1992 $106) 

1987 698.4 15,555.5 50,509.2 2,234.3 

1988 702.4 15,800.0 51,341.0 2,099.4 

1989 684.2 15,381.3 51,742.2 2,329.9 

1990 677.7 15,612.9 53,369.0 2,315.3 

1991 623.6 14,675.8 50,416.3 2,006.5 

1992 655.8 13,881.8 48,570.0 1,760.1 

1993 685.4 11,798.9 45,300.3 1,538.1 

1994 718.5 12,212.5 48,535.6 1,956.8 

1995 740.2 13,915.4 53,732.9 2,553.1 

1996 738.7 13,933.7 52,450.1 2,659.9 

Sources: U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures 

[Multiple Years]. Washington, DC: Government Printing Office. 

Table 4-4. Capacity Utilization Ratios for Lumber and Wood Products Industry, 1991–

1996 

1991 1992 1993 1994 1995 1996

78 80 81 80 77 78 

Note: All values are percentages. 

Source: U.S. Department of Commerce, Bureau of the Census. 1998. Survey of Plant Capacity: 1996. Washington, 

DC: Government Printing Office. 

4.2.2 Demand Side of the Industry 

This section describes the demand side of the market, including product characteristics, 

the uses and consumers of the final products, organization of the industry, and markets and 

trends. 

4.2.3 Product Characteristics 

Lumber and wood products are valued both for their physical attributes and their relative 

low cost. Wood is available in varying degrees of durability, shades, and sizes and can be easily 

shaped. Lumber and wood products have long been the principal raw materials for the residential 

and light commercial construction industries, the remodeling industry, and the furniture industry. 
4-6 

Wood is readily available because over one-third of the United States is forested. The ready 

supply of wood reduces its costs. 

4.2.4 Uses and Consumers of Outputs 

Lumber and wood products are used in a wide range of applications, including residential 

and nonresidential construction; repair/remodeling and home improvement projects; 

manufactured housing; millwork and wood products; pulp, paper, and paperboard mills; toys and 

sporting goods; kitchen cabinets; crates and other wooden containers; office and household 

furniture; and motor homes and recreational vehicles (Haltmaier, 1998). 

4.2.5 Organization of the Industry 

In 1992, 33,878 companies produced lumber and wood products and operated 35,807 

facilities, as shown in Table 4-5. By way of comparison, in 1987, 32,014 companies controlled 

33,987 facilities. About two-thirds of all establishments have nine or fewer employees. Between 

1987 and 1992, the number of facilities with nine or fewer employees increased more than 10 

percent to 23,590. These facilities’ share of the value of shipments increased about 18.3 percent. 

Although the number of establishments employing 100 to 249 people decreased during that time, 

that category’s shipment value jumped nearly 40 percent. The remaining facility categories lost 

both facilities and value of shipment. 

Market structure can affect the size and distribution of regulatory impacts. Concentration 

ratios are often used to evaluate the degree of competition in a market, with low concentration 

indicating the presence of a competitive market, and higher concentration suggesting lesscompetitive markets. Firms in less-concentrated industries are more likely to be price takers, 

while firms in more-concentrated industries are more likely to influence market prices. Typical 

measures include four- and eight-firm concentration ratios (CR4 and CR8) and HerfindahlHirschmann indices (HHI). The CR4 for lumber and wood products subsectors represented in the 

boilers inventory database ranges between 13 and 50, meaning that, in each subsector, the top 

firms’ combined sales ranged from 13 to 50 percent of that respective subsector’s total sales. The 

CR8 ranges from 47 to 66 (U.S. Department of Commerce, 1995d). 

Although there is no objective criterion for determining market structure based on the 

values of concentration ratios, the 1992 Department of Justice’s (DOJ’s) Horizontal Merger 

Guidelines provide criteria for doing so based on HHIs. According to these criteria, industries 

with HHIs below 1,000 are considered unconcentrated (i.e., more competitive), those with HHIs 

between 1,000 and 1,800 are considered moderately concentrated (i.e., moderately competitive), 

and those with HHIs above 1,800 are considered highly concentrated (i.e., less competitive) 
4-7 

Table 4-5. Size of Establishments and Value of Shipments for the Lumber and Wood 

Products Industry (SIC 24/NAICS 321) 

1987 1992

Average Number of Employees in 

Establishment

Number of 

Facilities

Value of 

Shipments 

(1992 $106)

Number of 

Facilities

Value of 

Shipments 

(1992 $106)

1 to 4 employees 14,562 2,769.7 15,921 3,288.9 

5 to 9 employees 6,702 4,264.4 7,669 5,030.4 

10 to 19 employees 5,353 6,982.3 5,331 6,902.8 

20 to 49 employees 4,160 28,551.3 3,924 26,964.9 

50 to 99 employees 1,702 (D) 1,615 (D) 

100 to 249 employees 1,190 24,583.3 1,082 34,051.4 

250 to 499 employees 260 12,093.4 219 (D) 

500 to 999 employees 47 3,907.9 39 3,331.4 

1,000 to 2,499 employees 4 2,231.3 4 598.6 

2,500 or more employees 2 (D) 3 1,396.4 

Total 33,987 85,383.4 35,807 81,564.8 

(D) = undisclosed 

Sources: U.S. Department of Commerce, Bureau of the Census. 1991. 1987 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

(DOJ, 1992). Firms in less-concentrated industries are more likely to be price takers, while firms 

in more-concentrated industries are more likely to be able to influence market prices. The 

unconcentrated nature of the markets is also indicated by HHIs of 1,000 or less (DOJ, 1992). 

Table 4-6 presents various measures of market concentration for sectors within the lumber and 

wood products industry. All lumber and wood products industries are considered unconcentrated 

and competitive. 

4.2.6 Markets and Trends 

The U.S. market for lumber and wood products is maturing, and manufacturers are 

looking to enter other markets. Although 91 percent of the industry’s products are consumed by 

the U.S. domestic market, the share of exports increases each year. Exports more than doubled in 

value from $3 billion in 1986 to $7.3 billion in 1996 (Haltmaier, 1998). The U.S. market grew 

only 2 percent between 1986 and 1996. American manufacturers are focusing on growing 

construction markets in Canada, Mexico, and the Pacific Rim, with products such as durable 

hardwood veneer products and reconstituted wood boards (EPA, 1995a). 
4-8 

Table 4-6. Measures of Market Concentration for Lumber and Wood Products Markets 

SIC Description

Comparable 

NAICS CR4 CR8 HHI

Number of 

Companies

Number of 

Facilities

2421 Saw Mills and Planing 

Mills 

321912, 321113, 

321918, 321999 

14 20 78 5,302 6004 

2434 Wood Kitchen Cabinets 33711 19 25 156 4,303 4323 

2449 Wood Containers, N.E.C. 32192 34 47 414 217 225 

2491 Wood Preserving 321114 17 28 152 408 486 

2493 Reconstituted Wood 

Products 

321219 50 66 765 193 288 

2499 Wood Products, N.E.C. 339999, 333414, 

32192, 321999 

13 19 70 2,656 2754 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995d. 1992 Concentration Ratios in 

Manufacturing. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

4.3 Furniture and Related Product Manufacturing (SIC 25/NAICS 337) 

More than 20,000 establishments in the United States produce furniture and furniturerelated products. These establishments are located across the United States but are traditionally 

most concentrated in southern states, such as North Carolina, Mississippi, Alabama, and 

Tennessee. According to the “1997 Economic Census,” these establishments employed more 

than 600,000 people and paid annual wages of nearly $15 billion. The overall industry-wide 

value of shipments was $63.9 billion that year (U.S. Department of Commerce, 2001). 

This industry is in a state of change: rapid U.S. economic growth translated into vigorous 

sales of household and office furniture, but this trend is unlikely to continue as the U.S. economy 

cools after its record run. Adding to industry fluctuation is the merger of two large firms, Lay-ZBoy and LADD Furniture. Although the industry includes a multitude of niche market players, it 

is really dominated by a few large companies that operate several subsidiaries, each with its own 

brand identity. It is unclear whether the merger between two key players in the market will 

compel other large manufacturers to pursue mergers and acquisitions. 

What is clear, however, is that large U.S. manufacturers will seek to leverage their brand 

identities into wider profit margins by operating direct sales establishments and co-branding. 

Manufacturers that are moving into retail and distribution include Bassett Furniture, Thomasville 

Furniture, Ethan Allen Interiors, and Drexel. Co-branding efforts are aimed at capitalizing on the 

combined power of two identities, such as the Thomas Kinkade Collection from Lay-Z-Boy and 
4-9 

popular artist Thomas Kinkade and the Ernest Hemingway Collection from Thomasville. The 

overarching goal is to enhance margins and ward off invigorated competition from foreign 

companies that have used this strategy to capture U.S. market share, such as the Swedish 

manufacturer Ikea (Lemm, 2000). 

U.S. imports of household furniture totaled nearly $7 billion in 1998. Between 1992 and 

1998, furniture imports grew at an annualized rate of nearly 15 percent. Jamie Lemm, an analyst 

with the U.S. Department of Commerce’s Office of Consumer Goods attributes this growth to 

changes in U.S. manufacturing and markets: 

A portion of [the] increase can be attributed to the labor-intensive furniture parts 

imported by U.S. manufacturers to enhance product lines, but the increase also signifies 

the growing importance of the U.S. market to foreign firms. While some U.S. 

manufacturers operate showrooms, galleries, and retail outlets in foreign markets, few 

sell internationally on a large scale. In 1998, U.S. furniture exports totaled $1.6 billion, 

accounting for only 6 percent of all U.S. product shipments. 

4.4 Paper and Allied Products (SIC 26/NAICS 322) 

The paper and allied products industry is one of the largest manufacturing industries in 

the United States. In 1996, the industry shipped nearly $150 billion in paper commodities. The 

industry produces a wide range of wood pulp, primary paper products, and paperboard products 

such as printing and writing papers, industrial papers, tissues, container board, and boxboard. 

The industry also includes manufacturers that “convert” primary paper and paperboard into 

finished products like envelopes, packaging, and shipping containers ( EPA, 1995b). Paper and 

allied products industry subsectors that are likely to be affected by the regulation are listed in 

Table 4-7. 

Table 4-7. Paper and Allied Products Industry Markets Likely to Be Affected by 

Regulation 

SIC NAICS Industry Description

2611 32211 Pulp Mills 

2621 32212 Paper Mills 

2676 322291 Sanitary Paper Products 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 
4-10 

Table 4-8 lists the paper and allied products industry’s value of shipments from 1987 to 

1996. The industry’s performance is tied to raw material prices, labor conditions, and worldwide 

inventories and demand (EPA, 1995b). Performance over the 10-year period was typical of most 

manufacturing industries. The industry expanded in the late 1980s, then contracted as demand 

tapered off as the industry suffered recessionary effects. In the two years after 1994, the 

industry’s value of shipments increased 9.3 percent to $149.5 billion. 

Table 4-8. Value of Shipments for the Paper and Allied Products Industry 

(SIC 26/NAICS 322), 1987–1996 

Year

Value of Shipments 

(1992 $106

)

1987 129,927.8 

1988 136,829.4 

1989 138,978.3 

1990 136,175.7 

1991 132,225.0 

1992 133,200.7 

1993 131,362.2 

1994 136,879.9 

1995 135,470.3 

1996 149,517.1 

Sources: U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summary. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures, 

[Multiple Years]. Washington, DC: Government Printing Office. 

4.4.1 Supply Side of the Industry 

4.4.1.1 Production Process 

The manufacturing paper and allied products industry is capital- and resource-intensive, 

consuming large amounts of pulp wood and water in the manufacturing process. Approximately 

half of all paper and allied products establishments are integrated facilities, meaning that they 

produce both pulp and paper on-site. The remaining half produce only paper products; few 

facilities produce only pulp (EPA, 1995b). 
4-11 

The paper and paperboard manufacturing process can be divided into three general steps: 

pulp making, pulp processing, and paper/paperboard production. Paper and paperboard are 

manufactured using what is essentially the same process. The principal difference between the 

two products is that paperboard is thicker than paper’s 0.3 mm. 

Producers manufacture pulp mixtures by using chemicals, machines, or both to reduce 

raw material into small fibers. In the case of wood, the most common pulping material, chemical 

pulping actions release cellulose fibers by selectively destroying the chemical bonds that bind the 

fibers together (EPA, 1995b). Impurities are removed from the pulp, which then may be 

bleached to improve brightness. Only about 20 percent of pulp and paper mills practice 

bleaching (EPA, 1995b). The pulp may also be further processed to aid in the paper-making 

process. 

During the paper-making stage, the pulp is strengthened and then converted into paper. 

Pulp can be combined with dyes, resins, filler materials, or other additives to better fulfill 

specifications for the final product. Next, the water is removed from the pulp, leaving the pulp on 

a wire or wire mesh conveyor. The fibers bond together as they are carried through heated 

presses and rollers. The paper is stored on large rolls before being shipped for conversion into 

another product, such as envelopes and boxes, or cut into paper sheets for immediate 

consumption. 

4.4.1.2 Types of Output 

The paper and allied products industry’s output ranges from writing papers to containers 

and packaging. Paper products include printing and writing papers; paperboard boxes; corrugated 

and solid fiber boxes; fiber cans, drums, and similar products; sanitary food containers; building 

paper; packaging; bags; sanitary paper napkins; envelopes; stationary products; and other 

converted paper products. 

4.4.1.3 Major By-Products and Co-Products 

The paper and allied products industry is the largest user of industrial process water in the 

United States. In 1988, a typical mill used between 16,000 and 17,000 gallons of water per ton of 

paper produced. The equivalent amount of waste water discharged each day is about 16 million 

cubic meters (EPA, 1995b). Most facilities operate waste water treatment facilities on site to 

remove biological oxygen demand (BOD), total suspended solids (TSS), and other pollutants 

before discharging the water into a nearby waterway. 
4-12 

4.4.1.4 Costs of Production 

Historical statistics for the costs of production for the paper and allied products industry 

are listed in Table 4-9. From 1987 to 1996, industry payroll generally ranged from approximately 

$19 to 20 billion. Employment peaked at 633,200 people in 1989 and declined slightly to 

630,600 people by 1996. Materials costs averaged $74.4 billion a year and new capital 

investment averaged $8.3 billion a year. 

Table 4-9. Inputs for the Paper and Allied Products Industry (SIC 26/NAICS 322), 1987–

1996 

Labor

Year Quantity (103

) Payroll (1992 $106)

Materials 

(1992 $106

)

New Capital 

Investment 

(1992 $106)

1987 611.1 20,098.6 70,040.6 6,857.5 

1988 619.8 19,659.0 73,447.4 8,083.8 

1989 633.2 19,493.1 75,132.5 10,092.9 

1990 631.2 19,605.2 74,568.8 11,267.2 

1991 624.7 19,856.3 72,602.5 9,353.9 

1992 626.3 20,491.9 73,188.0 7,962.4 

1993 626.3 20,602.6 73,062.6 7,265.2 

1994 621.4 20,429.7 76,461.6 6,961.7 

1995 629.2 18,784.3 79,968.6 7,056.8 

1996 630.6 19,750.0 75,805.9 8,005.9 

Sources: U.S. Department of Commerce, Bureau of the Census. 1996. 1992 Census of Manufactures, Subject Series: 

General Summery. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures 

[Multiple Years]. Washington, DC: Government Printing Office. 

4.4.1.5 Capacity Utilization 

Table 4-10 presents the trend in capacity utilization for the paper and allied products 

industry. The varying capacities reflect adjusting production levels and new production facilities 

going on- or off-line. The average capacity utilization ratio for the paper and allied products 

industry between 1991 and 1996 was approximately 80, with capacity declining slightly in recent 

years. 
4-13 

Table 4-10. Capacity Utilization Ratios for the Paper and Allied Products Industry, 1991–

1996 

1991 1992 1993 1994 1995 1996

78 80 81 80 77 78 

Note: All values are percentages. 

Source: U.S. Department of Commerce, Bureau of the Census. 1998. Survey of Plant Capacity: 1996. Washington, 

DC: Government Printing Office. 

4.4.2 Demand Side of the Industry 

4.4.2.1 Product Characteristics 

Paper is valued for its diversity in product types, applications, and low cost due to ready 

access to raw materials. Manufacturers produce papers of varying durabilities, textures, and 

colors. Consumers purchasing large quantities of papers may have papers tailored to their 

specification. Papers may be simple writing papers or newsprint for personal consumption and 

for the printing and publishing industry or durable for conversion into shipping cartons, drums, 

or sanitary boxes. Inputs in the paper production process are readily available in the United 

States because one-third of the country is forested, and facilities generally have ready access to 

waterways. 

4.4.2.2 Uses and Consumers of Products 

The paper and allied products industry is an integral part of the U.S. economy; nearly 

every industry and service sector relies on paper products for its personal, education, and 

business needs. Among a myriad of uses, papers are used for correspondence, printing and 

publishing, packing and storage, and sanitary purposes. Common applications are all manners of 

reading material, correspondence, sanitary containers, shipping cartons and drums, and 

miscellaneous packing materials. 

4.4.3 Organization of the Industry 

In 1992, 4,264 companies produced paper and allied products and operated 6,416 

facilities. By way of comparison, 4,215 companies controlled 1,732 facilities in 1987. Although 

the number of small firms and facilities increased during those 5 years, the industry is dominated 

by high-volume, low-cost producers (Haltmaier, 1998). Even though they account for only 45 

percent of all facilities, those with 50 or more employees contribute more than 93 percent of the 

industry’s total value of shipments (see Table 4-11). (According to the Small Business 

Administration, those companies employing fewer than 500 employees are “small.”) 
4-14 

Table 4-11. Size of Establishments and Value of Shipments for the Paper and Allied 

Products Industry (SIC 26/NAICS 322) 

1987 1992

Number of Employees in 

Establishment

Number of 

Facilities

Value of 

Shipments ($106

)

Number of 

Facilities

Value of 

Shipments ($106)

1 to 4 employees 729 640.6 786 216 

4 to 9 employees 531 (D) 565 483 

10 to 19 employees 888 1,563.4 816 1,456.5 

20 to 49 employees 1,433 18,328.6 1,389 6,366.6 

50 to 99 employees 1,018 (D) 1,088 12,811.5 

100 to 249 employees 1,176 32,141.7 1,253 35,114.0 

250 to 499 employees 308 24,221.1 298 22,281.2 

500 to 999 employees 145 28,129.1 159 31,356.5 

1,000 to 2,499 employees 63 24,903.1 62 23,115.4 

2,500 or more employees 1 (D) 

Total 1,732 129,927.8 6,416 133,200.7 

(D) = undisclosed 

Sources: U.S. Department of Commerce, Bureau of the Census. 1990c. 1987 Census of Manufactures, Industry 

Series: Pulp, Paper, and Board Mills. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1995c. 1992 Census of Manufactures, Industry 

Series: Pulp, Paper, and Board Mills. Washington, DC: Government Printing Office. 

For paper and allied products markets likely to be affected by the boilers regulation, the 

CR4 ranged between 29 and 68 in 1992 (see Table 4-12). This means that, in each subsector, the 

top firms’ combined sales ranged from 29 to 68 percent of their respective industry’s total sales. 

For example, in the sanitary paper products industry, the CR4 ratios indicate that a few firms 

control 68 percent of the market. This sector’s moderately concentrated nature is also indicated 

by its HHI of 1,451 (DOJ, 1992). The remaining two sectors’ HHIs indicate that their respective 

markets are unconcentrated (i.e., competitive). 

4.4.4 Markets and Trends 

The Department of Commerce projects that shipments of paper and allied products will increase 

through 2002 by an annual average of 2.5 percent (Haltmaier, 1998). Because nearly all of the 

industry’s products are consumer related, shipments will be most affected by the health of the 

U.S. and global economy. The United States is a key competitor in the international market for 

paper products and, after Canada, is the largest exporter of paper products. According to 

Haltmaier (1998), the largest paper and allied products exporters in the world are Canada (with 

23 percent of the market), the United States (10 to 15 percent), Finland (8 percent), and Sweden 

(7 percent). 
4-15 

Table 4-12. Measurements of Market Concentration for Paper and Allied Products 

Markets 

SIC Description CR4 CR8 HHI

Number of 

Companies

Number of 

Facilities

2611 Pulp Mills 48 75 858 29 45 

2621 Paper Mills 29 49 392 127 280 

2676 Sanitary Paper Products 68 82 1,451 80 150 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995d. 1992 Concentration Ratios in 

Manufacturing. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1995c. 1992 Census of Manufactures, Industry 

Series: Pulp, Paper, and Board Mills. Washington, DC: Government Printing Office. 

4.5 Medicinal Chemicals and Botanical Products and Pharmaceutical Preparations 

(SICs 2833, 2834/NAICS 32451) 

The pharmaceutical preparations industry (SIC 2834/NAICS 32451) and the medicinal 

chemicals and botanical products industry (SIC 2833/NAICS 32451) are both primarily engaged 

in the research, development, manufacture, and/or processing of medicinal chemicals and 

pharmaceutical products. Apart from manufacturing drugs for human and veterinary 

consumption, the industries grind, grade, and mill botanical products that are inputs for other 

industries. Typically, most facilities cross over into both industries (EPA, 1997a). Products 

include drugs, vitamins, herbal remedies, and production inputs, such as alkaloids and other 

active medicinal principals. 

Table 4-13 presents both industries’ value of shipments from 1987 to 1996. Medicinals 

and botanicals’ performance during the late 1980s and early 1990s was mixed. However, 

shipments increased steadily from 1994 to 1996, increasing 37.7 percent as natural products such 

as herbs and vitamins became more popular (EPA, 1997a). Pharmaceutical preparations’ 

shipments increased steadily over the 10-year period. From 1987 to 1996, the industry’s 

shipments increased 24.3 percent to $55.1 billion in 1996. 

4.5.1 Supply Side of the Industry 

4.5.1.1 Production Processes 

The medicinals and botanical products industry and the pharmaceutical preparations 

industry share similar production processes. Many products of the former are inputs in the 

latter’s production process. There are three manufacturing stages: research and development, 

preparation of bulk ingredients, and formulation of the final product. 
4-16 

Table 4-13. Value of Shipments for the Medicinals and Botanicals and Pharmaceutical 

Preparations Industries, 1987–1996 

Year

SIC 2833a Medicinals & 

Botanicals ($106)

SIC 2834a Pharmaceutical 

Preparations ($106)

1987 4,629.1 44,345.7 

1988 5,375.4 46,399.1 

1989 5,708.9 48,083.6 

1990 5,535.8 49,718.0 

1991 6,637.7 49,866.3 

1992 6,438.5 50,417.9 

1993 5,669.2 50,973.5 

1994 5,774.7 53,144.7 

1995 6,404.1 53,225.9 

1996 7,952.8 55,103.6 

a

 Comparable NAICS: 325411, 325412. 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures 

[Multiple Years]. Washington, DC: Government Printing Office. 

The research and development stage is a long process both to ensure the validity and 

benefit of the end product and to satisfy the requirements of stringent federal regulatory 

committees. (The pharmaceutical industry operates under strict oversight of the Food and Drug 

Administration [FDA].) Therefore, every stage in the development of new drugs is thoroughly 

documented and studied. After a new compound is discovered, it is subjected to numerous 

laboratory and animal tests. Results are presented to the FDA via applications that present and 

fully disclose all findings to date. As research and development proceeds, studies are gradually 

expanded to involve human trials of the new compound. Should FDA approve the compound, the 

new product is readied for mass production. 

To ensure a uniform product, all ingredients are prepared in bulk using batch processes. 

Companies produce enough of each ingredient to satisfy projected sales demand (EPA, 1997a). 

Prior to production, all equipment is thoroughly cleaned, prepared, and validated to prevent any 

contaminants from entering the production cycle. Most ingredients are prepared by chemical 

synthesis, a method whereby primary ingredients undergo a complex series of processes, 

including many intermediate stages and chemical reactions in a step-by-step fashion (EPA, 

1997a). 
4-17 

After the bulk materials are prepared, they are converted into a final usable form. 

Common forms include tablets, pills, liquids, creams, and ointments. Equipment used in this 

final stage is prepared in the same manner as that involved in the bulk preparation process. Clean 

and validated machinery is used to process and package the pharmaceuticals for shipment and 

consumption. 

