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.

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 addon 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 1 21 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 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.

1.2.4 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 cost effective 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 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 1 See 63 FR 18754, 18765 66 ( April 15, 1998) ( Pulp and Paper Combustion Sources Proposed NESHAP)

4 " Draft Revised Guidelines for Carcinogen Risk Assessment." NCEA F 0644. USEPA, Risk Assessment Forum, July 1999. pp 3 9ff. http:// www. epa. gov/ ncea/ raf/ pdfs/ cancer_ gls. pdf 1 22 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).

<IP_ADDRESS> 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. 3 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 Assessment4 suggest that carcinogens be assigned non linear dose response 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 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.

<IP_ADDRESS> Applicability Cutoffs for Hydrogen Chloride Controls Under Section 112( d)( 4)

of the CAA 1 23 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 healthbased 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.

( 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.

<IP_ADDRESS> 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 eight selected metals ( arsenic, cadmium, chromium, mercury, manganese, nickel, lead, and ), 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. 1 24 ( 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.

( 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 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 manganese equivalent 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.

1.3 Other Federal Programs There are a number of other federal programs that affect air pollutant emissions from these sources. The effects of similar federal programs are the following: 1 25

The commercial and industrial solid waste incinerators ( CISWI) standards ( in 40 CFR 60 subparts CCCC and DDDD) regulate commercial and industrial non hazardous solid waste incinerators. These standards are final as of Dec. 1, 2000. Sources subject to the CISWI rules are exempt from the requirements of this NESHAP.

The utility HAPs study Report to Congress provides information used to determine whether fossil fuel fired utility boilers should be regulated in a future MACT standard. A fossil fuelfired utility boiler is a fossil fuel fired combustion unit with a heat input greater than 25 megawatts that serves a generator producing electricity for sale. Fossil fuel fired utility boilers are exempt from this regulation. Non fossil fuel fired utility are, however, covered by this proposed standard.

EPA's Office of Solid Waste is in the process of developing MACT standards for hazardous waste boilers. Boilers burning hazardous waste are not included in this regulation.

Previously, EPA had codified new source performance standards ( NSPS) for industrial boilers in 1986 ( in 40 CFR 60 subparts Db and Dc) and revised portions of them in 1999. The NSPS regulates emissions of particulate matter ( PM), sulfur dioxide ( SO2), and nitrogen oxides ( NOx) from boilers constructed after June 19, 1984. Source subject to the NSPS are still subject to this NESHAP because the NESHAP regulates sources of hazardous air pollutants while the NSPS does not. However, in developing the NESHAP for industrial/ commercial/ institutional boilers and process heaters EPA minimized the monitoring, recordkeeping requirements, and testing requirements so as not to duplicate requirements.

1.4 Scope of the Analyses in the RIA 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 impacts of national compliance costs, including impacts to 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. EPA then estimated changes in particulate matter ( PM) concentrations associated with this regulation using an air quality model and then estimated the benefits associated with these changes in PM concentrations. To estimate the benefits, the Agency used an in house model to calculate benefits and then monetize them for emission reductions in areas where the assignment of controls to affected sources is well defined. The Agency then used a benefits transfer technique to apply the benefits estimates from reductions at sources with well defined control assignments to calculate benefits in areas where the assignment of controls is not well assigned. Finally, the Agency compared the benefits to the costs of the regulation.

Results of these analyses are presented for the final rule ( MACT floor) and Option 1A. Results of the costs and some economic impact information are presented for Option 1B. There is insufficient information for estimating the economic impacts and small entity impacts associated with Option 1B, and the benefits estimate for this option is the same as that for Option 1A since there are no additional emissions reductions expected.

1.5 Organization of the Report The remainder of this report is divided into ten chapters that describe the analysis methodologies and presents the analyses results:

Chapter 2 provides background information on