4.5.1.2 Types of Output 

Both industries produce pharmaceutical and botanical products for end consumption and 

intermediate products for the industries’ own applications. Products include vitamins, herbal 

remedies, and alkaloids. Prescription and over-the-counter drugs are produced in liquid, tablet, 

cream, and other forms. 

4.5.1.3 Major By-Products and Co-Products 

Both industries produce many by-products because of the large number of primary inputs 

and the extensive chemical processes involved. Wastes and emissions vary by the process 

employed, raw materials consumed, and equipment used. In general, emissions originate during 

drying and heating stages and during process water discharge. Emissions controls are in place 

pursuant to environmental regulations. Other wastes include used filters, spent raw materials, 

rejected product, and reaction residues (EPA, 1997a). 

4.5.1.4 Costs of Production 

Table 4-14 presents SIC 2833 industry’s costs of production and employment statistics 

from 1987 to 1996. Employment was stable during the late 1980s before steadily growing in the 

1990s. In 1987, medicinals and botanicals employed 11,600 people. By 1996, the industry 

employed 16,800, an increase of nearly 45 percent. Materials costs matched the increase in 

shipments over this same period. Industry growth also fed new capital investments, which 

averaged $191.2 million a year in the late 1980s and $515.6 million a year in the early to mid1990s. 

SIC 2834’s costs of production and employment for 1987 to 1996 are presented in 

Table 4-15. The number of people employed by the industry ranged between 123,000 and 

144,000; employment peaked in 1990 before declining by 21,000 jobs by the end of 1992. 

During this 10-year period, the cost of materials rose 42.1 percent. The increase is associated 

with increased product shipments and the development of new, more expensive medications 

(Haltmaier, 1998). New capital investment averaged $2.3 billion a year. 
4-18 

Table 4-14. Inputs for Medicinal Chemicals and Botanical Products Industry 

(SIC 2833/NAICS 32451), 1987–1996 

Labor 

Year Quantity (103)

Payroll 

($106

) 

Materials 

($106)

New Capital 

Investment ($106

)

1987 11.6 520.2 2,229.3 158.2 

1988 11.3 494.4 2,658.8 194.9 

1989 11.4 504.9 3,118.4 263.4 

1990 10.9 476.4 2,902.4 218.9 

1991 12.5 568.6 3,368.2 512.9 

1992 13.0 587.1 3,245.9 550.5 

1993 13.0 584.3 2,638.4 470.0 

1994 13.9 572.6 2,755.2 480.3 

1995 14.1 625.0 3,006.0 356.2 

1996 16.8 752.1 3,793.9 752.1 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures, 

[Multiple Years]. Washington, DC: Government Printing Office. 

Table 4-15. Inputs for the Pharmaceutical Preparations Industry (SIC 2834/NAICS 32451), 

1987–1996 

Labor

Year

Quantity 

(103

) 

Payroll 

($106) 

Materials 

($106) 

New Capital 

Investment ($106

)

1987 131.6 5,759.2 11,693.7 2,032.7 

1988 133.4 5,447.2 12,634.8 2,234.0 

1989 141.8 6,177.5 12,874.2 2,321.4 

1990 143.8 6,223.9 13,237.6 2,035.3 

1991 129.1 5,275.8 13,546.6 1,864.7 

1992 122.8 4,949.4 13,542.5 2,450.0 

1993 128.2 5,184.2 13,508.7 2,385.2 

1994 134.2 5,368.4 13,526.1 2,531.9 

1995 143.0 5,712.4 15,333.6 2,856.1 

1996 136.9 5,547.3 16,611.1 2,317.0 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures, 

[Multiple Years]. Washington, DC: Government Printing Office. 
4-19 

4.5.1.5 Capacity Utilization 

Table 4-16 presents the trend in these ratios from 1991 to 1996 for both industries. The 

varying capacity ratios reflect adjusting production volumes and new production facilities and 

capacity going both on- and off-line. In 1996, the capacity utilization ratios for SICs 2833 and 

2834 were 84 and 67, respectively. 

Table 4-16. Capacity Utilization Ratios for the Medicinal Chemicals and Botanical 

Products (SIC 2833/NAICS 32451) and Pharmaceutical Preparations 

(SIC 2834/NAICS 32451) Industries, 1991–1996 

1991 1992 1993 1994 1995 1996

SIC 2833/NAICS 32451 84 86 89 80 90 84 

SIC 2834/NAICS 32451 76 74 70 67 63 67 

Note: Capacity utilization ratio is the ratio of the actual production level to the full production level. All values 

are percentages. 

Source: U.S. Department of Commerce, Bureau of the Census. 1998. Survey of Plant Capacity: 1996. Washington, 

DC: Government Printing Office. 

4.5.2 Demand Side of the Industry 

New product introductions and improvements on older medications by the drug industry 

have greatly improved the health and well-being of the U.S. population (Haltmaier, 1998). 

Products help alleviate or reduce physical, mental, and emotional ailments or reduce the severity 

of symptoms associated with disease, age, and degenerative conditions. Dietary supplements, 

such as vitamins and herbal remedies, ensure that consumers receive nutrients of which they may 

not ordinarily consume enough. Products are available in a range of dosage types, such as tablets 

and liquids. 

Although prescription medications are increasingly distributed through third parties, such 

as hospitals and health maintenance organizations, the general population remains the end user of 

pharmaceutical products. As the average age of the U.S. population adjusts to reflect large 

numbers of older people, the variety and number of drugs consumed increases. An older 

population will generally consume more medications to maintain and improve quality of life 

(Haltmaier, 1998). 

4.5.3 Organization of the Industry 

In 1992, 208 companies produced medicinal chemicals and botanical products and 

operated 225 facilities (see Table 4-17). The number of companies and facilities in 1992 was the 

same as that of 1987, although shipment values increased almost 40 percent. The average facility 

employed more people in 1992 than in 1987. In fact, the number of facilities employing 50 or 
4-20 

Table 4-17. Size of Establishments and Value of Shipments for the Medicinal Chemicals 

and Botanical Products (SIC 2833/NAICS 32451) and Pharmaceutical Preparations (SIC 

2834/NAICS 32451) Industries 

1987 1992

Number of Employees in 

Establishment

Number of 

Facilities

Value of 

Shipments 

($106

)

Number of 

Facilities

Value of 

Shipments 

($106)

SIC 2833/NAICS 32451 

1 to 4 employees 61 20.7 62 23.8 

5 to 9 employees 34 38.6 42 58.3 

10 to 19 employees 46 237.0 47 357.1 

20 to 49 employees 47 287.3 29 182.0 

50 to 99 employees 15 273.6 25 653.9 

100 to 249 employees 12 520.6 10 5,163.4 

250 to 499 employees 5 753.0 4 (D) 

500 to 999 employees 4 2478.2 3 (D) 

1,000 to 2,499 employees 1 (D) 3 (D) 

Total 225 4629.1 225 6,438.5 

SIC 2834/NAICS 32451 

1 to 4 employees 158 58.7 152 115.6 

5 to 9 employees 108 178.8 73 105.4 

10 to 19 employees 102 320.3 101 284.6 

20 to 49 employees 117 932.5 110 815.7 

50 to 99 employees 66 1231.0 65 1,966.8 

100 to 249 employees 76 3596.0 77 2,912.4 

250 to 499 employees 50 9239.7 56 11,394.6 

500 to 999 employees 23 4946.9 30 10,077.7 

1,000 to 2,499 employees 24 15,100.9 21 14,525.7 

2,500 employees or more 8 8740.9 6 8,219.4 

Total 732 44,345.7 691 50,417.9 

(D) = undisclosed 

Sources: U.S. Department of Commerce, Bureau of the Census. 1990a. 1987 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

more people grew from 37 to 45. These facilities accounted for the lion’s share of the industry’s 

shipments. According to the Small Business Administration, companies in this SIC code are 

considered small if they employ fewer than 750 employees. It is unclear what percentage of the 

facilities listed in Table 4-17 are small companies. 
4-21 

In 1992, 585 companies manufactured pharmaceutical preparations and operated 691 

facilities. By way of comparison, 640 companies operated 732 facilities in 1987. Although the 

number of facilities declined by 41, no particular category lost or gained an exceptional number 

of facilities. The biggest movement was in the five to nine employees category, which lost 35 

facilities. In both years, facilities with more than 50 employees accounted for at least 95 percent 

of the industry’s shipments. 

Table 4-18 presents the measures of market concentration for both industries. For the 

medicinals and botanicals industry, the CR4 was 76 in 1992, and the CR8 was 84 (U.S. 

Department of Commerce, 1995b). The highly concentrated nature of the market is further 

indicated by an HHI of 2,999 (DOJ, 1992). According to the Department of Justice’s Horizontal 

Merger Guidelines, industries with HHIs above 1,800 are less competitive. 

Table 4-18. Measures of Market Concentration for the Medicinal Chemicals and Botanical 

Products (SIC 2833/NAICS 32451) and Pharmaceutical Preparations (SIC 2834/NAICS 

32451) Industries 

SIC NAICS Industry CR4 CR8 HHI

Number of 

Companies

Number of 

Facilities

2833 32451 Medicinal Chemicals and 

Botanical Products 

76 84 2,999 208 225 

2834 32451 Pharmaceutical 

Preparations 

26 42 341 585 691 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995d. 1992 Concentration Ratios in 

Manufacturing. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Manufactures, Industry 

Series: Drug Industry. Washington, DC: Government Printing Office. 

The pharmaceuticals preparations industry is less concentrated than the medicinal 

chemicals and botanical products industry. For SIC 2834, the CR4 and CR8 were 26 and 42, 

respectively, in 1992. The industry’s HHI was 341, indicating a competitive market. 

4.5.4 Markets and Trends 

According to the Department of Commerce, global growth in the consumption of 

pharmaceuticals is projected to accelerate over the coming decade as populations in developed 

countries age and those in developing nations gain wider access to health care. Currently, the 

United States remains the largest market for drugs, medicinals, and botanicals and produces 

more new products than any other country (Haltmaier, 1998). But, nearly two-fifths of American 

producers’ sales are generated abroad. Top markets for American exports are China, Canada, 
4-22 

Mexico, Australia, and Japan. Most imports originate in Canada, Russia, Mexico, Trinidad and 

Tobago, and Norway. 

4.6 Industrial Organic Chemicals Industry (SIC 2869/NAICS 3251) 

The industrial organic chemicals (not elsewhere classified) industry 

(SIC 2869/NAICS 3251) produces organic chemicals for end-use applications and for inputs into 

numerous other chemical manufacturing industries. In nominal terms, it was the single largest 

segment of the $367 billion chemical and allied products industry (SIC 28) in 1996, accounting 

for approximately 17 percent of the industry’s shipments. 

All organic chemicals are, by definition, carbon-based and are divided into two general 

categories: commodity and specialty. Commodity chemical manufacturers compete on price and 

produce large volumes of staple chemicals using continuous manufacturing processes. Specialty 

chemicals cater to custom markets, using batch processes to produce a diverse range of 

chemicals. Specialty chemicals generally require more technical expertise and research and 

development than the more standardized commodity chemicals industry (EPA, 1995c). 

Consequently, specialty chemical manufacturers have a greater value added to their products. 

End products for all industrial organic chemical producers are as varied as synthetic perfumes, 

flavoring chemicals, glycerin, and plasticizers. 

Table 4-19 presents the shipments of industrial organic chemicals from 1987 to 1996. In 

real terms, the industry’s shipments rose in the late 1980s to a high of $54.9 billion before 

declining in the early 1990s as the U.S. economy went into recession. By the mid-1990s, the 

industry recovered, as product values reached record highs (Haltmaier, 1998). Between 1993 and 

1996, the industry’s shipments grew 7.3 percent to $57.7 billion. 

4.6.1 Supply Side of the Industry 

4.6.1.1 Production Processes 

Processes used to manufacture industrial organic chemicals are as varied as the endproducts themselves. There are thousands of possible ingredients and hundreds of processes. 

Therefore, the discussion that follows is a general description of the ingredients and stages 

involved in a typical manufacturing process. 
4-23 

Table 4-19. Value of Shipments for the Industrial Organic Chemicals, N.E.C. Industry 

(SIC 2869/NAICS 3251), 1987–1996 

Year Value of Shipments (1992 $106)

1987 48,581.7 

1988 53,434.7 

1989 54,962.9 

1990 53,238.8 

1991 51,795.6 

1992 54,254.2 

1993 53,805.2 

1994 57,357.1 

1995 59,484.3 

1996 57,743.3 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995b. 1992 Census of Manufactures, Industry 

Series: Industrial Organic Chemicals. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures, 

Multiple Years. Washington, DC: Government Printing Office. 

Essentially a set of ingredients (feedstocks) is combined in a series of reactions to 

produce end products and intermediates (EPA, 1995c). The typical chemical synthesis processes 

incorporate multiple feedstocks in a series of chemical reactions. Commodity chemicals are 

produced in a continuous reactor, and specialty chemicals are produced in batches. Specialty 

chemicals may undergo a series of reaction steps, as opposed to commodity chemicals’ one 

continuous reaction because a finite amount of ingredients are prepared and used in the 

production process. Reactions usually take place at high temperatures, with one or two additional 

components being intermittently added. As the production advances, by-products are removed 

using separation, distillation, or refrigeration techniques. The final product may undergo a drying 

or pelletizing stage to form a more manageable substance. 

4.6.1.2 Types of Output 

Miscellaneous industrial organic chemicals comprise nine general categories of products: 

 aliphitic and other acyclic organic chemicals (ethylene); acetic, chloroaceptic, adipic, 

formic, oxalic, and tartaric acids and their metallic salts; chloral, formaldehyde, and 

methylamine; 

 solvents (ethyl alcohol etc.); methanol; amyl, butyl, and ethyl acetates; ethers; 

acetone, carbon disulfide and chlorinated solvents; 

 polyhydric alcohols (synthetic glycerin, etc.); 
4-24 

 synthetic perfume and flavoring materials (citral, methyl, oinone, etc.); 

 rubber processing chemicals, both accelerators and antioxidants (cyclic and acyclic); 

 cyclic and acyclic plasticizers (phosphoric acid, etc.); 

 synthetic tanning agents; 

 chemical warfare gases; and 

 esters, amines, etc., of polyhydric alcohols and fatty and other acids. 

4.6.1.3 Major By-Products and Co-Products 

Co-products, by-products, and emissions vary according to the ingredients, processes, 

maintenance practices, and equipment used (EPA, 1997b). Frequently, residuals from the 

reaction process that are separated from the end product are resold or possibly reused in the 

manufacturing process. A by-product from one process may be another’s input. The industry is 

strictly regulated because it emits chemicals through many types of media, including discharges 

to air, land, and water, and because of the volume and composition of these emissions. 

4.6.1.4 Costs of Production 

Of all the factors of production, employment in industrial organic chemicals fluctuated 

most often between 1987 and 1996 (see Table 4-20). During that time, employment fell 8.18 

percent to 92,100, after a high of 101,000 in 1991. Most jobs lost were at the production level 

(Haltmaier, 1998). Facilities became far more computerized, incorporating advanced 

technologies into the production process. Even with the drop in employment, payroll was $200 

million more in 1995 than in 1987. The cost of materials fluctuated between $29 and $36 billion 

for these years, and new capital investment averaged $3,646 million a year. 

4.6.1.5 Capacity Utilization 

Table 4-21 presents the trend in capacity utilization ratios from 1991 to 1996 for the 

industrial organic chemicals industry. The varying capacity utilization ratios reflect changes in 

production volumes and new production facilities and capacities going on- and off-line. The 

capacity utilization ratio for the industry averaged 85.3 over the 6-year period presented. 
4-25 

Table 4-20. Inputs for the Industrial Organic Chemicals Industry (SIC 2869/NAICS 3251), 

1987–1996 

Labor

Year Quantity (103

) Payroll (1992 $106)

Materials 

(1992 $106)

New Capital Investment 

(1992 $106)

1987 100.3 4,295.8 28,147.7 2,307.4 

1988 97.1 4,045.1 29,492.8 2,996.5 

1989 97.9 3,977.4 29,676.4 3,513.0 

1990 100.3 4,144.6 29,579.2 4,085.5 

1991 101.0 4,297.3 29,335.2 4,428.7 

1992 100.1 4,504.2 31,860.6 4,216.6 

1993 97.8 4,540.2 30,920.1 3,386.1 

1994 89.8 4,476.5 33,267.4 2,942.8 

1995 92.1 4,510.4 33,163.9 3,791.0 

1996 100.3 5,144.8 36,068.9 4,794.7 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995b. 1992 Census of Manufactures. Washington, 

DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990–1998. Annual Survey of Manufactures. 

Washington, DC: Government Printing Office. 

Table 4-21. Capacity Utilization Ratios for the Industrial Organic Chemicals Industry (SIC 

2869/NAICS 3251), 1991–1996 

1991 1992 1993 1994 1995 1996

SIC 2869/NAICS 3251 86 81 91 89 84 84 

Note: The capacity utilization ratio is the ratio of the actual production level to the full production level. 

All values are percentages. 

Source: U.S. Department of Commerce, Bureau of the Census. 1998. Survey of Plant Capacity: 1996. Washington, 

DC: Government Printing Office. 

4.6.2 Demand Side of the Industry 

Industrial organic chemicals are components of many chemical products. Most of the 

chemical sectors (classified under SIC 28) are downstream users of organic chemicals. These 

sectors either purchase commodity chemicals or enter into contracts with industrial organic 

chemical producers to obtain specialty chemicals. Consumers include inorganic chemicals (SIC 

281), plastics and synthetics (SIC 282), drugs (283), soaps and cleaners (SIC 284), paints and 

allied products (SIC 286), and miscellaneous chemical products (SIC 289). 

4.6.3 Organization of the Industry 

Although the industry’s value of shipments increased nearly 12 percent between 1987 

and 1992, the number of facilities producing industrial organic chemicals only increased by 6 
4-26 

percent. Facilities with 100 or more employees continued to account for the majority of the 

industry’s shipment values. For example, in 1992, 28 percent of all facilities had 100 or more 

employees (see Table 4-22), and these facilities produced 89 percent of the industry’s shipment 

values. The average number of facilities per firm was 1.4 in both years. According to the Small 

Business Administration, an industrial organic chemicals company is considered small if the 

total number of employees does not exceed 500. It is unclear what percentage of facilities are 

owned by small businesses. 

Table 4-22. Size of Establishments and Value of Shipments for the Industrial Organic 

Chemicals Industry (SIC 2869/NAICS 3251) 

1987 1992

Number of Employees in 

Establishment 

Number of 

Facilities

Value of Shipments 

(1992 $106)

Number of 

Facilities

Value of Shipments 

(1992 $106)

1 to 4 employees 97 552.8 100 102.6 

5 to 9 employees 80 200.9 80 208.7 

10 to 19 employees 91 484.7 97 533.9 

20 to 49 employees 137 1,749.9 125 1,701.5 

50 to 99 employees 99 2556.3 106 3,460.9 

100 to 249 employees 110 10,361.2 111 8,855.9 

250 to 499 employees 41 17,156.9 41 9,971.1 

500 to 999 employees 27 9,615.5 30 13,755.0 

1,000 to 2,499 employees 11 9,184.6 10 9,051.0 

2,500 or more employees 6 7,156.9 5 6,613.5 

Sources: U.S. Department of Commerce, Bureau of the Census. 1995b. 1992 Census of Manufactures, Industry 

Series: Industrial Organic Chemicals. Washington, DC: Government Printing Office. 

U.S. Department of Commerce, Bureau of the Census. 1990b. 1987 Census of Manufactures, Industry 

Series, Paints and Allied Products. Washington, DC: Government Printing Office. 

The industrial organic chemicals (not elsewhere classified) industry is unconcentrated 

and competitive. The CR4 was 29 and the CR8 43; the industry’s HHI was 336. 

4.6.4 Markets and Trends 

The U.S. industrial organic chemical industry is expected to expand through 2002 at an 

annual rate of 1.4 percent (Haltmaier, 1998). U.S. producers face increasing competition 

domestically and abroad as chemical industries in developing nations gain market share and 

increase exports to the United States. American producers will, however, benefit from decreasing 

costs for raw materials and energy and productivity gains. 
4-27 

4.7 Electric Services (SIC 4911/NAICS 22111) 

The ongoing process of deregulation of wholesale and retail electric markets is changing 

the structure of the electric power industry. Deregulation is leading to the functional unbundling 

of generation, transmission, and distribution and to competition in the generation segment of the 

industry. This profile provides background information on the U.S. electric power industry and 

discusses current industry characteristics and trends that will influence the future generation and 

consumption of electricity. It is important to note that through out this report the terms “boilers,” 

“process heaters,” and “units” are synonymous with “ICI boilers” and “process heaters.” Boilers 

primarily engaged in the generation of electricity are not covered by the NESHAP under analysis 

and are therefore excluded from this analysis. Utility sources are not affected by this NESHAP 

except for a small number of nonfossil fuel units within this industry. Those units in this industry 

that are affected may be engaged in activities such as heating and mechanized work. 

4.7.1 Electricity Production 

Figure 4-1 illustrates the typical structure of the electric utility market. Even with the 

technological and regulatory changes in the 1970s and 1980s, at the beginning of the 1990s the 

structure of the electric utility industry could still be characterized in terms of generation, 

transmission, and distribution. Commercial and retail customers were in essence “captive,” and 

rates and service quality were primarily determined by public utility commissions. 

The majority of utilities are interconnected and belong to a regional power pool. Pooling 

arrangements enable facilities to coordinate the economic dispatch of generation facilities and 

manage transmission congestion. In addition, pooling diverse loads can increase load factors and 

decrease costs by sharing reserve capacity. 

4.7.1.1 Generation 

As shown in Table 4-23, coal-fired plants have historically accounted for the bulk of 

electricity generation in the United States. With abundant national coal reserves and advances in 

pollution abatement technology, such as advanced scrubbers for pulverized coal and flue gasdesulfurization systems, coal will likely remain the fuel of choice for most existing generating 

facilities over the near term. 

Natural gas accounts for approximately 10 percent of current generation capacity but is 

expected to grow; advances in natural gas exploration and extraction technologies and new coal 

gasification have contributed to the use of natural gas for power generation. 
4-28 

Large C/I

Customers

Small C/I

Customers

Residential

Customers

Transformer

Generation

Electricity

Distribution

High Voltage Lines

Transmission

Power Plants

Figure 4-1. Traditional Electric Power Industry Structure 

Nuclear plants and renewable energy sources (e.g., hydroelectric, solar, wind) provide 

approximately 20 percent and 10 percent of current generating capacity, respectively. However, 

there are no plans for new nuclear facilities to be constructed, and there is little additional growth 

forecasted in renewable energy. 

4.7.1.2 Transmission 

Transmission refers to high voltage lines used to link generators to substations where 

power is stepped down for local distribution. Transmission systems have been traditionally 

characterized as a collection of independently operated networks or grids interconnected by bulk 

transmission interfaces. 
4-29 

Table 4-23. Net Generation by Energy Source, 1995 

Energy Source

Utility Generators 

(MWh)

Nonutility Generators 

(MWh) Total (MWh)

Fossil fuels 2,021,064 287,696 2,308,760 

Coal 1,652,914 63,440 

Natural gas 307,306 213,437 

Petroleum 60,844 3,957 

Nuclear 673,402 — 673,402 

Hydroelectric 293,653 14,515 308,168 

Renewable/other 6,409 98,295 104,704 

Total 2,994,582 400,505 3,395,033 

Sources: U.S. Department of Energy, Energy Information Administration. 1996. Electric Power Annual, 1995. Vol. 

1. DOE/EIA-0348(95/1). Washington, DC: U.S. Department of Energy. 

U.S. Department of Energy, Energy Information Administration. 1999b. The Changing Structure of the 

Electric Power Industry 1999: Mergers and Other Corporate Combinations. Washington, DC: U.S. 

Department of Energy. 

Within a well-defined service territory, the regulated utility has historically had 

responsibility for all aspects of developing, maintaining, and operating transmissions. These 

responsibilities included 

 system planning and expanding, 

 maintaining power quality and stability, and 

 responding to failures. 

Isolated systems were connected primarily to increase (and lower the cost of) power reliability. 

Most utilities maintained sufficient generating capacity to meet customer needs, and bulk 

transactions were initially used only to support extreme demands or equipment outages. 

4.7.1.3 Distribution 

Low-voltage distribution systems that deliver electricity to customers comprise integrated 

networks of smaller wires and substations that take the higher voltage and step it down to lower 

levels to match customers’ needs. 

The distribution system is the classic example of a natural monopoly because it is not 

practical to have more than one set of lines running through neighborhoods or from the curb to 

the house. 
4-30 

4.7.2 Cost of Production 

Table 4-24 shows total industry expenditures by production activities. Generation 

accounts for approximately 75.6 percent of the cost of delivered electric power in 1996. 

Transmission and distribution accounted for 2.5 percent and 5.6 percent, respectively. Customer 

accounts and sales and administrative costs accounted for the remaining 16.3 percent of the cost 

of delivered power. 

Table 4-24. Total Expenditures in 1996 ($103

) 

Utility 

Ownership Generation Transmission Distribution

Customer 

Accounts and 

Sales

Administration 

and General 

Expenses

Investor-owned 80,891,644 2,216,113 6,124,443 6,204,229 13,820,059 

Publicly owned 12,495,324 840,931 1,017,646 486,195 1,360,111 

Federal 3,685,719 327,443 1,435 55,536 443,809 

Cooperatives 15,105,404 338,625 1,133,984 564,887 1,257,015 

 112,178,091 3,723,112 8,277,508 7,310,847 16,880,994 

 75.6% 2.5% 5.6% 4.9% 11.4% 

 148,370,552 

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1998b. Financial Statistics of 

Major Publicly Owned Electric Utilities, 1997. Washington, DC: U.S. Department of Energy. 

U.S. Department of Energy, Energy Information Administration (EIA). 1997. Financial Statistics of Major 

U.S. Investor-Owned Electric Utilities, 1996. Washington, DC: U.S. Department of Energy. 

4.7.3 Organization of the Industry 

Because the restructuring plans and time tables are made at the state level, the issues of 

asset ownership and control throughout the current supply chain in the electric power industry 

vary from state to state. However, the activities conducted throughout the supply chain are 

generally the same. This section focuses on the generation segment of the market because all the 

boilers affected by the regulation are involved in generation. 

As part of deregulation, the transmission and distribution of electricity are being 

separated from the business of generating electricity, and a new competitive market in electricity 

generation is evolving. As power generators prepare for the competitive market, the share of 

electricity generation attributed to nonutilities and utilities is shifting. 
4-31 

More than 7,000 electricity suppliers currently operate in the U.S. market. As shown in 

Table 4-25, approximately 42 percent of suppliers are utilities and 58 percent are nonutilities. 

Utilities include investor-owned, cooperatives, and municipal systems. Of the approximately 

3,100 utilities operating in the United States, only about 700 generate electric power. The 

majority of utilities distribute electricity that they have purchased from power generators via 

their own distribution systems. 

Table 4-25. Number of Electricity Suppliers in 1999 

Electricity Suppliers Number Percent

Utilities 3,124 42% 

 Investor-owned utilities 222 

 Cooperatives 875 

 Municipal systems 1,885 

 Public power districts 73 

 State projects 55 

 Federal agencies 14 

Nonutilities 4,247 58% 

 Nonutilities (excluding EWGs) 4,103 

 Exempt wholesale generators 144 

Total 7,371 100% 

Source: U.S. Department of Energy, Energy Information Administration (EIA). 1999b. The Changing Structure of 

the Electric Power Industry 1999: Mergers and Other Corporate Combinations. Washington, DC: U.S. 

Department of Energy. 

Utility and nonutility generators produced a total of 3,369 billion kWh in 1995. Although 

utilities generate the vast majority of electricity produced in the United States, nonutility 

generators are quickly eroding utilities’ shares of the market. Nonutility generators include 

private entities that generate power for their own use or to sell to utilities or other end users. 

Between 1985 and 1995, nonutility generation increased from 98 billion kWh (3.8 percent of 

total generation) to 374 billion kWh (11.1 percent). Figure 4-2 illustrates this shift in the share of 

utility and nonutility generation. 

4.7.3.1 Utilities 

There are four categories of utilities: investor-owned utilities (IOUs), publicly owned 

utilities, cooperative utilities, and federal utilities. Of the four, only IOUs always generate 

electricity. 
4-32 

a

 Includes facilities classified in more than one of the following FERC designated categories: cogenerator QF, small 

power producer QF, or exempt wholesale generator. 

Cogen = Cogenerator. 

EWG = Exempt wholesale generator. 

Other Non-QF = Noncogenerator Non-QF. 

QF = Qualifying facility. 

SPP = Small power producer. 

Note: Sum of components may not equal total due to independent rounding. Classes for nonutility generation are 

determined by the class of each generating unit. 

Sources: Utility data: U.S. Department of Energy, Energy Information Administration ( EIA). 1996. Electric Power 

Annual 1995. Volumes I and II. DOE/EIA-0348(95)/1. Washington, DC: U.S. Department of Energy; 

Table 8 (and previous issues); 1985 nonutility data: Shares of generation estimated by EIA; total 

generation from Edison Electric Institute ( EEI). 1998. Statistical Yearbook of the Electric Utility Industry 

1998. November. Washington, DC; 1995 nonutility data: U.S. Department of Energy, Energy Information 

Administration ( EIA). 1996. Electric Power Annual 1995. Volumes I and II. DOE/EIA-0348(95)/1. 

Washington, DC: U.S. Department of Energy. 

Figure 4-2. Utility and Nonutility Generation and Shares by Class, 1988 and 1998 
4-33 

IOUs are increasingly selling off generation assets to nonutilities or converting those 

assets into nonutilities (Haltmaier, 1998). To prepare for the competitive market, IOUs have been 

lowering their operating costs, merging, and diversifying into nonutility businesses. 

In 1995, utilities generated 89 percent of electricity, a decrease from 96 percent in 1985. 

IOUs generate the majority of the electricity produced in the United States. IOUs are either 

individual corporations or a holding company, in which a parent company operates one or more 

utilities integrated with one another. IOUs account for approximately three-quarters of utility 

generation, a percentage that held constant between 1985 and 1995. 

Many states, municipalities, and other government organizations also own and operate 

utilities, although the majority do not generate electricity. Those that do generate electricity 

operate capacity to supply some or all of their customers’ needs. They tend to be small, localized 

outfits and can be found in 47 states. These publicly owned utilities accounted for about onetenth of utility generation in 1985 and 1995. In a deregulated market, these generators may be in 

direct competition with other utilities to service their market. 

Rural electric cooperatives are formed and owned by groups of residents in rural areas to 

supply power to those areas. Cooperatives generally purchase from other utilities the energy that 

they sell to customers, but some generate their own power. Cooperatives only produced 5 percent 

of utility generation in 1985 and only 6 percent in 1995. 

Utilities owned by the federal government accounted for about one-tenth of generation in 

both 1985 and 1995. The federal government operated a small number of large utilities in 1995 

that supplied power to large industrial consumers or federal installations. The Tennessee Valley 

Authority is an example of a federal utility. 

4.7.3.2 Nonutilities 

Nonutilities are private entities that generate power for their own use or to sell to utilities 

or other establishments. Nonutilities are usually operated at mines and manufacturing facilities, 

such as chemical plants and paper mills, or are operated by electric and gas service companies 

(DOE, EIA, 1998a). More than 4,200 nonutilities operate in the United States. 

4.7.4 Demand Side of the Industry 

4.7.4.1 Electricity Consumption 

This section analyzes the growth projections for electricity consumption as well as the 

price elasticity of demand for electricity. Growth in electricity consumption has traditionally 
4-34 

paralleled gross domestic product growth. However, improved energy efficiency of electrical 

equipment, such as high-efficiency motors, has slowed demand growth over the past few 

decades. The magnitude of the relationship has been decreasing over time, from growth of 7 

percent per year in the 1960s down to 1 percent in the 1980s. As a result, determining what the 

future growth will be is difficult, although it is expected to be positive ( DOE, EIA, 1999a). 

Table 4-26 shows consumption by sector of the economy over the past 10 years. The table shows 

that since 1989 electricity sales have increased at least 10 percent in all four sectors. The 

commercial sector has experienced the largest increase, followed by residential consumption. 

Table 4-26. U.S. Electric Utility Retail Sales of Electricity by Sector, 1989 Through 1998 

(106

 kWh) 

Period Residential Commercial Industrial Othera All Sectors

1989 905,525 725,861 925,659 89,765 2,646,809 

1990 924,019 751,027 945,522 91,988 2,712,555 

1991 955,417 765,664 946,583 94,339 2,762,003 

1992 935,939 761,271 972,714 93,442 2,763,365 

1993 994,781 794,573 977,164 94,944 2,861,462 

1994 1,008,482 820,269 1,007,981 97,830 2,934,563 

1995 1,042,501 862,685 1,012,693 95,407 3,013,287 

1996 1,082,491 887,425 1,030,356 97,539 3,097,810 

1997 1,075,767 928,440 1,032,653 102,901 3,139,761 

1998 1,124,004 948,904 1,047,346 99,868 3,220,121 

Percentage change 

1989–1998 

19% 24% 12% 10% 18% 

a

 Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and 

interdepartmental sales. 

Sources: U.S. Department of Energy, Energy Information Administration (EIA). 1999d. Electric Power Annual 

1998. Volumes I and II. Washington, DC: U.S. Department of Energy. 

U.S. Department of Energy, Energy Information Administration (EIA). 1996. Electric Power Annual 1995. 

Volumes I and II. Washington, DC: U.S. Department of Energy. 

In the future, residential demand is expected to be at the forefront of increased electricity 

consumption. Between 1997 and 2020, residential demand is expected to increase at 1.6 percent 

annually. Commercial growth in demand is expected to be approximately 1.4 percent, while 

industry is expected to increase demand by 1.1 percent (DOE, EIA, 1999a). Figure 4-3 shows the 

annual electricity sales by sector from 1970 with projections through 2020. 
4-35 

Figure 4-3. Annual Electricity Sales by Sector 

The literature suggests that electricity consumption is relatively price inelastic. 

Consumers are generally unable or unwilling to forego a large amount of consumption as the 

price increases. Numerous studies have investigated the short-run elasticity of demand for 

electricity. Overall, the studies suggest that, for a 1 percent increase in the price of electricity, 

demand will decrease by 0.15 percent. However, as Table 4-27 shows, elasticities vary greatly, 

depending on the demand characteristics of end users and the price structure. Demand elasticities 

are estimated to range from a –0.05 percent elasticity of demand for a “flat rates” case (i.e., no 

time-of-use assumption) up to a –0.50 percent demand elasticity for a “high consumer response” 

case (DOE, EIA, 1999c). 

4.7.4.2 Trends in the Electricity Market 

Beginning in the latter part of the 19th century and continuing for about 100 years, the 

prevailing view of policymakers and the public was that the government should use its power to 

require or prescribe the economic behavior of “natural monopolies” such as electric utilities. The 

traditional argument is that it does not make economic sense for there to be more than one 

supplier—running two sets of wires from generating facilities to end users is more costly than 

one set. However, since monopoly supply is not generally regarded as likely to provide a socially 

optimal allocation of resources, regulation of rates and other economic variables was seen as a 

necessary feature of the system. 
4-36 

Table 4-27. Key Parameters in the Cases 

Key Assumptions

Case Name

Cost Reduction 

and Efficiency 

Improvements 

Short-Run 

Elasticity of 

Demand (Percent)

Natural Gas 

Prices

Capacity 

Additions

AEO97 Reference Case AEO97 Reference 

Case 

— AEO97 Reference 

Case 

As needed to meet 

demand 

No Competition No change from 

1995 

— AEO97 Reference 

Case 

As needed to meet 

demand 

Flat Rates 

(no time-of-use rates) 

AEO97 Reference 

Case 

–0.05 AEO97 Reference 

Case 

As needed to meet 

demand 

Moderate Consumer 

Response 

AEO97 Reference 

Case 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

High Consumer Response AEO97 Reference 

Case 

–0.50 AEO97 Reference 

Case 

As needed to meet 

demand 

High Efficiency Increased cost 

savings and 

efficiencies 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

No Capacity Additions AEO97 Reference 

Case 

–0.15 AEO97 Low Oil 

and Gas Supply 

Technology Case 

Not allowed 

High Gas Price AEO97 Reference 

Case 

–0.15 AEO97 High Oil 

and Gas Supply 

Technology Case 

As needed to meet 

demand 

Low Gas Price AEO97 Reference 

Case 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

High Value of Reliability AEO97 Reference 

Case 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

Half O&M AEO97 Reference 

Case 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

Intense Competition AEO97 Reference 

Case 

–0.15 AEO97 Reference 

Case 

As needed to meet 

demand 

— = not applicable. 

Source: U.S. Department of Energy, Energy Information Administration (EIA), Office of Integrated Analysis and 

Forecasting. “Competitive Electricity Price Projections.” 

<http://www.eia.doe.gov/oiaf/elepri97/chap3.html>. As obtained on November 15, 1999c. 
4-37 

Beginning in the 1970s, the public policy view shifted against traditional regulatory 

approaches and in favor of deregulation for many important industries including transportation, 

communications, finance, and energy. The major drivers for deregulation of electric power 

included the following: 

 existence of rate differentials across regions offering the promise of benefits from 

more efficient use of existing generation resources if the power can be transmitted 

across larger geographic areas than was typical in the era of industry regulation; 

 the erosion of economies of scale in generation with advances in combustion turbine 

technology; 

 complexity of providing a regulated industry with the incentives to make socially 

efficient investment choices; 

 difficulty of providing a responsive regulatory process that can quickly adjust rates 

and conditions of service in response to changing technological and market 

conditions; and 

 complexity of monitoring utilities’ cost of service and establishing cost-based rates 

for various customer classes that promote economic efficiency while at the same time 

addressing equity concerns of regulatory commissions. 

Viewed from one perspective, not much changes in the electric industry with 

restructuring. The same functions are being performed, essentially the same resources are being 

used, and in a broad sense the same reliability criteria are being met. In other ways, the very 

nature of restructuring, the harnessing of competitive forces to perform a previously regulated 

function, changes almost everything. Each provider and each function become separate 

competitive entities that must be judged on their own. 

This move to market-based provision of generation services is not matched on the 

transmission and distribution side. Network interactions on AC transmission systems have made 

it impossible to have separate transmission paths compete. Hence, transmission and distribution 

remain regulated. Transmission and generation heavily interact, however, and transmission 

congestion can prevent specific generation from getting to market. Transmission expansion 

planning becomes an open process with many interested parties. This open process, coupled with 

frequent public opposition to transmission expansion, slows transmission enhancement. The net 

result is greatly increased pressure on the transmission system. 

Restructuring of the electric power industry could result in any one of several possible 

market structures. In fact, different parts of the country will probably use different structures, as 

the current trend indicates. The eventual structure may be dominated by a power exchange, 

bilateral contracts, or a combination. A strong Regional Transmission Organization (RTO) may 
4-38 

operate in the area, or a vertically integrated utility may continue to operate a control area. In any 

case, several important characteristics will change: 

 Commercial provision of generation-based services (e.g., energy, regulation, load 

following, voltage control, contingency reserves, backup supply) will replace 

regulated service provision. This drastically changes how the service provider is 

assessed. 

 Individual transactions will replace aggregated supply meeting aggregated demand. It 

will be necessary to continuously assess each individual’s performance. 

 Transaction sizes will shrink. Instead of dealing only in hundreds and thousands of 

MW, it will be necessary to accommodate transactions of a few MW and less. 

 Supply flexibility will greatly increase. Instead of services coming from a fixed fleet 

of generators, service provision will change dynamically among many potential 

suppliers as market conditions change. 
5-1 

SECTION 5 

ECONOMIC ANALYSIS METHODOLOGY 

The final rule to control emissions of HAPs from industrial, commercial, and institutional 

boilers and process heaters will affect almost all sectors of the U.S. economy. Several markets 

will bear the direct compliance costs. In addition, sectors that consume energy will also bear 

indirect costs through higher prices for energy. Finally, consumers of goods and services will 

experience impacts from higher market prices. 

This section presents the methodology for analyzing the economic impacts of the 

NESHAP. This economic analysis provides the economic data and supporting information 

needed by EPA to support its regulatory determination. The methodology is based on 

microeconomic theory and the methods developed for earlier EPA studies. These methods are 

tailored to and extended for this analysis, as appropriate, to meet EPA’s requirements for an EIA 

of controls placed on boilers and process heaters. 

This methodology section includes background information on typical economic 

modeling approaches, the conceptual approach selected for this EIA, and an overview of the 

computerized market model used in the analysis with emphasis on the links between energy 

markets and the markets for goods and services. Appendix A includes a description of the 

model’s baseline data set and specification. 

5.1 Background on Economic Modeling Approaches 

In general, the EIA methodology needs to allow EPA to consider the effects of the 

different regulatory alternatives. Several types of economic impact modeling approaches have 

been developed to support regulatory development. These approaches can be viewed as varying 

along two modeling dimensions: 

 the scope of economic decisionmaking accounted for in the model and 

 the scope of interaction between different segments of the economy. 

Each of these dimensions was considered in determining the approach for this study. The 

advantages and disadvantages of different modeling approaches are discussed below. 

5.1.1 Modeling Dimension 1: Scope of Economic Decisionmaking 

Models incorporating different levels of economic decisionmaking can generally be 

categorized as with behavior responses and without behavior responses (accounting approach). 

Table 5-1 provides a brief comparison of the two approaches. The nonbehavioral approach 
5-2 

Table 5-1. Comparison of Modeling Approaches 

EIA With Behavioral Responses 

• Incorporates control costs into production function 

• Includes change in quantity produced 

• Includes change in market price 

• Estimates impacts for 

T affected producers 

T unaffected producers 

T consumers 

T foreign trade 

EIA Without Behavioral Responses 

• Assumes firm absorbs all control costs 

• Typically uses discounted cash flow analysis to evaluate burden of control costs 

• Includes depreciation schedules and corporate tax implications 

• Does not adjust for changes in market price 

• Does not adjust for changes in plant production 

essentially holds fixed all interactions between facility production and market forces. It assumes 

that firms absorb all control costs and consumers do not face any of the costs of regulation. 

Typically, engineering control costs are weighted by the number of affected units to develop 

“engineering” estimates of the total annualized costs. These costs are then compared to company 

or industry sales to determine the regulation’s impact. 

In contrast, the behavioral approach is grounded in economic theory related to producer 

and consumer behavior in response to changes in market conditions. Owners of affected facilities 

are economic agents that can, and presumably will, make adjustments such as changing 

production rates or altering input mixes that will generally affect the market environment in 

which they operate. As producers change their behavior in response to regulation, consumers are 

typically faced with changes in prices that cause them to alter the quantity that they are willing to 

purchase. In essence, this approach models the expected reallocation of society’s resources in 

response to a regulation. The changes in price and production from the market-level impacts are 

used to estimate the distribution of social costs between consumers and producers. 
5-3 

5.1.2 Modeling Dimension 2: Interaction Between Economic Sectors 

Because of the large number of markets potentially affected by the regulation on boilers 

and process heaters, an issue arises concerning the level of sectoral interaction to model. In the 

broadest sense, all markets are directly or indirectly linked in the economy; thus, the regulation 

affects all commodities and markets to some extent. For example, controls on boilers and process 

heaters may indirectly affect almost all markets for goods and services to some extent because 

the cost of fuel (an input in the provision of most goods and services) is likely to increase with 

the regulation in effect. However, the impact of rising fuel prices will differ greatly between 

different markets depending on how important fuel is as an input in that market. 

The appropriate level of market interactions to be included in the EIA is determined by 

the scope of the regulation across industries and the ability of affected firms to pass along the 

regulatory costs in the form of higher prices. Alternative approaches for modeling interactions 

between economic sectors can generally be divided into three groups: 

 Partial equilibrium model: Individual markets are modeled in isolation. The only 

factor affecting the market is the cost of the regulation on facilities in the industry 

being modeled. 

 General equilibrium model: All sectors of the economy are modeled together. General 

equilibrium models operationalize neoclassical microeconomic theory by modeling 

not only the direct effects of control costs, but also potential input substitution effects, 

changes in production levels associated with changes in market prices across all 

sectors, and the associated changes in welfare economywide. A disadvantage of 

general equilibrium modeling is that substantial time and resources are required to 

develop a new model or tailor an existing model for analyzing regulatory alternatives. 

 Multiple-market partial equilibrium model: A subset of related markets are modeled 

together, with intersectoral linkages explicitly specified. To account for the 

relationships and links between different markets without employing a full general 

equilibrium model, analysts can use an integrated partial equilibrium model. The 

multiple-market partial equilibrium approach represents an intermediate step between 

a simple, single-market partial equilibrium approach and a full general equilibrium 

approach. This approach involves identifying and modeling the most significant 

subset of market interactions using an integrated partial equilibrium framework. In 

effect, the modeling technique is to link a series of standard partial equilibrium 

models by specifying the interactions between supply functions and then solving for 

prices and quantities across all markets simultaneously. In instances where separate 

markets are closely related and there are strong interconnections, there are significant 

advantages to estimating market adjustments in different markets simultaneously 

using an integrated market modeling approach. 
5-4 

5.2 Selected Modeling Approach for Boilers and Process Heaters Analysis 

To conduct the analysis for the boilers and process heaters MACT, the Agency used a 

market modeling approach that incorporates behavioral responses in a multiple-market partial 

equilibrium model as described above. This approach allows for a more realistic assessment of 

the distribution of impacts across different groups than the nonbehavioral approach, which may 

be especially important in accurately assessing the impacts of a significant rule affecting 

numerous industries. Because of the size and complexity of this regulation, it is important to use 

a behavioral model to examine the distribution of costs across society. Because the regulations 

on boilers and process heaters primarily affect energy costs, an input into many production 

processes, complex market interactions need to be captured to provide an accurate picture of the 

distribution of regulatory costs. Because of the large number of affected industries under this 

MACT, an appropriate model should include multiple markets and the interactions between 

them. Multiple-market partial equilibrium analysis provides a manageable approach to 

incorporate interactions between energy markets and final product markets into the EIA to 

accurately estimate the regulation’s impact. 

The model used for this analysis includes energy, agriculture, manufacturing, mining, 

commercial, and transportation markets affected by the controls placed on boilers and process 

heaters.6

 The energy markets are divided into natural gas, petroleum products, coal, and 

electricity. The residential sector is treated as a single representative demander in the energy 

markets. 

Figure 5-1 presents an overview of the key market linkages included in the economic 

impact model used for analyzing the boilers and process heaters MACT. The analysis’ emphasis 

is on the energy supply chain and the consumption of energy by producers of goods and services. 

The industries most directly affected by the boilers and process heaters MACT are the electric 

power industry, chemical industry and pulp and paper industry. However, changes in the 

equilibrium prices and quantities of energy and goods and services affect all sectors of the 

economy. (See Figure 5-1.) This analysis explicitly models the linkages between these market 

segments to capture both the direct costs of compliance and the indirect costs due to changes in 

prices. For example, production costs will increase for chemical companies using boilers and 

process heaters as a result of the capital investments and monitoring costs, as well as the 

resulting increase in the price of electricity used as an energy input in the production process. 

 

6

 These markets are defined at the two- and three-digit NAICS code level. This allows for a fairly disaggregated 

examination of the regulation’s impact on producers. However, if the costs of the regulation are concentrated on 

a particular subset of one of these markets, then treating the cost as if it fell on the entire NAICS code may still 

underestimate the impacts on the subset of producers affected by the regulation. 
5-5 

Σdemand

oil

Oil

Supply

Exogenous

Demand

Endogenous

Σdemand

NG

Gas

Σ demandcoal

Coal

Industry A

Btu

Production

Manufacturing

Process

Regulatory

Industry B

Costs

Energy Consumption

Fuel Markets

Σ supply product A

Product A

Supply

Endogenous

Demand

Exogenous

Intermediate or

Final Product Markets

Industry Z

Commercial Businesses

Residential Households

Σdemandelec

Electricity

Electricity Market

Supply

Exogenous

Demand

Endogenous

•••

Figure 5-1. Links Between Energy and Goods and Services Markets 
5-6 

The economic model also captures behavioral changes of producers of goods and services 

that feedback into the energy markets. Changes in production levels and fuel switching in the 

manufacturing process affect the demand for Btus in fuel markets. The change in output is 

determined by the size of the cost increase per Btu (typically variable cost per output), the 

facility’s production function (slope of supply curve), and the demand characteristics of the 

facility’s downstream market (other market suppliers and market demanders). For example, if 

consumers’ demand for a product is not very sensitive to price, then producers can pass the 

majority of the cost of the regulation through to consumers and output may not change 

appreciably. However, if only a small proportion of market output is produced by producers 

affected by the regulation, then competition will prevent the affected producers from raising their 

prices significantly. 

One possible feedback pathway that this analysis does not model is technical changes in 

the manufacturing process. For example, if the cost of Btus increases, a facility may use 

measures to increase manufacturing efficiency or capture waste heat. Facilities could also 

possibly change the input mix that they use, substituting other inputs for fuel. These facility-level 

responses will also act to reduce pollution, but including these responses is beyond the scope of 

this analysis. 

5.2.1 Directly Affected Markets 

Markets where boilers and process heaters are used as an input to production are 

considered to be directly affected. As outlined in Section 2, facilities using several types of 

boilers or process heaters will be required to add controls. In addition, a larger population of 

boilers and process heaters will incur monitoring costs to comply with the regulation. Therefore, 

the regulation will increase their production costs and cause these directly affected firms to 

reduce the quantity that they are willing to supply at any given price. 

5.2.1.1 Electricity Market 

Boilers are used to generate power throughout the electric power industry. Even though 

utility boilers are not covered under this regulation, the Agency estimates over 300 industrial, 

commercial, and institutional boilers involved in providing electric services 

(SIC 4911/NAICS22111) will be affected. Most of these are owned by municipal electric service 

providers. 

For this study, the electricity market was modeled as a nationally competitive market. 

The direct costs of compliance on affected boilers lead to an upward shift in the total market 

supply for electricity. Figure 5-2 illustrates the shifts in the supply curve for a representative 
5-7 

P1

P0

Q11 Q10

(a) Producers bearing control

costs (affected)

S 11

S 10

$

Quantity

$ $

Q Quantity 20 Q21

(b) Producers bearing no control

costs (unaffected)

S 20

Quantity

(c) Total Market

QT1 QT0

D

ST0

S T1

P0 = market price without regulation 

P1 = market price with regulation 

S10 = supply function for affected firms without regulation 

S11 = supply function for affected firms with regulation 

Q10 = quantity sold for affected firms without regulation 

Q11 = quantity sold for affected firms with regulation 

S20 = supply function for unaffected firms both with and without regulation 

Q20 = quantity sold for unaffected firms without regulation 

Q21 = quantity sold for unaffected firms with regulation 

ST0 = total market supply function without regulation 

ST1 = total market supply function with regulation 

QT0 = total market quantity sold without regulation 

QT1 = total market quantity sold with regulation 

Figure 5-2. Market Effects of Regulation-Induced Costs 

energy market. In addition to the direct costs, the market for electricity will also be indirectly 

affected through changes in fuel prices. Electricity generators are extremely large consumers of 

coal, natural gas, and petroleum products. For example, some of the impact of control costs on 

the petroleum industry will be on the electricity industry in the form of higher prices. Indirect 

costs will also lead to an upward shift in the supply curve. 

The demand for electricity is derived by aggregating across the goods and services 

markets and the residential sector. Because of direct compliance costs on the goods and services 

markets, the demand curve for electricity will shift downward. Therefore, it is ambiguous 

whether equilibrium quantity will rise or fall. The changes in the price and quantity are 

determined by the relative magnitude of the shifts in the price elasticities of the supply and 

demand curves. 

5.2.1.2 Petroleum Market 

Control costs associated with boilers and process heaters will increase the cost of refining 

petroleum products. The supply curve for petroleum products will shift upward by the 

proportional increase in total production costs caused by the control costs on boilers and process 
5-8 

heaters. For petroleum products, a single composite product was used to model market 

adjustment because boilers and process heaters are used throughout the refinement process, from 

distillation to reformulation. As a result, assigning costs to specific end products, such as fuel oil 

#2 or reformulated gasoline, is difficult. The use of a composite product tends to understate the 

impacts for petroleum products where compliance costs as a percentage of production costs are 

greater than average and overstate impacts for products where compliance costs as a percentage 

of production costs are less than average. 

5.2.1.3 Goods and Services Markets: Agriculture, Manufacturing, Mining, Commercial, and 

Transportation 

Many manufacturing facilities use boilers and process heaters in their production 

processes to generate steam and process heat. Commercial entities use boilers for space heating 

and to generate supplementary electricity. In addition to the direct costs of the regulation, goods 

and services markets are indirectly affected through price increases in the energy markets. 

Directly affected producers are segmented into sectors defined at the two- or three-digit 

NAICS code level. A partial equilibrium analysis was conducted for each sector to model the 

supply and demand. Changes in production levels and fuel switching due to the regulation’s 

impact on the price of Btus were then linked back into the energy markets. 

The impact of the regulation on producers in these sectors was modeled as an increase in 

the cost of Btus used in the production process. In this context, Btus refer to the generic energy 

requirements used to generate process heat, process steam, or shaft power. Compliance costs 

associated with the regulation will increase the cost of Btu production in the manufacturing 

sectors. The cost of Btu production for industry increases because of both direct control costs on 

boilers and process heaters owned by manufacturers, and increases in the price of fuels. Because 

Btus are an input into the production process, these price increases lead to an upward shift in the 

facility (and industry) supply curves as shown in Figure 5-2, leading to a change in the 

equilibrium market price and quantity. 

The changes in equilibrium supply and demand in each market are modeled to estimate 

the regulation’s impact on each sector. In a perfectly competitive market, the point where supply 

equals demand determines the market price and quantity, so market price and quantity are 

determined by solving the model for the price where the quantity supplied and the quantity 

demanded are equal. The size of the regulation-induced shifts in the supply curve is a function of 

the total direct control costs associated with boilers and process heaters and the indirect fuel 

costs (determined by the change in fuel price and intensity of use) in each goods and services 
5-9 

market. The proportional shift in the supply curve is determined by the ratio of total control costs 

(both direct and indirect) to total revenue. 

This impact on the price of Btus facing industrial users feeds back to the fuel market in 

two ways (see Figure 5-3). The first is through the company’s input decision concerning the 

fuel(s) that will be used for its manufacturing process. As the cost of Btus increases, firms may 

switch fuels and/or change production processes to increase energy efficiency and reduce the 

number of Btus required per unit of output. Fuel switching impacts were modeled using crossprice elasticities of demand between energy sources. For example, a cross-price elasticity of 

demand between natural gas and electricity of 0.5 implies that a 1 percent increase in the price of 

electricity will lead to a 0.5 percent increase in the demand for natural gas. Own-price elasticities 

of demand are used to estimate the change in the use of fuel by demanders. For example, a 

demand elasticity of –0.175 for electricity implies that a 1 percent increase in the price of 

electricity will lead to a 0.175 percent decrease in the quantity of electricity demanded. 

Btu

Production

Decision

Output

Market

Δ Fuel Use

Δ Output

Δ $/Btu

Production

$/Btu Decision

Δ $/Btu

Fuel

Markets

Compliance

Costs

Figure 5-3. Fuel Market Interactions with Facility-Level Production Decisions 

The second feedback pathway to the energy markets is through the facility’s change in 

output. Because Btus are an input into the production process, energy price increases lead to an 

upward shift in the facility supply curves (not modeled individually). This leads to an upward 

shift in the industry supply curve when the shifts at the facility level are aggregated across 

facilities. A shift in the industry supply curve leads to a change in the equilibrium market price 

and quantity. In a perfectly competitive market, the point where supply equals demand 

determines the new market price and quantity. The Agency modeled the feedback into the energy 

market by assuming that the percentage change in output in the manufacturing sectors translates 

into a equivalent percentage change in the demand for energy (Btus). This implies that there are 
5-10 

constant returns to scale from energy inputs in the manufacturing process over the relevant range 

of output and time period of analysis. This is an appropriate assumption for this analysis because 

the output changes in these sectors being modeled are relatively small (always less than 1 

percent) and reflect short-run production decisions.7

The Agency assumed that the demand curves for goods and services in all sectors are 

unchanged by the regulation. However, because the demand function quantifies the change in 

quantity demanded in response to a change in price, the baseline demand conditions are 

important in determining the regulation’s impact. The key demand parameters are the elasticities 

of demand with respect to changes in the price of goods and services. For these markets, a 

“reasonable” range of elasticity values is assigned based on estimates from similar commodities. 

Because price changes are anticipated to be small, the point elasticities at the original price and 

quantity should be applicable throughout the relevant range of prices and quantities examined in 

this model. 

5.2.2 Indirectly Affected Markets 

In addition to the many markets that are directly affected by the regulation on boilers and 

process heaters, some markets feel the regulation’s impacts despite having no direct costs 

resulting from the regulation. Firms in these markets generally face changes in the price of 

energy that affect their production decisions. 

5.2.2.1 Market for Coal 

The coal market is not directly affected by the regulation, but it has the potential to be 

significantly affected through indirect costs. Although boilers and process heaters are not 

commonly used in the production or transportation of coal, the supply of coal will be affected by 

the price of energy used in coal production. However, the indirect impacts on coal production 

costs are relatively small compared to the direct impacts on the production costs in the electricity 

and petroleum markets; thus, the “relative” price of coal (per Btu) will decrease compared with 

other energy sources. 

The demand for coal from the industrial sectors will be affected by differences in 

compliance costs by fuel type applied to boilers and process heaters in the industrial sectors. 

Because compliance costs are high for coal-fired units, manufacturers will switch away from 

coal units toward natural gas units with lower compliance costs. However, the overall impact on 

the demand for coal is ambiguous because the relative increase in the cost of producing Btus by 

 

7

 Long-run production decisions of fuel switching and increased energy efficiency are captured by the cross- and 

own-price elasticities in the energy markets. 
5-11 

burning coal will be offset by the relative decrease in the price of coal. Similarly, the demand for 

coal by utility generators will be affected through changes in the relative price of alternative 

(noncoal) energy sources and direct costs on coal boilers. 

5.2.2.2 Natural Gas Market 

The natural gas market is included in the economic model to complete coverage of the 

energy markets. EPA projects that there are no direct and minimal indirect impacts on the 

production costs of natural gas. However, the demand for natural gas will increase because of the 

relative decrease in the price of natural gas and the lower relative compliance costs for gas-fired 

boilers and process heaters. 

5.2.2.3 Goods and Services Markets 

Some goods and services markets do not include any boilers or process heaters and are 

therefore not directly affected by the regulation. However, these markets will still be affected 

indirectly because of the changes in energy prices that they will face following the regulation. 

There will be a tendency for these users to shift away from electricity and petroleum products 

and towards natural gas and coal. 

5.2.2.4 Impact on Residential Sector 

The residential sector does not bear any direct costs associated with the regulation 

because this sector does not own boilers or process heaters. However, they bear indirect costs 

due to price increases. The residential sector is a significant consumer of electricity, natural gas, 

and petroleum products used for heating, cooling, and lighting, as well as many other end uses. 

The change in the quantity of energy demanded by these consumers in response to changes in 

energy prices is modeled as a single demand curve parameterized by demand elasticities for 

residential consumers obtained from the literature. 

5.3 Operationalizing the Economic Impact Model 

Figure 5-4 illustrates the linkages used to operationalize the estimation of economic 

impacts associated with the compliance costs. Compliance costs placed on boilers and process 

heaters shift the supply curve for electricity and petroleum products. Adjustments in the 

electricity and petroleum energy markets determine the share of the cost increases that producers 

(electric service providers and petroleum companies) and consumers (product manufacturers, 

commercial business, and residential households) bear. 
5-12 

Σdemandelec

Electricity

Electricity Market

Σdemand

oil

Oil

Assume

Supply

Model

Demand

Σdemand

NG

Gas

Σdemandcoal

Coal

Industry A

Btu

Production

Manufacturing

Process

Industry B

Industry Z

Regulatory Costs

(Δ Fuel Prices)

⇒

P

Δ

Q

Q

Energy Consumption Final Product Markets Fuel Markets

Fuel PricesFuel PricesFuel PricesFuel Prices

Δ Production Process

(Fuel Switching)

Δ Production Levels

Product Supply

Product Price

P = market price of final

output

Q = quantity sold of final

output

•••

Commercial Businesses

Residential Households

Fuel Prices

Regulatory Costs

Figure 5-4. Operationalizing the Estimation of Economic Impact 
5-13 

The supply and demand relationships between the energy markets are fully modeled. For 

example, changes in electricity production feed back and affect the demand for coal, natural gas 

and petroleum products. Similar changes in refinery production affect the petroleum industry’s 

demand for electricity. 

Manufacturers experience supply curve shifts due to control costs on affected boilers and 

process heaters they operate and changes in prices for natural gas, petroleum, electricity, and 

coal. The share of these costs borne by producers and consumers is determined by the new 

equilibrium price and quantity in the goods and services markets. Changes in manufacturers’ Btu 

demands due to fuel switching and changes in production levels feed back into the energy 

markets. 

Adjustments in price and quantity in all markets occur simultaneously. A computer 

model was used to numerically simulate market adjustments by iterating over commodity prices 

until equilibrium is reached (i.e., until the quantity supplied equals the quantity demanded in all 

markets being modeled). Using the results provided by the model, economic impacts of the 

regulation (changes in consumer and producer surplus) were estimated for all sectors of the 

economy being modeled. 

5.3.1 Computer Model 

The computer model comprises a series of computer spreadsheet modules. The modules 

integrate the engineering cost inputs and the market-level adjustment parameters to estimate the 

regulation’s impact on the price and quantity in each market being analyzed. At the heart of the 

model is a market-clearing algorithm that compares the total quantity supplied to the total 

quantity demanded for each market commodity. 

Current prices and production levels are used to calibrate the baseline scenario (without 

regulation) for the model. Then, the compliance costs associated with the regulation are 

introduced as a “shock” to the system, and the supply and demand for market commodities are 

allowed to adjust to account for the increased production costs resulting from the regulation. 

Using an iterative process, if the supply does not equal demand in all markets, a new set of prices 

is “called out” and sent back to producers and consumers to “ask” what quantities they would 

supply and demand based on these new prices. This technique is referred to as an auctioneer 

approach because new prices are continually called out until an equilibrium set of prices is 

determined (i.e., where supply equals demand for all markets). 
5-14 

Supply and demand quantities are computed at each price iteration. The market supply 

for each market is obtained by using a mathematical specification of the supply function, and the 

key parameter is the point elasticity of supply at the baseline condition. Table 5-2 lists the supply 

elasticities for the markets used in the model. 

Table 5-2. Supply and Demand Elasticities 

Demand Elasticities

Supply Elasticities Industrial Residentiala Transportation Commercial

Petroleum 0.58b Derived –0.28 Derived Derived 

Natural Gas 0.41b Derived –0.26 Derived Derived 

Electricity 0.75c Derived –0.23 Derived Derived 

Coal 1.00b Derived –0.26 Derived Derived 

NAICS Description Supplyd Demandd

311 Food 0.75c –0.30 

312 Beverage and Tobacco Products 0.75c –1.30 

313 Textile Mills 0.37e

 –0.85e

314 Textile Product Mills 0.37e –0.85e

315 Apparel 0.75c

 –1.80 

316 Leather and Allied Products 0.75c

 –1.20 

321 Wood Products 0.75d –0.20 

322 Paper 1.20c

 –1.09 

323 Printing and Related Support 0.75c

 –1.80 

325 Chemicals 0.75c –1.50 

326 Plastics and Rubber Products 0.75c

 –1.80 

327 Nonmetallic Mineral Products 0.75c

 –0.90 

331 Primary Metals 3.50f –0.80 

332 Fabricated Metal Products 0.75c

 –0.20 

333 Machinery 0.75c –0.50 

334 Computer and Electronic Products 0.75c

 –0.30 

335 Electrical Equipment, Appliances, and Components 0.75c

 –0.50 

336 Transportation Equipment 0.75c

 –1.00c

337 Furniture and Related Products 0.75c

 –3.40 

339 Miscellaneous 0.75c

 –0.60 

11 Agricultural Sector 0.75c

 –1.80 

23 Construction Sector 0.75c

 –1.00c

(continued) 
5-15 

Table 5-2. Supply and Demand Elasticities (continued) 

NAICS Description Supplyd Demandd

 

21 Other Mining Sector 0.43 –0.30 

48 Transportation 0.75c

 –0.70 

Commercial Commercial 0.75c –1.00c

a

 U.S. Department of Energy, Energy Information Administration (EIA). “Issues in Midterm Analysis and 

Forecasting 1999—Table 1.” <http://www.eia.doe.gov/oaif/issues/pricetbl1.html>. As obtained on May 8, 2000a. 

b

 Dahl, Carol A., and Thomas E. Duggan. 1996. “U.S. Energy Product Supply Elasticities: A Survey and 

Application to the U.S. Oil Market.” Resource and Energy Economics18:243-263. c

 Assumed value. 

d

 E.H. Pechan & Associates, Inc. 1997. Qualitative Market Impact Analysis for Implementation of the Selected 

Ozone and PM NAAQS. Appendix B. Prepared for the U.S. Environmental Protection Agency. 

e

 Warfield, et al. 2001. “Multifiber Arrangement Phaseout: Implications for the U.S. Fibers/Textiles/Fabricated 

Products Complex.” www.fibronet.com.tw/mirron/ncs/9312/mar.html> As obtained September 19, 2001. 

f

 U.S. International Trade Commission (USITC). November 21, 2001. Memorandum to the Commission from 

Craig Thomsen, John Giamalua, John Benedetto, Joshua Levy, International Economists. Investigation No. TA201-73: STEEL-Remedy Memorandum. 

The demand curves for the energy markets are the sum of demand responses across all 

markets. The demand for energy in the manufacturing sectors is a derived demand calculated 

using baseline energy usage and changes associated with fuel switching and changes in output 

levels. Similarly, the energy demand in residential sectors is obtained through mathematical 

specification of a demand function (see Appendix A). 

The demand for goods and service in the two- and three-digit NAICS code manufacturing 

sectors is obtained by using a mathematical specification of the demand function. Table 5-2 lists 

the demand elasticities for the markets used in the model. 

EPA modeled fuel switching using secondary data developed by the U.S. Department of 

Energy for the National Energy Modeling System (NEMS). Table 5-3 contains fuel price 

elasticities of demand for electricity, natural gas, petroleum products, and coal. The diagonal 

elements in the table represent own-price elasticities. For example, the table indicates that for 

steam coal, a 1 percent change in the price of coal will lead to a 0.499 percent decrease in the use 

of coal. The off diagonal elements are cross-price elasticities and indicate fuel switching 

propensities. For example, for steam coal, the second column indicates that a 1 percent increase 

in the price of coal will lead to a 0.061 percent increase in the use of natural gas. 
5-16 

Table 5-3. Fuel Price Elasticities 

Own and Cross Elasticities

Inputs Electricity Natural Gas Coal Residual Distillate

Electricity –0.074 0.092 0.605 0.080 0.017 

Natural Gas 0.496 –0.229 1.087 0.346 0.014 

Steam Coal 0.021 0.061 –0.499 0.151 0.023 

Residual 0.236 0.036 0.650 –0.587 0.012 

Distillate 0.247 0.002 0.578 0.044 –0.055 

Source: U.S. Department of Energy, Energy Information Administration (EIA). January 2000b. Model 

Documentation Report: Industrial Sector Demand Module of the National Energy Modeling System. 

DOE/EIA-M064(2000). Washington, DC: U.S. Department of Energy.

5.3.2 Calculating Changes in Social Welfare 

The boilers and process heaters MACT will impact almost every sector of the economy, 

either directly through control costs or indirectly through changes in the price of energy and final 

products. For example, a share of control costs that originate in the energy markets is passed 

through the goods and services markets and borne by both the producers and consumers of their 

products. To estimate the total change in social welfare without double-counting impacts across 

the linked partial equilibrium markets being modeled, EPA quantified social welfare changes for 

the following categories: 

 change in producer surplus in the energy markets; 

 change in producer surplus in the goods and services markets; 

 change in consumer surplus in the goods and services markets; and 

 change in consumer surplus in the residential sector. 

Figure 5-5 illustrates the change in producer and consumer surplus in the intermediate energy 

market and the goods and services markets. For example, assume a simple world with only one 

energy market, wholesale electricity, and one product market, pulp and paper. If the regulation 

increases the cost of generating wholesale electricity, then part of the cost of the regulation will 

be borne by the electricity producers as decreased producer surplus, and part of the costs will be 

passed on to the pulp and paper manufacturers. In Figure 5-5(a), the pulp and paper 

manufacturers are the consumers of electricity, so the change in consumer surplus is displayed. 

This change in consumer surplus in the energy market is captured by the product market 

(because the consumer is the pulp and paper industry in this case), where it is split between 

consumer surplus and producer surplus in those markets. Figure 5-5(b) shows the change in 

producer surplus in the energy market, where B represents an increase in producer surplus and C 

represents a decrease. 
5-17 

S

D

S′

D

(a) Change in Consumer Surplus

in the Energy Market

(c) Change in Consumer Surplus

in Final Product Markets

(b) Change in Producer Surplus in

the Energy Market

(d) Change in Producer Surplus in

Final Product Markets

P

P2

Q

P1

Q2 Q1

S

D

S′

P

PB

Q

PA

QB QA

S

D

P S′

PB

Q

PA

QB QA

P

P2

Q

P1

Q2 Q1

S

D

S′

A B

C

E

F

Figure 5-5. Changes in Economic Welfare with Regulation 

As shown in Figures 5-5(c) and 5-5(d), the cost affects the pulp and paper industry by 

shifting up the supply curve in the pulp and paper market. These higher electricity prices 

therefore lead to costs in the pulp and paper industry that are distributed between producers and 

consumers of paper products in the form of lower producer surplus and lower consumer surplus. 

Note that the change in consumer surplus in the intermediate energy market must equal the total 

change in consumer and producer surplus in the product market. Thus, to avoid double-counting, 

the change in consumer surplus in the intermediate energy market was not quantified; instead the 

total change in social welfare was calculated as 

 Change in Social Welfare = 3ΔPSE + 3ΔPSF + 3ΔCSF + 3ΔCSR (5.1) 
5-18 

where 

ΔPSE = change in producer surplus in the energy markets; 

ΔPSF = change in producer surplus in the goods and services markets; 

ΔCSF = change in consumer surplus in the goods and services markets; and 

ΔCSR = change in consumer surplus in the commercial, residential, and transportation 

energy markets. 

Appendix A contains the mathematical algorithms used to calculate the change in producer and 

consumer surplus in the appropriate markets. The market analysis is conducted for the year 2005 

and incorporates both growth in supply and demand. As a result, both new and existing sources 

are evaluated using the same analysis approach. 

The engineering control costs presented in Section 3.3 are inputs (regulatory “shocks”) in 

the market model approach. The magnitude and distribution of the regulatory costs’ impact on 

the economy depend on the relative size of the impact on individual markets (relative shift of the 

market supply curves) and the behavioral responses of producers and consumers in each market 

(measured by the price elasticities of supply and demand). 
6-1 

SECTION 6 

ECONOMIC IMPACT ANALYSIS RESULTS 

The underlying objective of the EIA is to evaluate the effect of the regulation on the 

welfare of affected stakeholders and society in general. Although the engineering cost analysis 

presented in Section 3 does represent an estimate of the resources required to comply with the 

rule under baseline economic conditions, the analysis does not account for the fact that the 

regulations may cause the economic conditions to change. For instance, producers may reduce 

production in the face of higher production costs, thereby reducing market supply. Moreover, the 

control costs may be passed along to other parties through various economic exchanges. 

Therefore, EPA developed an analytical structure and economic model to measure and track 

these effects (described in detail in Section 5 and Appendix A). In this section, we report 

quantitative estimates of these welfare impacts and their distribution across stakeholders. 

Note that EPA requested RTI to update model unit costs, which had the effect of 

lowering the economic impacts presented in this section. The revised scenario is presented in 

Appendix D of this report. 

6.1 Social Cost Estimates 

Under the final rule, EPA estimates the total change in social welfare is $862.9 million 

(see Table 6-1). This estimate is slightly smaller (less than $0.3 million) than the estimated 

baseline engineering costs as a result of behavior changes by producers and consumers. Possible 

behavior responses include changes in consumption and production patterns and fuel switching. 

Table 6-1. Social Cost Estimates ($1998 106

): Final Rule 

Change in Social Welfare

Baseline engineering costs $863.0 

Social costs with market adjustments $862.9 

Difference between engineering and social costs $0.1 

EPA also estimated the distribution of social costs between producers and consumers and 

report the distribution of impacts across sectors/markets in Table 6-2. The market analysis 

estimates that consumers will bear $414.3 million, or 48 percent of the total social cost as a result 

of higher prices and lower consumption levels. Producer surplus is projected to decrease by 

$448.7 million, or 52 percent of the total social cost as result of direct control costs, higher 

energy costs, and reductions in output. 
6-2 

Table 6-2. Distribution of Social Costs by Sector/Market: Final Rule ($1998 106

) 

 Change in:

Sectors/Markets 

Producer 

Surplus

Consumer 

Surplus

Social 

Welfare

Energy Markets 

Petroleum –$1.9 

Natural gas $4.1 

Electricity –$33.7 

Coal –$2.7 

Subtotal –$34.2 

NAICS Code SIC Code Description 

311 20 (pt) Food –$28.2 –$11.3 –$39.4 

312 20 (pt); 21 Beverage and Tobacco Products –$2.4 –$4.1 –$6.5 

313 22 (pt) Textile Mills –$22.7 –$52.0 –$74.7 

314 22 (pt) Textile Product Mills –$0.1 –$0.1 –$0.2 

315 23 Apparel –$0.4 –$1.1 –$1.5 

316 31 Leather and Allied Products –$0.3 –$0.4 –$0.7 

321 24 Wood Products –$39.1 –$10.4 –$49.5 

322 26 Paper –$66.1 –$60.0 –$126.1 

323 27 Printing and Related Support –$0.2 –$0.4 –$0.6 

325 28 Chemicals –$40.9 –$81.8 –$122.8 

326 30 Plastics and Rubber Products –$2.2 –$5.4 –$7.6 

327 32 Nonmetallic Mineral Products –$3.4 –$4.0 –$7.4 

331 33 Primary Metals –$25.2 –$5.7 –$30.9 

332 34 Fabricated Metal Products –$8.5 –$2.3 –$10.8 

333 35 Machinery –$7.3 –$4.9 –$12.2 

334 36 (pt) Computer and Electronic Products –$3.6 –$1.4 –$5.0 

335 36 (pt) Electrical Equipment, Appliances, 

and Components 

–$2.5 –$1.6 –$4.1 

336 37 Transportation Equipment –$24.6 –$32.8 –$57.3 

337 25 Furniture and Related Products –$5.4 –$24.6 –$30.1 

339 39 Miscellaneous –$0.8 –$0.7 –$1.5 

11 01-08 Agricultural Sector –$0.6 –$1.3 –$1.9 

23 15-17 Construction Sector –$0.8 –$1.1 –$1.9 

21 10; 14 Other Mining Sector –$10.1 –$7.0 –$17.2 

48 40-47 (pt) Transportation –$4.7 –$4.3 –$9.0 

42; 44-45; 49; 51-56; 

61-62; 71-72; 81 

40-48 (pt); 

50-99 

Commercial –$71.6 –$95.5 –$167.1 

 Residential NA –$42.7 –$42.7 

Grand Total –$414.3 –$448.7 –$862.9 

NA = Not applicable. 

pt = Part. 
6-3 

With exception of the natural gas market, energy producers are expected to experience 

producer surplus losses. Under the final rule, electricity, petroleum, and coal producer surplus is 

projected to decline by approximately $35 million. In contrast, natural gas producer surplus is 

projected to increase by $4 million as they benefit from increased demand from industries 

switching from petroleum and electricity. 

The majority welfare impacts fall on the agriculture, manufacturing, and mining 

industries. EPA estimates total welfare losses of $609.8 million for these sectors. Manufacturing 

industries with large number of boilers and process heaters and industries that consume 

electricity experience the majority these losses (e.g., chemicals and allied products, paper, textile 

mill products, and food). Consumers in these industries experience losses of $295.2 million and 

producers bear $314.6 million. The cost of this rule to producers as a percentage of baseline 2005 

shipments is less than 0.5 percent. 

EPA also examined the impact on the commercial, transportation and residential sectors. 

The total welfare loss for the commercial sector is estimated to be $167.1 million. Therefore, the 

regulatory burden associated with the MACT is estimated as 0.001 percent of total 2005 

commercial sector revenues. Consumers in this sector bear approximately $71.6 million and 

producers bear $95.5 million of these impacts. In contrast, the total welfare loss for the 

transportation sector is estimated to be $9.0 million. The regulatory burden associated with the 

rule is estimated as 0.003 percent of total 2005 transportation sector revenues. Transportation 

consumers bear approximately $4.7 million and producers bear $4.3 million of these impacts. 

Finally, the social cost burden to residential consumers of energy, $42.7 million, is 0.037 percent 

of annual residential energy expenditures in 2005. 

6.2 National Market-Level Impacts 

Increases in the costs of production in the energy and final product markets due to the 

regulation are expected to result in changes in prices, production, and consumption from baseline 

levels. As shown in Table 6-3, the electricity market price increases by 0.050 percent, while 

production/consumption decreases by 0.011 percent as a result of additional control costs. A 

significant share of electricity is produced in the United States using coal as a primary input. 

Therefore, projected reductions in electricity production also lead to a decrease in demand for 

coal. As a result, the price and quantities of coal are projected to fall by 0.007 percent and 0.010 

percent, respectively. In the petroleum market, the model projects small price and quantity 

effects (i.e., less than 0.01 percent). In the natural gas market, the model projects the market 

price will rise in response to increased demand (0.005 percent). The price increase is the result of 

additional control costs and increased demand. Production and consumption quantities also 

increase in this market (0.002) as a result of increased demand. 
6-4 

Table 6-3. Market-Level Impacts: Final Rule 

 Percent Change

Sectors/Markets Price Quantity

Energy Markets 

Petroleum 0.002% 0.000% 

Natural gas 0.005% 0.002% 

Electricity 0.050% –0.011% 

Coal –0.007% –0.010% 

NAICS Code SIC Code Description 

311 20 (pt) Food 0.006% –0.002% 

312 20 (pt); 21 Beverage and Tobacco Products 0.003% –0.004% 

313 22 (pt) Textile Mills 0.025% –0.021% 

314 22 (pt) Textile Product Mills 0.000% 0.000% 

315 23 Apparel 0.000% –0.001% 

316 31 Leather and Allied Products 0.002% –0.003% 

321 24 Wood Products 0.041% –0.008% 

322 26 Paper 0.026% –0.028% 

323 27 Printing and Related Support 0.000% 0.000% 

325 28 Chemicals 0.009% –0.013% 

326 30 Plastics and Rubber Products 0.001% –0.002% 

327 32 Nonmetallic Mineral Products 0.003% –0.003% 

331 33 Primary Metals 0.011% –0.009% 

332 34 Fabricated Metal Products 0.003% –0.001% 

333 35 Machinery 0.002% –0.001% 

334 36 (pt) Computer and Electronic Products 0.001% 0.000% 

335 36 (pt) Electrical Equipment, Appliances, and 

Components 

0.002% –0.001% 

336 37 Transportation Equipment 0.004% –0.004% 

337 25 Furniture and Related Products 0.008% –0.026% 

339 39 Miscellaneous 0.001% 0.000% 

11 01-08 Agricultural Sector 0.000% 0.000% 

23 15-17 Construction Sector 0.000% 0.000% 

21 10; 14 Other Mining Sector 0.012% –0.004% 

48 40-47 (pt) Transportation 0.001% –0.001% 

42; 44-45; 49; 51-56; 61-

62; 71-72; 81 

40-48 (pt); 50-99 Commercial 0.000% 0.000% 

pt = Part. 
6-5 

Additional control costs and higher energy costs associated with the regulation lead to 

higher goods and services prices in all markets and a decline in output. However, the changes are 

generally very small. Under the MACT Floor, three markets have price increases greater than or 

equal to 0.02 percent—Wood Products (NAICS 321), Paper (NAICS 322), and Textile Mills 

(NAICS 313). The producers in these sectors are expected to face higher per-unit control costs 

relative to other industries. In addition, these industries are also electricity-intensive; therefore, 

costs of production also increase as a result of higher electricity prices. 

Although the impacts on price and quantity in the goods and services markets are 

estimated to be small, one possible effect of modeling market impacts at the two and three digit 

NAICS code level is that fuel-intensive industries within the larger NAICS code definition may 

be affected more significantly than the average industry for that NAICS code. Thus, the changes 

in price and quantity should be interpreted as an average for the whole NAICS code, not 

necessarily for each disaggregated industry within that NAICS code. 

6.3 Executive Order 13211 (Energy Effects) 

Executive Order 13211, “Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use” (66 Fed. Reg. 28355 [May 22, 2001]), requires EPA to 

prepare and submit a Statement of Energy Effects to the Administrator of the Office of 

Information and Regulatory Affairs, Office of Management and Budget, for certain actions 

identified as “significant energy actions.” Section 4(b) of Executive Order 13211 defines 

“significant energy actions” as “any action by an agency (normally published in the Federal 

Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, 

including notices of inquiry, advance notices of rulemaking, and notices of rulemaking: 

 that is a significant regulatory action under Executive Order 12866 or any successor 

order, and is likely to have a significant adverse effect on the supply, distribution, or 

use of energy; or 

 that is designated by the Administrator of the Office of Information and Regulatory 

Affairs as a significant energy action.” 

EPA has provided additional information on the impacts of the final rule on affected 

energy markets below.8

 

8

 Conversion factors for heat rates were obtained from AEO 2002, Appendix H. These factors vary by year to year; 

2010 values are reported in this Appendix. 
6-6 

Energy Price Effects. As described in the market-level results section, electricity prices 

are projected to increase by less than 1 percent. Petroleum and natural gas prices are all projected 

to increase by less than 0.1 percent. The price of coal is projected to decrease slightly. 

Impacts on Electricity Supply, Distribution, and Use. We project the increased 

compliance costs for the electricity market will result in an annual production decline of 

approximately 415 million kWh under the MACT floor. 

Impacts on Petroleum, Natural Gas, and Coal Supply, Distribution, and Use. The model 

projects decreases in petroleum production/consumption of approximately 68 barrels per day 

under the MACT floor. In contrast, natural gas production/consumption is projected to increase 

by 1.1 million cubic feet per day under the MACT floor. This is the result of fuel switching in 

response to relative price changes. Finally, the model also projects less than a 1,000 tons per day 

decrease in coal production/consumption in response to reduced output from the electricity sector 

(a significant consumer of coal). 

6.4 Conclusions 

The decrease in social surplus estimated using the market analysis is $862.9 million. This 

estimate is slightly smaller than the estimated baseline engineering costs because the market 

model accounts for behavioral changes of producers and consumers. Although the rule affects 

boilers and process heaters used in energy industries, energy producers only incur less than 6 

percent of the total social cost of the regulation. This burden is spread across numerous markets 

because the price of energy increases slightly as a result of the regulation, which increases the 

cost of production for all markets that use energy as part of their production process. 

The remaining share of the social cost is mostly borne by the manufacturing sectors 

which operate the majority of the boilers and process heaters affected by the regulation. 

Manufacturing industries bearing the largest social costs include percent—Wood Products 

(NAICS 321), Paper (NAICS 322), and Textile Mills (NAICS 313). However, the market model 

predicts that changes in these industries’ price and quantity do not exceed 0.02 percent. 

Because of the minimal changes in price and quantity estimated for most of the affected 

markets, EPA expects that there would be no discernable impact on international trade. Although 

an increase in the price of U.S. products relative to those of foreign producers is expected to 

decrease exports and increase imports, the changes in price due to the industrial boilers and 

process heaters MACT are generally too small to significantly influence trade patterns. There 

may also be a small decrease in employment, but because the impact of the regulation is spread 

across so many industries and the decreases in market quantities are so small, it is unlikely that 

any particular industry will face a significant decrease in employment. 
7-1 

SECTION 7 

SMALL ENTITY IMPACTS 

This section investigates the potential impact the regulation will have on small entities. 

The Agency has identified 187 small entities that will be affected by the final rule for the ICI 

boilers and process heaters NESHAP. For these entities, the average cost-to-sales ratio (CSR) is 

0.52 percent and the average annual control cost is $149,000. Eight entities will incur annual 

costs that are greater than or equal to 3 percent of their annual sales (see Table 7-1). 

Table 7-1. Summary of Small Entity Impacts 

February 2004 

Report Final Rule

Number of small entities 185 187 

Total number of entities 576 576 

Average annual control cost per small entity (103

) $199 $149 

Average control cost/sales ratio 0.78% 0.52% 

Number of small entities with cost-to-sales ratios $1 percent 34 23 

Number of small entities with cost-to-sales ratios $3 percent 10 8 

This report corrects errors in the February 2004 report and reflects revised model unit 

cost estimates and corrected characterizations of size status. The net increase in small entities 

affected by the final rule was 2 entities. However, lower model unit control costs lowered the 

average annual control cost per small entity, which had the effect of lowering the average costto-sales ratio and the number of small entities with cost-to-sales ratios greater than 1 percent. The 

lower model unit cost estimates were prepared as part of revisions to the costs for the final 

MACT standard issued in 2004, but were not incorporated in the February 2004 report due to 

lack of time and resources. These lower model unit costs do not reflect the risk-based compliance 

alternatives included in the final MACT standard. 

7.1 Background on Small Entity Screenings 

The regulatory costs imposed on domestic producers and government entities to reduce 

air emissions from boilers and process heaters will have a direct impact on owners of the affected 

facilities. Firms, individuals, or governmental jurisdictions that own the facilities with boilers 

and process heaters are typically business entities that have the capacity to conduct business 

transactions and make business decisions that affect the facility. The legal and financial 

responsibility for compliance with a regulatory action ultimately rests with these owners, who 
7-2 

must bear the financial consequences of their decisions. Environmental regulations potentially 

affect all sizes of businesses, but small businesses may have special problems relative to large 

businesses in complying with such regulations. 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts of today’s rule on small entities, small entity is 

defined as: 

(1) a small business according to Small Business Administration (SBA) size standards by 

the Standard Industrial Classification (SIC) category of the owning entity. The range 

of small business size standards for the 40 affected industries ranges from 500 to 

1,000 employees, except for petroleum refining and electric utilities. In these latter 

two industries, the size standard is 1,500 employees and a mass throughput of 75,000 

barrels/day or less, and 4 million megawatt-hours of production or less, respectively. 

(2) a small governmental jurisdiction that is a government of a city, county, town, school 

district or special district with a population of less than 50,000; and 

(3) a small organization that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field. 

This section investigates characteristics of businesses and government entities that own 

existing boilers and process heaters affected by this rule and provides a preliminary screeninglevel analysis to assist in determining whether this rule is likely to impose a significant impact on 

a substantial number of the small businesses within this industry. The screening-level analysis 

employed here is a “sales test,” which computes the annualized compliance costs as a share of 

sales/revenue for existing companies/government entities. 

7.2 Identifying Small Entities with Affected Sources in the Inventory Database 

As discussed in Section 3.2, EPA identified 2,186 boilers and process heaters located at 

commercial, industrial, and government facilities that would be affected by the regulation. The 

population of boilers and process heaters was developed from the EPA ICCR Inventory Database 

version 4.1.9

 The list of boilers and process heaters contained in these databases was developed 

 

9

 The ICCR Inventory Database contains data for boilers, process heaters, incinerators, landfill gas flares, turbines, 

and internal combustion engines. 
7-3 

from information in the AIRS and OTAG databases, state and local permit records, and the 

combustion source ICR conducted by the Agency. Industry and environmental stakeholders 

reviewed the units contained in these databases as part of the ICCR FACA process. In addition, 

stakeholders contributed to the databases by identifying and including omitted units. Information 

was extracted from the ICCR databases to support the ICI boilers and process heaters NESHAP. 

This modified database containing information on only boilers and process heaters is referred to 

as the Inventory Database. 

The ICCR Inventory Database provided information on thousands of facilities at which 

units were located. Using DUNS numbers, plant names, and ownership records, each facility’s 

ultimate parent entity was identified. The parent company was added to the Inventory Database 

to facilitate the SBREFA screening. Next, revenue, employment, and, if applicable, population 

and nameplate capacity data were obtained for all parent entities: 

 Parent company data were gathered from Dun & Bradstreet, Standard & Poor’s, and 

American Business Information. The reference years for this data are 1999 to 2000. 

 Electric utility and nonutility data were taken from the Energy Information 

Administration. The reference year for this data is 1999. 

 Population data were obtained from the U.S. Census Bureau, and the reference year 

of the data is 2000. 

These revenue, employment, capacity, and population data were used to characterize each 

entity as either small or large using SBA small business size standards. The initial screening for 

this analysis was done before widespread adoption of NAICS. All data sources still used the SIC 

system, and accordingly the Agency used the ultimate parent’s 4-digit SIC code when 

characterizing each entity as large or small. 

In some instances, a facility’s 4-digit SIC code did not match the 4-digit SIC code for its 

parent’s primary economic activity. The size standard for the parent’s primary economic activity 

was used for the SBREFA screening; however, the facility SIC code was left as reported so that 

all tables listing unit, facility, and company counts accurately reflect the economic activity of the 

affected boiler or process heater. For example, a government owning an electric generating unit 

was characterized as small if it had fewer than 50,000 residents, but the unit, facility, and parent 

is presented in the tables as a constituent member of SIC 49. 

The sum of each parent’s affected unit control costs was compared with its revenue to 

calculate the parent’s cost-to-sales ratio (CSR). The CSR presents the total annual control costs 

as a percentage of estimated annual revenue. This measure is used to determine the extent to 
7-4 

which the proposed rule will affect the parent financially. Sections 7.3 and 7.4 present summary 

descriptive statistics on parent entity sales and employment, as well as the distribution of CSRs 

among small and large entities. 

The small entities screening analysis for the regulation is based on the evaluation of 

existing owners of boilers and process heaters for which information was available. It is assumed 

that the size and ownership distribution of units in the Inventory Database is representative of the 

entire estimated population of existing boilers and process heaters. In addition, it is assumed that 

new sources included in the 2005 population will also be representative of the Inventory 

Database. However, because our analysis is based on a subset of the total population of boilers 

and process heaters, the number of entities identified as highly affected in this analysis may not 

be identical to the actual impact of the regulation on small entities. The remainder of this section 

presents cost and sales information on small companies and government organizations that own 

existing boilers and process heaters. 

7.3 Analysis of Facility-Level and Parent-Level Data 

The 2,186 units in the Inventory Database with full information were linked to 1,214 

existing facilities. As shown in Table 7-2, these 1,214 facilities are owned by 576 parent entities. 

The average number of facilities per entity is approximately 2.0; however, as is also illustrated in 

Table 7-2, several large entities in the health services industry and government sectors own many 

facilities with boilers and process heaters. 

Employment and sales are typically used as measures of business size. Employment, 

sales, population, and tax revenue data (when applicable) were collected for the 576 parent 

companies and government entities.10 Figure 7-1 shows the distribution of employees by parent 

company for the final rule. Employment for parent companies ranges from 5 to 608,000 

employees. 178 or more of the firms have fewer than 500 employees, and 55 companies have 

more than 25,000 employees. 

Sales provide another measure of business size. Figure 7-2 presents the sales or revenue 

distribution for affected parent entities. The median sales figure for affected companies is $300 

million ($200 million), and the average sales figure is $4.1 billion ($3.5 billion) (excluding the 

federal government). As shown in Figure 7-2, revenue and sales figures vary greatly across the 

 

10 Total annualized cost is compared to tax revenue to assess the relative impact on local governments. This metric 

for estimating impacts on government entities is consistent with the 1999 Interim Final RFA and SBREFA 

Guidance prepared by EPA and issued in March 1999. 
7-5 

Table 7-2. Facility-Level and Parent-Level Data by Industry 

SIC 

Code

NAICS 

Code Description

Number of 

Units 

Number of 

Facilities

Number of 

Parent 

Entities

Avg. Number of 

Facilities Per 

Parent Entity

01 111 Agriculture—Crops 3 3 3 1.0 

02 112 Agriculture—Livestock — — — — 

07 115 Agricultural Services — — — — 

10 212 Metal Mining 9 4 2 2.0 

12 212 Coal Mining 2 1 — — 

13 211 Oil and Gas Extraction — — — — 

14 212 Mining/Quarrying—Nonmetallic Minerals 8 4 3 1.3 

17 235 Construction—Special Trade — — — — 

20 311 Food and Kindred Products 138 60 32 1.9 

21 312 Tobacco Products 11 7 4 1.8 

22 313 Textile Mill Products 135 71 33 2.2 

23 315 Apparel & Other Products from Fabrics 2 2 1 2.0 

24 321 Lumber and Wood Products 360 262 122 2.1 

25 337 Furniture and Fixtures 234 154 67 2.3 

26 322 Paper and Allied Products 321 194 68 2.9 

27 511 Printing, Publishing, and Related Industries — — — — 

28 325 Chemicals and Allied Products 174 70 41 1.7 

29 324 Petroleum Refining and Related Industries 11 8 9 0.9 

30 326 Rubber and Misc. Plastics Products 17 13 9 1.4 

31 316 Leather and Leather Products 1 1 1 1.0 

32 327 Stone, Clay, Glass, and Concrete Products 9 7 4 1.8 

33 331 Primary Metal Industries 41 16 10 1.6 

34 332 Fabricated Metal Products 16 10 7 1.4 

35 333 Industrial Machinery and Computer Equip. 23 12 9 1.3 

36 335 Electronic and Electrical Equipment 5 5 3 1.7 

37 336 Transportation Equipment 102 41 12 3.4 

38 334 Scientific, Optical, and Photographic 

Equipment 

8 4 3 1.3 

39 339 Misc. Manufacturing Industries 2 2 2 1.0 

40 482 Railroad Transportation 4 1 1 1.0 

42 484 Motor Freight and Warehousing 5 1 1 1.0 

46 486 Pipelines, Except Natural Gas — — — — 

49 221 Electric, Gas, and Sanitary Services 318 160 80 2.0 

50 421 Wholesale Trade—Durable Goods 3 2 1 2.0 

51 422 Wholesale Trade—Nondurable Goods 2 1 1 1.0 

55 441 Automotive Dealers and Gasoline Service 

Stations 

— — — — 

58 722 Eating and Drinking Places — — — — 

59 445–454 Miscellaneous Retail — — — — 

60 522 Depository Institutions — — — — 

(continued) 
7-6 

Table 7-2. Facility-Level and Parent-Level Data by Industry (continued) 

SIC 

Code

NAICS 

Code Description

Number of 

Units 

Number of 

Facilities

Number of 

Parent 

Entities

Avg. Number of 

Facilities Per 

Parent Entity

70 721 Hotels and Other Lodging Places 1 1 1 1.0 

72 812 Personal Services — — — — 

76 811 Misc. Repair Services 2 1 — — 

80 621 Health Services 37 18 2 9.0 

81 541 Legal Services — — — — 

82 611 Educational Services 105 45 30 1.5 

83 624 Social Services 2 1 — — 

86 813 Membership Organizations — — — — 

87 541 Engineering, Accounting, Research, 

Management and Related Services 

2 2 1 2.0 

89 711/514 Services, N.E.C. 2 1 — — 

91 921 Executive, Legislative, and General 

Administration 

1 1 — — 

92 922 Justice, Public Order, and Safety 29 9 — — 

94 923 Administration of Human Resources 1 1 — — 

96 926 Administration of Economic Programs 4 3 1 3.0 

97 928 National Security and International Affairs 29 11 2 5.5 

NA SIC Information Not Available 7 4 — — 

State Parent is a state government — — 10 — 

 Total 2,186 1,214 576 2.0 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 

10 12

31

125

52

121

141

55

0

50

100

150

200

<25 25 to 49 50 to 99 100 to

499

500 to

999

1,000 to

4,999

5,000 to

24,999

>25,000

Parent Employment

Number of Parents

Figure 7-1. Parent Size by Employment Range 
7-7 

7

18

128

56

110

51

133

20

33

17

0

50

100

150

200

<5 5 to 9 10 to 49 50 to 99 100 to

499

500 to

999

1,000 to

4,999

5,000 to

9,999

10,000 to

24,999

>25,000

Parent Sales ($106)

Number of Parents

Figure 7-2. Number of Parents by Sales Range 

*Excludes 3 parent entities for which sales or revenue information was unavailable. 

population: 209 firms and governments affected by the final rule have annual revenues less than 

$100 million per year. These figures include all sales associated with the parent company, not 

just facilities affected by the regulation (i.e., facilities with boilers or process heaters). 

Based on SBA guidelines, 187 of the entities were identified as small businesses.11 Small 

businesses by business type are presented in Table 7-3. The lumber and wood products industry 

contains the largest number of the small businesses with 84, followed by furniture and fixtures 

with 28, electric services with 28, and paper and allied products with 13. The remaining small 

businesses are distributed across 40 different two-digit SIC code groupings. This corrected report 

identified 2 additional small entities in SIC 49, changed one entity in SIC 80 from small to large, 

and corrected one SIC 82 entity from large to small. 

 

11 Small business guidelines typically define small businesses based on employment, and the threshold varies from 

industry to industry. For example, in the paints and allied products industry, a business with fewer than 500 

employees is considered a small business; whereas in the industrial gases industry, a business with fewer than 

1,000 employees is considered small. However, for a few industries, usually services, sales are used as the 

criterion. For example, in the veterinary hospital industry, companies with less than $5 million in annual sales 

are defined as small businesses. 
7-8 

Table 7-3. Small Parent Entities by Industry 

SIC 

Code

NAICS 

Code Description

Number of Parent 

Entities

February 2004 

Report 

Number of Small 

Parent Entities

Final Rule 

Number of Small 

Parent Entities

01 111 Agriculture—Crops 3 — — 

02 112 Agriculture—Livestock — — — 

07 115 Agricultural Services — — — 

10 212 Metal Mining 2 2 2 

12 212 Coal Mining — — — 

13 211 Oil and Gas Extraction — — — 

14 212 Mining/Quarrying—Nonmetallic Minerals 3 — — 

17 235 Construction—Special Trade Contractors — — — 

20 311 Food and Kindred Products 32 12 12 

21 312 Tobacco Products 4 — — 

22 313 Textile Mill Products 33 5 5 

23 315 Apparel and Other Products from Fabrics 1 — — 

24 321 Lumber and Wood Products 122 84 84 

25 337 Furniture and Fixtures 67 28 28 

26 322 Paper and Allied Products 68 13 13 

27 511 Printing, Publishing, and Related Industries — — — 

28 325 Chemicals and Allied Products 41 4 4 

29 324 Petroleum Refining and Related Industries 9 2 2 

30 326 Rubber and Misc. Plastics Products 9 1 1 

31 316 Leather and Leather Products 1 1 1 

32 327 Stone, Clay, Glass, and Concrete Products 4 — — 

33 331 Primary Metal Industries 10 1 1 

34 332 Fabricated Metal Products 7 3 3 

35 333 Industrial Machinery and Computer Equip. 9 1 1 

36 335 Electronic and Electrical Equipment 3 — — 

37 336 Transportation Equipment 12 1 1 

38 334 Scientific, Optical, and Photographic Equip. 3 — — 

39 339 Miscellaneous Manufacturing Industries 2 — — 

40 482 Railroad Transportation 1 — — 

42 484 Motor Freight and Warehousing 1 — — 

46 486 Pipelines, Except Natural Gas — — — 

49 221 Electric, Gas, and Sanitary Services 80 26 28 

50 421 Wholesale Trade—Durable Goods 1 — — 

51 422 Wholesale Trade—Nondurable Goods 1 — — 

55 441 Automotive Dealers and Gasoline Stations — — — 

58 722 Eating and Drinking Places — — — 

59 445–454 Miscellaneous Retail — — — 

60 522 Depository Institutions — — — 

(continued) 
7-9 

Table 7-3. Small Parent Entities by Industry (continued) 

SIC 

Code

NAICS 

Code Description

Number of Parent 

Entities

February 2004 

Report 

Number of Small 

Parent Entities

Final Rule 

Number of Small 

Parent Entities

70 721 Hotels and Other Lodging Places 1 — — 

72 812 Personal Services — — 

76 811 Misc. Repair Services — — 

80 621 Health Services 2 1 — 

81 541 Legal Services — — — 

82 611 Educational Services 30 — 1 

83 624 Social Services — — — 

86 813 Membership Organizations — — — 

87 541 Engineering, Accounting, Research, 

Management and Related Services 

1 — — 

89 711/514 Services, N.E.C. — — — 

91 921 Executive, Legislative, and General 

Administration 

— — — 

92 922 Justice, Public Order, and Safety — — — 

94 923 Administration of Human Resources — — — 

96 926 Administration of Economic Programs 1 — — 

97 928 National Security and International Affairs 2 — — 

NA SIC Information Not Available — — — 

State Parent is a State Government 10 — — 

 Total 576 185 187 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 

7.4 Small Entity Impacts 

Table 7-4 presents a summary of the ratio of control costs to sales for affected large and 

small entities. The average CSR is 0.10 percent for large entities (excluding the federal 

government) and 0.52 percent for small entities. In all, 23 small parents had CSRs greater than 

1 percent, assuming add-on control is employed to meet the standard. For these 23 parent 

companies, the CSRs ranged from 1.00 percent to 7.83 percent. Eight entities had CSRs ratios 

greater than 3 percent. The February 2004 report identified 44 small entities, 10 of which were 

impacted at the greater than 3 percent cost-to-sales ratio level. 
7-10 

Table 7-4. Summary Statistics for SBREFA Screening Analysis 

February 2004 

Report 

Final Rule 

Total Number of Small Entities 185 187 

Average Annual Compliance Cost per Small Entity ($103) $199 $149 

Entities with Sales/Revenue Data 

 Compliance costs are <1% of sales 141 164 

 Compliance costs are $1 to 3% of sales 34 15 

 Compliance costs are $3% of sales 10 8 

Compliance Cost-to-Sales/Revenue Ratios 

 Average 0.78 0.52 

 Median 0.50 0.16 

 Maximum 7.83 7.83 

 Minimum 0.01 0.01 

7.5 Affected Government Entities: Supplemental Analysis 

Of the 187 small entities identified, 14 were small governmental jurisdictions that own 

and operate public utilities with affected boilers. The Regulatory Flexibility Act as amended by 

the Small Business Regulatory Enforcement Fairness Act provides the following standard 

definition of “small governmental jurisdiction”: a city, county, town, township, village, school 

district, or special district with a population of less than 50,000. For this analysis, public power 

producers are defined as nonprofit publicly owned utilities operated by municipalities, counties, 

and states or other publicly owned bodies such as public utility districts. This excludes rural 

electric cooperatives. 

As illustrated in Table 7-5, the vast majority of small municipal systems with affected 

boilers are located in the Midwest (10 systems or 71 percent). Four of the 10 municipal systems 

are located in Minnesota and two are in Indiana. The February 2004 report incorrectly identified 

13 small government entities; the third column of Table 7-5 includes one additional entity in 

both Pennsylvania and Georgia, but removes a Michigan municipality incorrectly categorized as 

small. 

Historically municipal utilities were created to provide residents of a community with 

reliable energy. For example, the residential sector accounts for more than two-thirds of total 

consumers in all cases (see Table 7-6). However, the residential sector generally represents the 

smallest group in terms of total energy consumption. The industrial and commercial sectors 
7-11 

Table 7-5. Regional Distribution of Municipal Systems 

Regional Distribution

February 2004 Report 

Number of Facilities 

Final Rule 

 Number of Facilities 

East 

Pennsylvania — 1 

Vermont 1 1 

Midwest 

Indiana 2 2 

Iowa 1 1 

Michigan 2 1 

Minnesota 4 4 

Ohio 1 1 

Wisconsin 1 1 

South 

Georgia — 1 

West 

California 1 1 

Total 13 14 

consume approximately 70 percent of total energy supplied. Power not consumed by the 

residential, commercial, or industrial sector is sold into the wholesale energy market. 

Public power producers do not pay state or local taxes. However, they typically are under 

agreement to make annual contributions to state and local government operating funds. In 

addition, they are not guaranteed a rate of return (as regulated public utilities are); however, their 

rates are set by agreement with local councils, and these rates are typically adjusted to reflect 

changes in operating costs. 

Municipal utilities can generate capital by issuing tax-exempt municipal bonds. These 

municipal bonds are exempt from federal income taxes, permitting publicly owned utilities to 

finance capital projects at a more affordable rate. Additionally, the local governments investing 

in municipal utilities generally issue revenue bonds rather than general obligation bonds. This 

ensures that the debt can be paid back through revenues from generating electricity and does not 

obligate the local government or community tax base. 
7-12 

Table 7-6. Selected Municipal Utilities’ Capacity, Usage, and Consumer Types 

Distribution of Energy Usage by Customer 

Type Distribution 

Row 

ID

Capacity 

(MW) 

Energy Usage 

(kWh/y) Residential Commercial Industrial

Total 

Consumers Residential Com

1 50.5 332,524,000 27% NA NA 19,313 82% 2 115 371,823,000 36% 28% 16% 15,615 87% 3 24.3 388,066,000 19% 10% 70% 9,082 84% 4 22.2 185,191,000 26% 14% 58% 6,235 86% 5 34.5 147,335,000 26% 27% 44% 5,955 86% 6 23 573,003,000 8% NA NA 7,207 90% 7 35 338,903,000 38% 8% 51% 13,247 87% 8 46 194,753,000 22% NA NA 6,890 85% 9 103.1 837,175,000 NA NA NA NA NA 10 32 218,208,000 40% 3% 55% 10,829 88% 11 26 267,201,000 16% NA NA 9,471 75% 12 34 95,642,000 33% 67% NA 5,747 83% 13 31.5 363,989,000 39% NA NA 11,650 79% 

Source: Giles, Ellen F. 2000. Platt’s Directory of Electric Power Producers and Distributors, 109th Edition of the Electrical World Dir

McGraw Hill. 

Note: One impacted municipality’s boiler is employed by its city school district; the unit is not an electric generating unit. This correcte

municipal utility system (Row 13) that was incorrectly categorized as large in the February 2004 report. 
7-13 

As shown in Table 7-7, the average total annual compliance costs per entity are $258,654 

under the final rule. The median cost-to-revenue ratio is 0.90 percent, and ratios range from less 

than 0.5 percent to 8 percent. Three of the affected small governments have cost-to-revenue 

ratios at or above 3 percent. The average annual control cost for impacted small governments 

increased in the corrected version of the report because the total annual control costs for the 

corrected subset of municipal entities increased. 

Table 7-7. Comparison of Screening Analysis Results for Small Governmental Jurisdictions 

February 2004 

Report 

Final Rule

Total Number of Small Entities 13 14 

Average Total Annual Compliance Cost (TACC) per Small Entity ($103) $223 $259 

Entities with Sales/Revenue Data 

 Compliance costs are <1% of revenue 7 7 

 Compliance costs are $1 to 3% of revenue 3 4 

 Compliance costs are $3% of revenue 3 3 

Compliance Cost-to-Sales/Revenue Ratios 

 Average 1.67 1.51 

 Median 0.94 0.90 

 Maximum 7.83 7.83 

 Minimum 0.02 0.02 

7.6 Small Utility and Nonutility Entities: Data and Screening Analysis Results 

EPA identified 14 small commercial utilities and nonutilities in addition to the 14 small 

municipal utility systems. The commercial entities consisted of 11 small electric power 

generators (SIC 4911). One facility is a cogeneration plant at a sugar cane processing facility. 

The remaining two entities are small local private utility services that provide steam services 

within a limited service territory (see Table 7-8). 

As shown in Table 7-9, the average total annual compliance costs per entity are $270,428 

under the final rule. The median cost-to-revenue ratio is 0.24 percent, and ratios range from less 

than 0.02 percent to 1.02 percent. Only 1 of these 14 affected entities has a cost-to-revenue ratio 

at or above 1 percent. 
7-14 

Table 7-8. Industry Distribution of Small Commercial Electric Utility and Nonutility 

Entities 

Parent SIC 

Code Parent Industry 

Final Rule 

Number of Entities SBA Size Standard 

2062 Sugar Cane Producers 1 750 employees 

4911 Electric Generation 11 4 million megawatt hours 

4931 Electricity and Other Services Combined 1 $5 million annual revenue 

4961 Steam and Air Conditioning Supply 1 $9 million annual revenue 

 Total 14 

Table 7-9. Supplemental Screening Analysis for Small Governmental Jurisdictions 

Final Rule

Total Number of Small Entities 14 

Average Total Annual Compliance Cost (TACC) per Small Entity ($103) $270 

Entities with Sales/Revenue Data 

 Compliance costs are <1% of revenue 13 

 Compliance costs are $1 to 3% of revenue 1 

 Compliance costs are $3% of revenue 0 

Compliance Cost-to-Sales/Revenue Ratios 

 Average 0.33 

 Median 0.24 

 Maximum 1.02 

 Minimum 0.02 

7.7 Assessment of SBREFA Screening 

This analysis indicates that over two-thirds of the entities affected by the industrial 

boilers and process heaters standard are large.12 The relatively small proportion of small entities 

affected by the regulation at the MACT floor is due in part to the exclusion of ICI boilers and 

process heaters with less than 10 MMBtu input capacity that also use a fossil fuel liquid or gas as 

primary fuel. As a result, a large share of small boilers and process heaters, which are 

presumably owned disproportionately by smaller entities, will not incur compliance costs. The 

Agency estimates that approximately 57 percent of the U.S. population are less than 10 MMBtus 

or are emergency units and, hence, are excluded from the regulation. 

 

12 Based on SBA guidelines for determining small entities. 
7-15 

Of the small entities affected by the final rule, the majority are in the lumber and wood 

products, furniture and fixtures, paper and allied products, and electric, gas and sanitary services 

sectors. As shown in Table 7-10, the median profit margin for these four sectors is approximately 

3 percent. Table 7-10 also shows the profit margins for the other industry sectors with affected 

small businesses. All profit margins of industry sectors with affected small businesses are above 

2 percent. 

Table 7-10. Profit Margins for Industry Sectors with Affected Small Businesses 

SIC Code NAICS Code Description Median Profit Margin

20 311 Food and Kindred Products 3.6% 

22 313 Textile Mill Products 2.1% 

24 321 Lumber and Wood Products 3.0% 

25 337 Furniture and Fixtures 3.0% 

26 322 Paper and Allied Products 3.3% 

28 325 Chemicals and Allied Products 2.7% 

49 221 Electric, Gas, and Sanitary Services 7.5% 

Source: Dun & Bradstreet. 1997. Industry Norms & Key Business Ratios. Desktop Edition 1996-97. Murray Hill, 

NJ: Dun & Bradstreet, Inc. 

After considering the economic impact of the final rule on small entities, EPA certifies 

that this action will not have a significant impact on a substantial number of small entities. In 

accordance with the RFA, as amended by the SBREFA, 5 U.S.C. 601, et. seq., EPA conducted 

an assessment of the standard on small businesses within the industries affected by the rule. 

Based on SBA size definitions and reported sales and employment data, the Agency identified 

187 entities, or 32 percent. 

Although small entities represent 32 percent of the SBREFA screening population, they 

are expected to incur only 7.5 percent of the screening population’s compliance costs of $370.4 

million (1998$). Only 8 small entities have compliance costs equal to or greater than 3 percent of 

their sales. In addition, only 15 small entities have CSRs between 1 and 3 percent. Additional 

analysis of small governmental jurisdictions shows 3 of 14 have CSRs greater than 3 percent, 

and 4 have CSRs between 1 and 3 percent. 

An EIA was performed to estimate the changes in product price and production quantities 

for this rule. As mentioned in the summary of economic impacts earlier in this report, the 

estimated changes in prices and output for affected firms (including small firms) are no more 

than 0.04 percent. It should be noted that we did not use median profit margin data in drawing 

any conclusions on the size of the small entity impacts estimated for this report. 
7-16 

This rule will not have a significant economic impact on a substantial number of small 

entities as a result of several decisions EPA made regarding the development of this rulemaking 

which resulted in limiting the impact of this rule on small entities. First, as mentioned earlier, 

EPA identified small units (heat input of 10 MMBtu/hr or less) and limited-use boilers (operate 

less than 10 percent of the time) as separate subcategories from large units. Many small and 

limited-use units are located at small entities. As also discussed earlier, the result of the MACT 

floor analysis for these subcategories of existing sources was that no MACT floor could be 

identified except for the limited-use solid fuel subcategory, which is less stringent than the 

MACT floor for large units. Furthermore, the results of the above-the-floor analysis for these 

subcategories indicated that the costs would be too high to be considered feasible. Consequently, 

this rule contains no emission limitations for any of the existing small and limited-use 

subcategories except the existing limited-use solid fuel subcategory. In addition, the alternative 

metals emission limit resulted in minimizing the impacts on small entities because some of the 

potential entities burning a fuel containing very little metals are small entities. 
R-1 

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R-5 

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A-1 

APPENDIX A: 

ECONOMIC MODEL OF MARKETS AFFECTED BY THE BOILERS AND 

PROCESS HEATERS MACT 

The primary purpose of the EIA for the rule is to describe and quantify the economic 

impacts associated with the rule. The Agency used a basic framework that is consistent with 

economic theory and the analyses performed for other rules to develop estimates of these 

impacts. This approach employs standard microeconomic concepts to model behavioral 

responses expected to occur with regulation. This appendix describes the spreadsheet model in 

more detail and discusses how the Agency 

 collected the baseline data set from the Annual Energy Outlook 2002 (DOE, EIA, 

2002), U.S. Census Bureau (U.S. Department of Commerce, 2001), and U.S. 

Department of Agriculture (USDA, 2002). 

 characterized market supply and demand for each market and specified links between 

the energy and agricultural, manufacturing, mining, and commercial markets. 

 introduced a policy “shock” into the model by using control cost-induced shifts in the 

supply functions, and 

 used a solution algorithm to determine a new with-regulation equilibrium for each 

market. 

A.1 Baseline Data Set 

EPA collected the following data to characterize the baseline year, 2005: 

 Energy Market Data—The Department of Energy’s Supplemental Tables to the 

Annual Energy Outlook 2002 report forecasts of price, quantity, and fuel intensities 

used to calibrate the model. 

 Agriculture, Mining, Manufacturing, Commercial Sectors—EPA obtained shipment 

data from the 1997 Economic Census and 1997 Agriculture Census. We then used 

annual growth rates reported by the Bureau of Economic Analysis (BEA, 1997) to 

estimate baseline shipment data for 2005. The Agency selected units for output such 

that the price in each market equals one. We computed energy demand using fuel 

intensity data reported in the AEO 2002. 

 Supply and Demand Elasticities—The supply and demand elasticity values used in 

the market model are reported in Table 5-2 of this report. Given the uncertainties 

regarding these parameters, EPA also conducted several sensitivity analyses and 

report these results in Appendix B. 
A-2 

A.2 Multi-Market Model 

The model includes four energy markets (coal, electricity, natural gas, and petroleum) 

and 24 goods and service markets. The following sections describe model equations the Agency 

developed to characterize these markets and estimate welfare changes resulting from the rule. 

A.1.1 Supply Side Modeling 

EPA estimated the change in quantity supplied as follows: 

ΔqS

 = q0

S

 • ε

S

 • 

0

n

j 1

j j

p

p c ∑ p

=

Δ − − α Δ

 (A.1) 

where q0

S

 is the baseline quantity, ε

S

 is the domestic supply elasticity, the term 

∑

=

Δ − − α Δ

n

j 1

j j p c p is the change in the producer’s net price, and p0 is the baseline price. The 

change in net price is composed of the change in baseline price resulting from the regulation, the 

direct shift in the supply function resulting from compliance costs, and the indirect shift in the 

supply function resulting from changes in input prices in energy market (j). The fuel share is 

allowed to vary using a fuel switching rule relying on cross-price elasticities of demand between 

energy sources. 

A.1.1.1 Producer Welfare Measurement

EPA approximated the change in producer surplus with the following equation: 

ΔPS = q1 • ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

Δ − −∑α Δ

=

n

j 1

j p j p – 0.5 • c Δq • ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

Δ − −∑α Δ

=

n

j 1

j p j p (A.2) c

Increased control costs, higher energy input costs, and output declines have a negative 

effect on domestic producer surplus. However, these losses are mitigated to some degree as a 

result of higher market prices. 

A.1.2 Energy Demand Side Modeling 

Market demand in the energy markets is expressed as the sum of the energy, residential, 

agriculture, manufacturing, mining, commercial, and transportation sectors: 

 QDj = ∑

=

n

i 1

 qDji, (A.3) 
A-3 

where j indexes the energy market and i indexes the consuming sector. The change in residential 

quantity demanded of energy market j can be approximated as follows: 

ΔqDj

 = q0

Dj

 • ηDj • 

j0

j

p

Δp (A.4) 

where q0

Dj

 is baseline consumption, ηDj is the residential demand elasticity and (Δp) is the 

change in the market price. 

In contrast, energy demand from energy, agricultural, manufacturing, mining, 

commercial, and transportation sectors is modeled as a derived demand resulting from the 

production and consumption choices in these industries. Energy demand responds to changes in 

sector output and fuel switching that occurs in response to changes in relative energy prices. For 

each of these sectors, energy demand is expressed as follows: 

 BTUji1 = 

i0

ji

q

BTU

 • FSW • qi1 (A.5) 

where BTU is demand for energy market j from sector i, q is sector i’s output, and FSW is a 

factor generated by the fuel switching algorithm. The subscripts 0 and 1 represent baseline and 

with regulation conditions, respectively. 

A.1.3 Agriculture, Manufacturing, Mining, Commercial, and Transportation Demand Side 

Modeling 

The change in quantity demanded in these markets can be approximated as follows: 

ΔqDi

 = q0

Di

 • ηDi • 

i0

i

p

Δp (A.6) 

where q0

Di

 is baseline output, ηD is the demand elasticity of the respective market (i) and (Δpi) is 

the change in the market price. 

The change in consumer surplus in markets is approximated as follows: 

ΔCS =~ q1 • Δp + 0.5 • Δq • Δp (A.7) 

As shown, higher market prices and reduced consumption lead to welfare losses for consumers. 
A-4 

A.2 With-Regulation Market Equilibrium Determination 

Market adjustments can be conceptualized as an interactive feedback process. Supply 

segments face increased production costs as a result of the rule and are willing to supply smaller 

quantities at the baseline price. This reduction in market supply leads to an increase in the market 

price that all producers and consumers face, which leads to further responses by producers and 

consumers and thus new market prices. The new with-regulation equilibrium is the result of a 

series of iterations in which price is adjusted and producers and consumers respond, until a set of 

stable market prices arises where total market supply equals market demand (i.e., Qs = QD) in 

each market. Market price adjustment takes place based on a price revision rule that adjusts price 

upward (downward) by a given percentage in response to excess demand (excess supply). 

The algorithm for determining with-regulation equilibria can be summarized by seven 

recursive steps: 

1. Impose the control costs on affected supply segments, thereby affecting their supply 

decisions. 

2. Recalculate the market supply in each market. Excess demand currently exists. 

3. Determine the new prices via a price revision rule. 

4. Recalculate market supply with new prices, accounting for fuel switching choices 

associated with new energy prices. 

5. Compute market demand in each market. 

6. Compare supply and demand in each markets. If equilibrium conditions are not 

satisfied, go to Step 3, resulting in a new set of market prices. Repeat until 

equilibrium conditions are satisfied (i.e., the ratio of supply to demand is arbitrarily 

close to one). 
B-1 

APPENDIX B: 

ASSUMPTIONS AND SENSITIVITY ANALYSIS 

In developing the economic model to estimate the impacts of the industrial/commercial/ 

institutional boilers and process heaters NESHAP, several assumptions were necessary to make 

the model operational. This appendix lists and explains the major model assumptions and 

describes their potential impact on the analysis results. Sensitivity analyses are presented for 

numeric assumptions. 

Assumption: The domestic markets for goods and services are all perfectly competitive.

Explanation: Assuming that these markets are perfectly competitive implies that the producers 

of these products are unable to unilaterally affect the prices they receive for their products. 

Because the industries used in this analysis are aggregated across a large number of individual 

producers, it is a reasonable assumption that the individual producers have a very small share of 

industry sales and cannot individually influence the price of output from that industry. 

Possible Impact: If these product markets were in fact imperfectly competitive, implying that 

individual producers can exercise market power and thus affect the prices they receive for their 

products, then the economic model would understate possible increases in the price of final 

products due to the regulation as well as the social costs of the regulation. Under imperfect 

competition, producers would be able to pass along more of the costs of the regulation to 

consumers; thus, consumer surplus losses would be greater, and producer surplus losses would 

be smaller in the final product markets. 

Assumption: Market Supply and Demand Elasticity Uncertainty 

Explanation: The goods and service markets are modeled at the two or three-digit NAICS code 

level to operationalize the economic model. Because of the high level of aggregation, only 

limited data on elasticities of supply and demand estimates are available. However, these 

elasticities strongly influence the distribution of economic impacts between producers and 

consumers. 

Sensitivity Analysis: Tables B-1a and Table B-1b show how the economic impact estimates vary 

as the supply and demand elasticities for goods and services change by 25 percent. 
B-2 

Table B-1a. Sensitivity Analysis: Supply and Demand Elasticities in the Goods and Services 

Markets 

Change Supply 

Demand Constant 25% Decrease

Elasticities Reported 

in Section 6 25% Increase

Change in consumer surplus –367.8 –414.3 –450.5 

Change in producer surplus –495.2 –448.7 –412.4 

Change in social welfare –862.9 –862.9 –862.9 

Table B-1b. Sensitivity Analysis: Supply and Demand Elasticities in the Goods and Services 

Markets 

Supply Constant 

Demand Change 25% Decrease

Elasticities Reported 

in Section 6 25% Increase

Change in consumer surplus –462.7 –414.3 –364.4 

Change in producer surplus –400.2 –448.7 –498.5 

Change in social welfare –862.9 –862.9 –862.9 

Assumption: Cross-price elasticities of demand for fuels are based on 2015 NEMS 

projections. 

Explanation: Cross- and own-price elasticities of demand from NEMS were used to capture fuel 

switching in the manufacturing sectors in the economic model. As shown in Table 5-2, allowing 

manufacturers to switch fuels in response to changes in relative energy prices decreases the 

change in social welfare by approximately 10 percent. However, the NEMS projection reflects 

aggregate behavioral responses in the year 2015. Because this is a longer window of analysis 

compared to the baseline year 2005, this analysis may overestimate firms’ ability to switch fuels 

in the short run. 

Sensitivity Analysis: Table B-2 shows how the economic impact estimates vary as the own- and 

cross-price elasticities used in the EIA are reduced by 50 percent and 75 percent. 
B-3 

Table B-2. Sensitivity Analysis: Own- and Cross-Price Elasticities Used to Model Fuel 

Switching 

Fuel Price Elasticities 

Presented in Table 5-2

Reduced by 50 

Percent

Reduced by 75 

Percent

Change in consumer surplus –414.3 –414.6 –414.9 

Change in producer surplus –448.7 –448.4 –448.0 

Change in social welfare –862.9 –862.9 –862.9 

Assumption: The domestic markets for energy are perfectly competitive. 

Explanation: Assuming that the markets for energy are perfectly competitive implies that 

individual producers are not capable of unilaterally affecting the prices they receive for their 

products. Under perfect competition, firms that raise their price above the competitive price are 

unable to sell at that higher price because they are a small share of the market and consumers can 

easily buy from one of a multitude of other firms that are selling at the competitive price level. 

Given the relatively homogeneous nature of individual energy products (petroleum, coal, natural 

gas, electricity), the assumption of perfect competition at the national level seems to be 

appropriate.

Possible Impact: If energy markets were in fact imperfectly competitive, implying that 

individual producers can exercise market power and thus affect the prices they receive for their 

products, then the economic model would understate possible increases in the price of energy 

due to the regulation as well as the social costs of the regulation. Under imperfect competition, 

energy producers would be able to pass along more of the costs of the regulation to consumers; 

thus, consumer surplus losses would be greater, and producer surplus losses would be smaller in 

the energy markets. 

Assumption: The elasticity of supply in the electricity market for existing sources is 

approximately 0.75. 

Explanation: The price elasticity of supply in the electricity markets represents the behavioral 

responses from existing sources to changes in the price of electricity. However, there is no 

consensus on estimates of the price elasticity of supply for electricity. This is in part because, 

under traditional regulation, the electric utility industry had a mandate to serve all its customers 

and utilities were compensated on a rate-based rate of return. As a result, the market concept of 

supply elasticity was not the driving force in utilities’ capital investment decisions. This has 
B-4 

changed under deregulation. The market price for electricity has become the determining factor 

in decisions to retire older units or to make higher cost units available to the market. 

Sensitivity Analysis: Table B-3 shows how the economic impact estimates vary as the elasticity 

of supply in the electricity markets varies. 

Table B-3. Sensitivity Analysis: Elasticity of Supply in the Electricity Markets 

ES = 0.5 ES = 0.75 ES = 1.0

Change in consumer surplus –405.0 –414.3 –419.6 

Change in producer surplus –457.9 –448.7 –443.4 

Change in social welfare –862.9 –862.9 –862.9 
C-1 

APPENDIX C: 

ECONOMIC ANALYSIS OF REGULATORY ALTERNATIVE: OPTION 1A 

EPA examined one above-the-floor alternative referred to in this appendix as Option 1A. 

Option 1A broadens the scope of affected units to include those fueled by residual fuel oil and 

units of covered fuel types with input capacities less than 10 million Btus. In this appendix, we 

describe the engineering compliance costs associated with this option, estimate the size and 

distribution of social cost, and report the results of the small entity screening analysis 

C.1 Engineering Cost Analysis: Affected Population and Cost Estimates 

The entire Inventory Database contains more than 58,000 ICI boilers and process heaters. 

The number of units included in the profile was 3,580 for Option 1A. As shown in Table C-1, the 

industries with the largest number of potentially affected units are the furniture, paper, lumber, 

and electrical services industries. These four industries alone account for nearly 60 percent of 

affected units. Almost all the process heaters are in the lumber industry. The remaining units are 

primarily distributed across the manufacturing sector and service industries. The distribution of 

units affected by the Option 1A alternative is similar to the final rule, although both the number 

of units and the number of facilities is greater for Option 1A. 

We describe the technical characteristics of existing boilers affected under Option 1A 

below (see Figure C-1). These characteristics include capacity range, fuel type, and level of 

preexisting controls. 

 Capacity Range: About half of the 3,580 units affected by this alternative have input 

capacities between 10 and 100 MMBtu/hr. Twenty percent have capacities between 

100 and 250, 16 percent have capacities greater than 250, and 13 percent have 

capacities less than 10 MMBtu/hr. 

 Fuel Type: Coal and residual fuel oil are the primary fuel types each accounting for 

slightly less than one-third of the units. The remaining third primarily consists of 

units that consume wood or some other type of biomass fuel. 

 Control Level: Forty-one percent have no existing pollution control equipment 

installed. Typical control devices include fabric filters, wet scrubbers, and 

electrostatic precipitators. 

 Fuel Type: This alternative includes those units affected under Option 1A, as well as 

a large number of natural gas units that were not affected under Option 1A. The vast 

majority of the 78 percent of the total number of potentially affected units are fueled 

by natural gas. 

 Control Level: Eighty-eight percent of the affected units have no preexisting control 

equipment. 
C-2 

Table C-1. Units and Facilities Affected by the Option 1A Alternative by Industrya 

SIC 

Code

NAICS 

Code Description Boilers Heaters

Total 

Units Facilities

01 111 Agriculture—Crops 6 0 6 6 

02 112 Agriculture—Livestock 0 0 0 0 

07 115 Agricultural Services 0 0 0 0 

10 212 Metal Mining 10 1 11 5 

12 212 Coal Mining 2 0 2 1 

13 211 Oil and Gas Extraction 8 10 18 4 

14 212 Mining/Quarrying—Nonmetallic Minerals 10 0 10 5 

17 235 Construction—Special Trade Contractors 2 0 2 1 

20 311 Food and Kindred Products 163 0 163 72 

21 312 Tobacco Products 22 0 22 11 

22 313 Textile Mill Products 247 3 250 134 

23 315 Apparel and Other Products from Fabrics 4 0 4 4 

24 321 Lumber and Wood Products 434 28 462 337 

25 337 Furniture and Fixtures 310 0 310 209 

26 322 Paper and Allied Products 503 0 503 272 

27 511 Printing, Publishing, and Related Industries 8 0 8 6 

28 325 Chemicals and Allied Products 332 101 433 163 

29 324 Petroleum Refining and Related Industries 54 108 162 50 

30 326 Rubber and Miscellaneous Plastics Products 56 0 56 37 

31 316 Leather and Leather Products 22 0 22 12 

32 327 Stone, Clay, Glass, and Concrete Products 40 2 42 25 

33 331 Primary Metal Industries 83 2 85 33 

34 332 Fabricated Metal Products 44 0 44 28 

35 333 Industrial Machinery and Computer Equipment 46 0 46 25 

36 335 Electronic and Electrical Equipment 45 0 45 29 

37 336 Transportation Equipment 158 0 158 61 

38 334 Scientific, Optical, and Photographic Equip. 33 0 33 16 

39 339 Miscellaneous Manufacturing Industries 14 0 14 10 

40 482 Railroad Transportation 4 0 4 1 

42 484 Motor Freight and Warehousing 5 2 7 3 

46 486 Pipelines, Except Natural Gas 3 3 6 5 

49 221 Electric, Gas, and Sanitary Services 371 1 372 185 

50 421 Wholesale Trade—Durable Goods 3 0 3 2 

(continued) 
C-3 

Table C-1. Units and Facilities Affected by the Option 1A Alternative by Industrya

(continued) 

SIC 

Code

NAICS 

Code Description Boilers Heaters

Total 

Units Facilities

51 422 Wholesale Trade—Nondurable Goods 2 0 2 1 

55 441 Automotive Dealers and Gasoline Service Stations 0 1 1 1 

58 722 Eating and Drinking Places 0 0 0 0 

60 522 Depository Institutions 0 0 0 0 

59 445–454 Miscellaneous Retail 1 0 1 1 

70 721 Hotels and Other Lodging Places 1 0 1 1 

72 812 Personal Services 0 0 0 0 

76 811 Miscellaneous Repair Services 2 0 2 1 

80 621 Health Services 40 0 40 19 

81 541 Legal Services 0 0 0 0 

82 611 Educational Services 114 0 114 50 

83 624 Social Services 3 0 3 2 

86 813 Membership Organizations 0 0 0 0 

87 541 Engineering, Accounting, Research, Management 

and Related Services 

6 0 6 5 

89 711/514 Services, N.E.C. 2 0 2 1 

91 921 Executive, Legislative, and General 

Administration 

2 0 2 2 

92 922 Justice, Public Order, and Safety 33 0 33 10 

94 923 Administration of Human Resources 1 0 1 1 

96 926 Administration of Economic Programs 4 0 4 3 

97 928 National Security and International Affairs 41 0 41 13 

NA SIC Information Not Available 24 0 24 18 

 3,318 262 3,580 1,881 

a

 Based on the Inventory Database. 

The Agency estimates that in 2005, 9,163 units (existing units and new units) may be 

affected by the Option 1A. These populations were used to estimate national engineering costs. 

As shown in Table C-2, the cost of controls for Option 1A is $1,995.8 million, with an average 

per-unit cost of $218,000. 
C-4 

Input Capacity

(million Btu)

Preexisting Control

Technology

Fuel Type

Coal

31%

Coal and

Wood

5% Wood

18%

Other

3%

Other

Biomass

9%

Bagasse

2%

Option 1A Alternative (n=3,580)

>250

16%

10 to 100

51%

100 to 250

20%

0 to 10

13%

Cyclone

26%

No Control

41%

Wet

Scrubber

8%

Fabric Filter

10%

ESP

15% Residual

Fuel Oil

32%

Figure C-1. Characteristics of Units Affected 

Table C-2. Unit Cost and Population Estimates for the Option 1A by Industry, 2005 

Total Units Total Cost

SIC 

Code

NAICS 

Code Description

Option 

1A Units Percent

Option 1A Costs 

(by Unit) Percent

01 111 Agriculture—Crops 11 0.12% $1,633,841 0.08% 

02 112 Agriculture—Livestock — 0.00% — 0.00% 

07 115 Agricultural Services — 0.00% — 0.00% 

10 212 Metal Mining 34 0.37% $8,952,098 0.45% 

12 212 Coal Mining 6 0.06% $683,026 0.03% 

13 211 Oil and Gas Extraction 137 1.50% $6,070,001 0.30% 

14 212 Mining/Quarrying—Nonmetallic Minerals 31 0.34% $17,958,177 0.90% 

17 235 Construction—Special Trade Contractors 2 0.03% $230,525 0.01% 

20 311 Food and Kindred Products 376 4.10% $122,487,346 6.14% 

21 312 Tobacco Products 56 0.61% $13,685,614 0.69% 

22 313 Textile Mill Products 673 7.34% $147,094,726 7.37% 

23 315 Apparel and Other Products from Fabrics 10 0.11% $1,213,586 0.06% 

24 321 Lumber and Wood Products 620 6.77% $89,961,854 4.51% 

25 337 Furniture and Fixtures 421 4.60% $50,045,573 2.51% 

26 322 Paper and Allied Products 1,050 11.46% $323,736,302 16.22% 

27 511 Printing, Publishing, and Related Industries 37 0.40% $1,824,933 0.09% 

28 325 Chemicals and Allied Products 1,359 14.83% $293,027,205 14.68% 

29 324 Petroleum Refining and Related Industries 677 7.38% $73,172,001 3.67% 

30 326 Rubber and Miscellaneous Plastics Products 178 1.94% $18,100,195 0.91% 

31 316 Leather and Leather Products 66 0.72% $6,924,480 0.35% 

32 327 Stone, Clay, Glass, and Concrete Products 154 1.68% $17,509,996 0.88% 

33 331 Primary Metal Industries 271 2.95% $65,174,064 3.27% 

(continued) 
C-5 

Table C-2. Unit Cost and Population Estimates for the Option 1A by Industry, 2005 

(continued) 

 Total Units Total Cost

SIC 

Code 

NAICS 

Code Description 

Option 1A 

Units Percent

Option 1A 

Costs 

(by Unit) Percent

34 332 Fabricated Metal Products 165 1.80% $22,066,661 1.11% 

35 333 Industrial Machinery and Computer Equipment 151 1.65% $26,418,385 1.32% 

36 335 Electronic and Electrical Equipment 167 1.82% $18,770,867 0.94% 

37 336 Transportation Equipment 453 4.95% $107,402,909 5.38% 

38 334 Scientific, Optical, and Photographic Equipment 104 1.13% $13,638,983 0.68% 

39 339 Miscellaneous Manufacturing Industries 37 0.41% $4,222,427 0.21% 

40 482 Railroad Transportation 9 0.10% $2,240,871 0.11% 

42 484 Motor Freight and Warehousing 19 0.21% $3,475,610 0.17% 

46 486 Pipelines, Except Natural Gas 19 0.21% $1,959,589 0.10% 

49 221 Electric, Gas, and Sanitary Services 865 9.44% $331,479,389 16.61% 

50 421 Wholesale Trade—Durable Goods 6 0.07% $2,675,296 0.13% 

51 422 Wholesale Trade—Nondurable Goods 4 0.04% $2,693,380 0.13% 

55 441 Automotive Dealers and Gasoline Service 

Stations 

2 0.02% $195,421 0.01% 

58 722 Eating and Drinking Places — 0.00% — 0.00% 

59 445–454 Miscellaneous Retail 3 0.03% $259,585 0.01% 

60 522 Depository Institutions — 0.00% — 0.00% 

70 721 Hotels and Other Lodging Places 2 0.02% $849,114 0.04% 

72 812 Personal Services 1 0.01% $7,840 0.00% 

76 811 Miscellaneous Repair Services 4 0.05% $1,120,435 0.06% 

80 621 Health Services 93 1.01% $22,545,605 1.13% 

81 541 Legal Services — 0.00% — 0.00% 

82 611 Educational Services 273 2.98% $91,770,778 4.60% 

83 624 Social Services 8 0.08% $1,448,405 0.07% 

86 813 Membership Organizations — 0.00% — 0.00% 

87 541 Engineering, Accounting, Research, Management 

and Related Services 

49 0.54% $5,016,627 0.25% 

89 711/514 Services, N.E.C. 2 0.02% $1,211,582 0.06% 

91 921 Executive, Legislative, and General 

Administration 

5 0.06% $845,423 0.04% 

92 922 Justice, Public Order, and Safety 77 0.85% $21,308,885 1.07% 

94 923 Administration of Human Resources 2 0.02% $314,316 0.02% 

96 926 Administration of Economic Programs 8 0.09% $4,200,975 0.21% 

97 928 National Security and International Affairs 96 1.05% $36,080,306 1.81% 

NA SIC Information Not Available 368 4.01% $12,099,975 0.61% 

State Parent is a state government — 0.00% — 0.00% 

 9,163 $1,995,805,181 
C-6 

C.2 Economic Impact Analysis Results 

As shown in Table C-3, EPA estimates the welfare impacts are over twice as high as the 

MACT floor ($1,995.5 million). The market analysis shows that consumers will bear $955.3 

million, or 48 percent of the total social cost as a result of higher prices and lower consumption 

levels. Producer surplus is projected to decrease by $1,040.2 million, or 52 of the total social cost 

as result of direct control costs, higher energy costs, and reductions in output. 

Table C-3. Social Cost Estimates ($1998 106) 

Change in Social Welfare, 

MACT Floor

Change in Social Welfare, 

Option 1A

Baseline engineering costs $863.0 $1,995.8 

Social costs with market adjustments $862.9 $1,995.5 

Difference between engineering and social costs $0.1 $0.3 

With exception of the natural gas market, energy producers are expected to experience 

producer surplus losses. Electricity, petroleum, and coal producer surplus is projected to decline 

by approximately $113 million under Option 1A. In contrast, natural gas producer surplus is 

projected to increase by $2 million as they benefit from increased demand from industries 

switching from petroleum and electricity (Table C-4). 

The majority welfare impacts fall on the agriculture, manufacturing, and mining 

industries and EPA estimates losses of $1,444.3 million for these sectors. Manufacturing 

industries with large number of boilers and process heaters and industries that consume 

electricity experience the majority these losses (e.g., chemicals and allied products, paper, textile 

mill products, and food). Consumers in these industries experience losses of $709.9 million and 

producers bear $734.4 million. 

EPA also examined the impact on the commercial, transportation and residential sectors. 

We project the commercial sector has the highest welfare losses among the three ($302 million) 

with commercial customers bearing approximately 42 percent of these losses, or $129 million. 

EPA estimates similar consumer surplus loss ($92 million) for residential energy consumers. 

Finally, the total welfare loss for the transportation sector is estimated to be $46.5 million, with 

transportation customers bearing slightly more than half of these losses (51 percent). However, 

all of these losses (consumer or producer) for these sectors represent less than 0.05 percent of 

baseline value of consumption or shipments. 
C-7 

Table C-4. Distribution of Social Costs by Sector/Market: Option 1A ($1998 106) 

 Change in:

Sectors/Markets 

Producer 

Surplus

Consumer 

Surplus

Social 

Welfare

Energy Markets 

 Petroleum –$27.3 

 Natural gas $2.4 

 Electricity –$79.5 

 Coal –$6.4 

Subtotal –$110.8 

NAICS Code SIC Code Description 

311 20 (pt) Food –$90.0 –$36.0 –$126.0 

312 20 (pt); 21 Beverage and Tobacco Products –$5.4 –$9.3 –$14.7 

313 22 (pt) Textile Mills –$45.0 –$103.2 –$148.2 

314 22 (pt) Textile Product Mills –$0.1 –$0.3 –$0.4 

315 23 Apparel –$0.9 –$2.1 –$3.0 

316 31 Leather and Allied Products –$2.7 –$4.3 –$7.1 

321 24 Wood Products –$72.0 –$19.2 –$91.2 

322 26 Paper –$173.1 –$157.2 –$330.3 

323 27 Printing and Related Support –$0.4 –$1.0 –$1.4 

325 28 Chemicals –$102.4 –$204.7 –$307.1 

326 30 Plastics and Rubber Products –$6.1 –$14.6 –$20.7 

327 32 Nonmetallic Mineral Products –$9.1 –$10.9 –$20.0 

331 33 Primary Metals –$59.5 –$13.6 –$73.1 

332 34 Fabricated Metal Products –$18.6 –$5.0 –$23.6 

333 35 Machinery –$17.1 –$11.4 –$28.5 

334 36 (pt) Computer and Electronic 

Products 

–$12.0 –$4.8 –$16.8 

335 36 (pt) Electrical Equipment, 

Appliances, and Components 

–$11.7 –$7.8 –$19.6 

336 37 Transportation Equipment –$47.8 –$63.7 –$111.4 

337 25 Furniture and Related Products –$9.2 –$41.8 –$51.0 

339 39 Miscellaneous –$3.2 –$2.5 –$5.7 

11 01-08 Agricultural Sector –$1.5 –$3.6 –$5.1 

23 15-17 Construction Sector –$3.2 –$4.3 –$7.5 

21 10; 14 Other Mining Sector –$18.9 –$13.1 –$32.0 

48 40-47 (pt) Transportation –$24.1 –$22.5 –$46.5 

42; 44-45; 49; 51-56; 

61-62; 71-72; 81 

40-48 (pt); 50-

99 

Commercial –$129.3 –$172.5 –$301.8 

 Residential NA –$92.0 –$92.0 

Grand Total –$955.3 –$1,040.2 –$1,995.5 

NA = Not applicable. 

pt = Part 
C-8 

C.2.1 Market-Level Impacts 

Increases in the costs of production in the energy and final product markets due to the 

regulation are expected to result in changes in prices, production, and consumption from baseline 

levels. As shown in Table C-5, the electricity market price increases by 0.11 percent, while 

production/consumption decreases by 0.03 percent as a result of additional control costs. A 

significant share of electricity is produced in the United States using coal as a primary input. 

Therefore, projected reductions in electricity production also lead to a decrease in demand for 

coal. As a result, the price and quantities of coal are projected to fall by 0.02 percent and 0.02 

percent, respectively. In the petroleum market, the model projects small price and quantity 

effects (i.e., less than 0.02 percent). In the natural gas market, the model projects the market 

price will rise in response to increased demand (0.01 percent). The price increase is the result of 

additional control costs and increased demand. Production and consumption quantities also 

slightly increase in this market as a result of increased demand. 

Additional control costs and higher energy costs associated with the regulation lead to 

higher goods and services prices in all markets and a decline in output. However, the changes are 

generally very small. Under Option 1A, three markets have price increases greater than or equal 

to 0.05 percent—Wood Products (NAICS 321), Paper (NAICS 322), and Textile Mills (NAICS 

313). The producers in these sectors are expected to face higher per-unit control costs relative to 

other industries. In addition, these industries are also electricity-intensive; therefore, costs of 

production also increase as a result of higher electricity prices. 

C.2.2 Executive Order 13211 (Energy Effects) 

EPA has provided additional information on the impacts of the rule on affected energy 

markets below.13

Energy Price Effects. As described in the market-level results section, electricity prices 

are projected to increase by less than 1 percent. Petroleum and natural gas prices are all projected 

to increase by less than 0.1 percent. The price of coal is projected to decrease slightly. 

Impacts on Electricity Supply, Distribution, and Use. We project the increased 

compliance costs for the electricity market will result in an annual production decline of 

approximately 980 million kWh under Option 1A. 

 

13 Conversion factors for heat rates were obtained from AEO 2002, Appendix H. These factors vary by year to year; 

2010 values are reported in this appendix. 
C-9 

Table C-5. Market-Level Impacts: Option 1A 

 

Option 1A 

Percent Change

Sectors/Markets Price Quantity

Energy Markets 

 Petroleum 0.019% –0.005% 

 Natural gas 0.005% 0.001% 

 Electricity 0.108% –0.026% 

 Coal –0.020% –0.024% 

NAICS Code SIC Code Description 

311 20 (pt) Food 0.019% –0.006% 

312 20 (pt); 21 Beverage and Tobacco Products 0.007% –0.009% 

313 22 (pt) Textile Mills 0.050% –0.043% 

314 22 (pt) Textile Product Mills 0.000% 0.000% 

315 23 Apparel 0.001% –0.001% 

316 31 Leather and Allied Products 0.025% –0.030% 

321 24 Wood Products 0.075% –0.015% 

322 26 Paper 0.068% –0.074% 

323 27 Printing and Related Support 0.000% –0.001% 

325 28 Chemicals 0.021% –0.032% 

326 30 Plastics and Rubber Products 0.003% –0.005% 

327 32 Nonmetallic Mineral Products 0.009% –0.008% 

331 33 Primary Metals 0.026% –0.021% 

332 34 Fabricated Metal Products 0.007% –0.001% 

333 35 Machinery 0.005% –0.002% 

334 36 (pt) Computer and Electronic Products 0.002% –0.001% 

335 36 (pt) Electrical Equipment, Appliances, and Components 0.009% –0.004% 

336 37 Transportation Equipment 0.007% –0.007% 

337 25 Furniture and Related Products 0.013% –0.044% 

339 39 Miscellaneous 0.003% –0.002% 

11 01-08 Agricultural Sector 0.001% –0.001% 

23 15-17 Construction Sector 0.000% 0.000% 

21 10; 14 Other Mining Sector 0.023% –0.007% 

48 40-47 (pt) Transportation 0.007% –0.005% 

42; 44-45; 49; 51-

56; 61-62; 71-72; 

81 

40-48 (pt); 

50-99 

Commercial 0.001% –0.001% 

pt = Part. 
C-10 

Impacts on Petroleum, Natural Gas, and Coal Supply, Distribution, and Use. The model 

projects decreases in petroleum production/consumption of approximately 975 barrels per day 

under Option 1A. In contrast, natural gas production/consumption is projected to increase by 

600,000 cubic feet per day under Option 1A. This is the result of fuel switching in response to 

relative price changes. Finally, the model also projects less than a 1,000 tons per day decrease in 

coal production/consumption in response to reduced output from the electricity sector (a 

significant consumer of coal). 

C.3 Small Entity Screening 

The 3,580 units in the Inventory Database with full information were linked to 1,881 

existing facilities. As shown in Table C-6, these are facilities owned by 969 parent companies. 

The average number of facilities per company is approximately 2.2; however, several large 

entities in the health services industry and government sectors own many facilities with boilers 

and process heaters. 

Based on SBA guidelines, 372 of the companies were identified as small businesses.14

The lumber and wood products industry contains the largest number of the small businesses with 

134, followed by furniture and fixtures with 55, electric services with 33, and paper and allied 

products with 30. The remaining small businesses are distributed across 40 different two-digit 

SIC code groupings (Table C-7). 

 

14 Small business guidelines typically define small businesses based on employment, and the threshold varies from 

industry to industry. For example, in the paints and allied products industry, a business with fewer than 500 

employees is considered a small business; whereas in the industrial gases industry, a business with fewer than 

1,000 employees is considered small. However, for a few industries, usually services, sales are used as the 

criterion. For example, in the veterinary hospital industry, companies with less than $5 million in annual sales 

are defined as small businesses. 
C-11 

Table C-6. Facility-Level and Parent-Level Data by Industry 

SIC 

Code

NAICS 

Code Description

Number of 

Units 

Number of 

Facilities 

Number of 

Parent 

Companies 

Avg. Number of 

Facilities Per 

Parent Entity

01 111 Agriculture—Crops 6 6 6 1.0 

02 112 Agriculture—Livestock — — — — 

07 115 Agricultural Services — — — — 

10 212 Metal Mining 11 5 2 2.5 

12 212 Coal Mining 2 1 — — 

13 211 Oil and Gas Extraction 18 4 2 4.0 

14 212 Mining/Quarrying—Nonmetallic Minerals 10 5 4 1.3 

17 235 Construction—Special Trade 2 1 1 1.0 

20 311 Food and Kindred Products 163 72 38 1.9 

21 312 Tobacco Products 22 11 6 1.8 

22 313 Textile Mill Products 250 134 73 1.8 

23 315 Apparel & Other Products from Fabrics 4 4 3 1.3 

24 321 Lumber and Wood Products 462 337 175 1.9 

25 337 Furniture and Fixtures 310 209 100 2.1 

26 322 Paper and Allied Products 503 272 100 2.7 

27 511 Printing, Publishing, and Related Industries 8 6 3 2.0 

28 325 Chemicals and Allied Products 433 163 91 1.8 

29 324 Petroleum Refining and Related Industries 162 50 32 1.6 

30 326 Rubber and Misc. Plastics Products 56 37 24 1.5 

31 316 Leather and Leather Products 22 12 8 1.5 

32 327 Stone, Clay, Glass, and Concrete Products 42 25 15 1.7 

33 331 Primary Metal Industries 85 33 22 1.5 

34 332 Fabricated Metal Products 44 28 19 1.6 

35 333 Industrial Machinery and Computer Equip. 46 25 20 1.3 

36 335 Electronic and Electrical Equipment 45 29 19 1.5 

37 336 Transportation Equipment 158 61 26 2.3 

38 334 Scientific, Optical, and Photographic 

Equipment 

33 16 9 1.8 

39 339 Misc. Manufacturing Industries 14 10 9 1.1 

40 482 Railroad Transportation 4 1 1 1.0 

42 484 Motor Freight and Warehousing 7 3 3 1.0 

46 486 Pipelines, Except Natural Gas 6 5 1 5.0 

49 221 Electric, Gas, and Sanitary Services 372 185 95 1.9 

50 421 Wholesale Trade—Durable Goods 3 2 1 2.0 

(continued) 
C-12 

Table C-6. Facility-Level and Parent-Level Data by Industry (continued) 

SIC 

Code

NAICS 

Code Description

Number of 

Units 

Number of 

Facilities 

Number of 

Parent 

Companies 

Avg. Number of 

Facilities Per 

Parent Entity

51 422 Wholesale Trade—Nondurable Goods 2 1 1 1.0 

55 441 Automotive Dealers and Gasoline Service 

Stations 

1 1 1 1.0 

58 722 Eating and Drinking Places — — — — 

59 445–454 Miscellaneous Retail 1 1 1 1.0 

60 522 Depository Institutions — — — — 

70 721 Hotels and Other Lodging Places 1 1 1 1.0 

72 812 Personal Services — — — — 

76 811 Misc. Repair Services 2 1 — — 

80 621 Health Services 40 19 3 6.3 

81 541 Legal Services — — — — 

82 611 Educational Services 114 50 35 1.4 

83 624 Social Services 3 2 1 2.0 

86 813 Membership Organizations — — — — 

87 541 Engineering, Accounting, Research, 

Management and Related Services 

6 5 2 2.5 

89 711/514 Services, N.E.C. 2 1 — — 

91 921 Executive, Legislative, and General 

Administration 

2 2 1 2.0 

92 922 Justice, Public Order, and Safety 33 10 — — 

94 923 Administration of Human Resources 1 1 — — 

96 926 Administration of Economic Programs 4 3 1 3.0 

97 928 National Security and International Affairs 41 13 2 6.5 

NA SIC Information Not Available 24 18 2 9.0 

State Parent is a state government — — 11 — 

 Total 3,580 1,881 969 2.2 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 
C-13 

Table C-7. Small Parent Companies by Industry 

SIC 

Code

NAICS 

Code Description

Number of Parent 

Companies

Number of Small 

Parent Companies

01 111 Agriculture—Crops 6 1 

02 112 Agriculture—Livestock — — 

07 115 Agricultural Services — — 

10 212 Metal Mining 2 2 

12 212 Coal Mining — — 

13 211 Oil and Gas Extraction 2 1 

14 212 Mining/Quarrying—Nonmetallic Minerals 4 — 

17 235 Construction—Special Trade Contractors 1 1 

20 311 Food and Kindred Products 38 15 

21 312 Tobacco Products 6 — 

22 313 Textile Mill Products 73 27 

23 315 Apparel and Other Products from Fabrics 3 2 

24 321 Lumber and Wood Products 175 134 

25 337 Furniture and Fixtures 100 55 

26 322 Paper and Allied Products 100 30 

27 511 Printing, Publishing, and Related Industries 3 2 

28 325 Chemicals and Allied Products 91 19 

29 324 Petroleum Refining and Related Industries 32 9 

30 326 Rubber and Misc. Plastics Products 24 4 

31 316 Leather and Leather Products 8 4 

32 327 Stone, Clay, Glass, and Concrete Products 15 3 

33 331 Primary Metal Industries 22 3 

34 332 Fabricated Metal Products 18 5 

35 333 Industrial Machinery and Computer Equip. 20 5 

36 335 Electronic and Electrical Equipment 19 — 

37 336 Transportation Equipment 26 5 

38 334 Scientific, Optical, and Photographic Equip. 9 1 

39 339 Miscellaneous Manufacturing Industries 9 1 

40 482 Railroad Transportation 1 — 

42 484 Motor Freight and Warehousing 3 1 

46 486 Pipelines, Except Natural Gas 1 — 

49 221 Electric, Gas, and Sanitary Services 95 33 

(continued) 
C-14 

Table C-7. Small Parent Companies by Industry (continued) 

SIC 

Code

NAICS 

Code Description

Number of Parent 

Companies 

Number of Small 

Parent Companies

50 421 Wholesale Trade—Durable Goods 1 — 

51 422 Wholesale Trade—Nondurable Goods 1 — 

55 441 Automotive Dealers and Gasoline Service 

Stations 

1 1 

58 722 Eating and Drinking Places — — 

59 445–454 Miscellaneous Retail 1 1 

60 522 Depository Institutions — — 

70 721 Hotels and Other Lodging Places 1 — 

72 812 Personal Services — — 

76 811 Misc. Repair Services — — 

80 621 Health Services 3 1 

81 541 Legal Services — — 

82 611 Educational Services 35 4 

83 624 Social Services 1 — 

86 813 Membership Organizations — — 

87 541 Engineering, Accounting, Research, 

Management and Related Services 

2 — 

89 711/514 Services, N.E.C. — — 

91 921 Executive, Legislative, and General 

Administration 

1 — 

92 922 Justice, Public Order, and Safety — — 

94 923 Administration of Human Resources — — 

96 926 Administration of Economic Programs 1 — 

97 928 National Security and International Affairs 2 — 

NA SIC Information Not Available 2 2 

State Parent is a State Government 11 — 

 Total 969 372 

Source: Industrial Combustion Coordinated Rulemaking (ICCR). 1998. Data/Information Submitted to the 

Coordinating Committee at the Final Meeting of the Industrial Combustion Coordinated Rulemaking 

Federal Advisory Committee. EPA Docket Numbers A-94-63, II-K-4b2 through -4b5. Research Triangle 

Park, North Carolina. September 16-17. 
C-15 

C.3.1 Small Entity Screening Results 

As shown in Table C-8, the average cost per entity is $280,000. The median cost-to-sales 

ratio is 0.8 percent, and ratios range from 0.01 to 39 percent. Forty-seven of the 372 affected 

small businesses have CSRs at or above 3 percent. 

Table C-8. Summary Statistics for SBREFA Screening Analysis 

Option 1A

Total Number of Small Entities 372 

Average Annual Compliance Cost per Small Entity ($103) $280 

Entities with Sales/Revenue Data 

 Compliance costs are <1% of sales 151 

 Compliance costs are $1 to 3% of sales 104 

 Compliance costs are $3% of sales 47 

Compliance Cost-to-Sales/Revenue Ratios 

 Average 1.744 

 Median 0.77 

 Maximum 38.83 

 Minimum 0.01 

C.3.2 Affected Government Entities: Supplemental Analysis 

As shown in Table C-9, the average total annual compliance costs per entity are $559,000 

for Option 1A. The median cost-to-revenue ratio is 1.7 percent, and ratios range from less than 

0.5 percent to 16 percent. Five of the 15 affected small governments have cost-to-revenue ratios 

at or above 3 percent. 
C-16 

Table C-9. Supplemental Screening Analysis for Small Governmental Jurisdictions 

Option 1A

Total Number of Small Entities 15 

Average Total Annual Compliance Cost (TACC) per Small Entity ($) $559 

Entities with Sales/Revenue Data 

 Compliance costs are <1% of revenue 13 

 Compliance costs are $1 to 3% of revenue 8 

 Compliance costs are $3% of revenue 5 

Compliance Cost-to-Sales/Revenue Ratios 

 Average 3.65 

 Median 1.68 

 Maximum 16.30 

 Minimum 0.02 

Source: American Public Power Association (APPA). 2002. Straight Answers to False Charges about Public 

Power. Washington, DC: APPA. <http://www.appanet.org/about/publicpower/index.cfm>. As obtained on 

November 13, 2003. 
D-1 

APPENDIX D: 

IMPACTS FROM APPLICATION OF RISK-BASED ALTERNATIVES 

As an alternative to the requirement for each large solid fuel-fired boiler to demonstrate 

compliance with the HC1 emission limit in the final rule, the source may demonstrate 

compliance with a health-based facility-wide HC1 equivalent allowable emission limit. The 

procedures for complying with this compliance alternative are in Appendix A of the final rule. 

Also, in lieu of complying with the emission standard for what are called total selected metals 

(TSM) in subpart DDDDD of part 63 based on the sum of emissions for metals (such as arsenic, 

cadmium, chromium, mercury, manganese, nickel, and lead facilities may demonstrate eligibility 

for complying with the TSM standard based on excluding manganese emissions from the 

summation of TSM emissions for the affected source unit. 

The impacts discussed below reflect the effects of compliance with both risk-based 

alternatives to the final rule. 

Per technical direction received February 5, 2004, RTI performed an economic and small 

entity sensitivity analysis of a modified emission control scenario under the Industrial Boilers 

and Process Heaters MACT. The key elements of the sensitivity scenario are as follows: 

 Exempt controls for HCL emissions for coal-fired units—(model plants 2d, 3e, 6d, 

and 7e). 

 Exempt controls for manganese emissions for wood-fired units (model plants 30a, 

30b, 34a, 34b, and 34d). 

 Monitoring, record-keeping, and reporting costs for units linked to these model plants 

remain unchanged. 

This appendix highlights the key results of these analyses. 

 Social Cost Estimates—The social cost estimates fall from $863 billion to $746 

billion, or approximately 14 percent (see Table D-1). The sensitivity analysis does not 

show significant changes in the distribution of these costs across sectors and 

stakeholders (see Table D-2). 

 Market-Level Impacts—A comparison of the relative price and quantity changes 

shows the sensitivity scenario moderates price and quantity effects, but the 

differences are very small (see Table D-3). 
D-2 

Table D-1. Social Cost Estimates ($1998 106) 

Change in Social Welfare

Baseline engineering costs $746.49 

Social costs with market adjustments $746.44 

Difference between engineering and social cost estimates $.04 

 Energy Effects—Energy impacts are small in both analyses. However, electricity and 

natural gas production/consumption impacts in the sensitivity scenario are 

approximately half the values projected under the MACT floor. Annual electricity 

production declines by 246 million kWh compared to 415 kWh. Natural gas 

production/consumption declines by 230,000 cubic feet per day compared to 1.1 

million cubic feet per day. Petroleum and coal sector effects do not significantly 

change. 

 Small Entity Impacts—The average annual control costs fall from $199K to $142K 

under the sensitivity scenario (see Table D-4). Similarly, the average (median) costto-sales ratio (CSR) falls from 0.78 percent (0.50 percent) to 0.52 percent (0.16 

percent) (see Table D-5). Twenty-two entities have CSRs greater than 1 percent under 

the sensitivity scenario compared with 34 entities under the MACT floor. Eight 

entities have CSRs that are 3 percent or higher compared to 10 entities under the 

MACT floor. 

 Affected Government Entities: Supplemental Analysis—The average annual control 

costs fall from $223K to $217K under the sensitivity scenario(see Table D-6). CSRs 

remain essentially unchanged (e.g., the average [median] CSR falls from 1.67 percent 

[0.94 percent] to 1.66 percent [0.94 percent]). As a result, there is no change in 

projections of the number of government entities affected at the 1 or 3 percent level. 
D-3 

Table D-2. Distribution of Social Costs by Sector/Market: ($1998 106) 

 Change in:

Sectors/Markets 

Producer 

Surplus

Consumer 

Surplus

Social 

Welfare

Energy Markets 

 Petroleum –$2.4 

 Natural gas $0.9 

 Electricity –$32.3 

 Coal –$2.6 

Subtotal –$36.3 

NAICS Code SIC Code Description 

311 20 (pt) Food –$21.4 –$8.6 –$30.0 

312 20 (pt); 21 Beverage and Tobacco Products –$2.1 –$3.7 –$5.8 

313 22 (pt) Textile Mills –$20.8 –$47.6 –$68.4 

314 22 (pt) Textile Product Mills –$0.1 –$0.1 –$0.2 

315 23 Apparel –$0.3 –$0.8 –$1.2 

316 31 Leather and Allied Products –$0.3 –$0.4 –$0.7 

321 24 Wood Products –$25.2 –$6.7 –$31.9 

322 26 Paper –$63.3 –$57.5 –$120.8 

323 27 Printing and Related Support –$0.2 –$0.4 –$0.5 

325 28 Chemicals –$35.5 –$71.0 –$106.5 

326 30 Plastics and Rubber Products –$2.1 –$5.0 –$7.0 

327 32 Nonmetallic Mineral Products –$2.6 –$3.1 –$5.7 

331 33 Primary Metals –$21.6 –$4.9 –$26.6 

332 34 Fabricated Metal Products –$6.3 –$1.7 –$8.0 

333 35 Machinery –$6.3 –$4.2 –$10.5 

334 36 (pt) Computer and Electronic Products –$3.2 –$1.3 –$4.5 

335 36 (pt) Electrical Equipment, Appliances, 

and Components 

–$2.4 –$1.6 –$4.1 

336 37 Transportation Equipment –$19.9 –$26.6 –$46.5 

337 25 Furniture and Related Products –$3.3 –$14.8 –$18.1 

339 39 Miscellaneous –$0.8 –$0.6 –$1.4 

11 01-08 Agricultural Sector –$0.5 –$1.2 –$1.7 

23 15-17 Construction Sector –$0.7 –$0.9 –$1.6 

21 10; 14 Other Mining Sector –$9.9 –$6.9 –$16.8 

48 40-47 (pt) Transportation –$3.5 –$3.2 –$6.7 

42; 44-45; 49; 51-56; 

61-62; 71-72; 81 

40-48 (pt); 

50-99 

Commercial –$63.7 –$84.9 –$148.6 

 Residential NA –$36.3 –$36.3 

Grand Total –$352.3 –$394.2 –$746.4 

NA = Not applicable. 

pt = Part. 
D-4 

Table D-3. Market-Level Impacts: Final Rule 

 Percent Change

Sectors/Markets Price Quantity

Energy Markets 

 Petroleum 0.001% 0.000% 

 Natural gas 0.002% 0.000% 

 Electricity 0.044% –0.010% 

 Coal –0.008% –0.010% 

NAICS Code SIC Code Description 

311 20 (pt) Food 0.004% –0.001% 

312 20 (pt); 21 Beverage and Tobacco Products 0.003% –0.004% 

313 22 (pt) Textile Mills 0.023% –0.020% 

314 22 (pt) Textile Product Mills 0.000% 0.000% 

315 23 Apparel 0.000% –0.001% 

316 31 Leather and Allied Products 0.002% –0.003% 

321 24 Wood Products 0.026% –0.005% 

322 26 Paper 0.025% –0.027% 

323 27 Printing and Related Support 0.000% 0.000% 

325 28 Chemicals 0.007% –0.011% 

326 30 Plastics and Rubber Products 0.001% –0.002% 

327 32 Nonmetallic Mineral Products 0.003% –0.002% 

331 33 Primary Metals 0.009% –0.007% 

332 34 Fabricated Metal Products 0.002% –0.000% 

333 35 Machinery 0.002% –0.001% 

334 36 (pt) Computer and Electronic Products 0.001% 0.000% 

335 36 (pt) Electrical Equipment, Appliances, and 

Components 

0.002% –0.001% 

336 37 Transportation Equipment 0.003% –0.003% 

337 25 Furniture and Related Products 0.005% –0.015% 

339 39 Miscellaneous 0.001% 0.000% 

11 01-08 Agricultural Sector 0.000% 0.000% 

23 15-17 Construction Sector 0.000% 0.000% 

21 10; 14 Other Mining Sector 0.012% –0.004% 

48 40-47 (pt) Transportation 0.001% –0.001% 

42; 44-45; 49; 51-56; 61-

62; 71-72; 81 

40-48 (pt); 50-99 Commercial 0.000% 0.000% 

pt = Part. 
D-5 

Table D-4. Summary of Small Entity Impacts 

Final Rule

Number of small entities 187

Total number of entities 576

Average annual control cost per small entity (103

) $149

 Average control cost/sales ratio 0.52%

Number of small entities with cost-to-sales ratios $1 percent 23

Number of small entities with cost-to-sales ratios $3 percent 8

Table D-5. Summary Statistics for SBREFA Screening Analysis 

Final Rule

Total Number of Small Entities 187

Average Annual Compliance Cost per Small Entity ($103) $149

Entities with Sales/Revenue Data 

 Compliance costs are <1% of sales 164

 Compliance costs are $1 to 3% of sales 15

 Compliance costs are $3% of sales 8

Compliance Cost-to-Sales/Revenue Ratios 

 Average 0.52

 Median 0.16

 Maximum 7.83

 Minimum 0.01
D-6 

Table D-6. Supplemental Screening Analysis for Small Governmental Jurisdictions 

Final Rule

Total Number of Small Entities 14

Average Total Annual Compliance Cost (TACC) per Small Entity ($103) $259

Entities with Sales/Revenue Data 

 Compliance costs are <1% of revenue 7

 Compliance costs are $1 to 3% of revenue 4

 Compliance costs are $3% of revenue 3

Compliance Cost-to-Sales/Revenue Ratios 

 Average 1.51

 Median 0.90

 Maximum 7.83

 Minimum 0.02

Source: American Public Power Association (APPA). 2002. Straight Answers to False Charges about Public 

Power. Washington, DC: APPA. <http://www.appanet.org/about/publicpower/index.cfm>. As obtained on 

November 13, 2003. 
June 2007 Office of Air Quality Planning and Standards 

Air Quality Strategies and Standards Division Research Triangle Park, NC 

United States Environmental Protection Agency 
TECHNICAL REPORT DATA

(Please read Instructions on reverse before completing)

1. REPORT NO.

 EPA-452/R-04-001 

2. 3. RECIPIENT’S ACCESSION NO.

5. REPORT DATE

June 2007 

4. TITLE AND SUBTITLE

Economic Impact Analysis of the Industrial Boilers and Process 

Heaters NESHAP 6. PERFORMING ORGANIZATION CODE

7. AUTHOR(S)

Mike Gallaher, Alan O’Connor, Brooks Depro 

8. PERFORMING ORGANIZATION REPORT NO.

RTI Project Number 0209897-001-

029 

9. PERFORMING ORGANIZATION NAME AND ADDRESS 10. PROGRAM ELEMENT NO.

RTI International 

Center for Regulatory Economics and Policy Research, Hobbs Bldg. 

Research Triangle Park, NC 27709 

11. CONTRACT/GRANT NO.

68-D-99-024 

12. SPONSORING AGENCY NAME AND ADDRESS 13. TYPE OF REPORT AND PERIOD COVERED

Director 

Office of Air Quality Planning and Standards 

Office of Air and Radiation 

U.S. Environmental Protection Agency 

Research Triangle Park, NC 27711 

14. SPONSORING AGENCY CODE

EPA/200/04 

15. SUPPLEMENTARY NOTES 

16. ABSTRACT

This report evaluates the economic impacts of the Industrial Boilers and Process Heaters 

NESHAP. The social costs of the rule are estimated by incorporating the expected costs of compliance in a 

partial equilibrium model and projecting the market impacts. The report also provides the screening analysis 

for small business impacts. 

17. KEY WORDS AND DOCUMENT ANALYSIS

a. DESCRIPTORS b. IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group

economic impacts 

small business impacts 

social costs 

Air Pollution Control 

Economic Impact Analysis 

Regulatory Flexibility Analysis 

19. SECURITY CLASS (Report)

Unclassified 

21. NO. OF PAGES

191 

18. DISTRIBUTION STATEMENT

Release Unlimited 20. SECURITY CLASS (Page)

Unclassified 

22. PRICE

EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION IS OBSOLETE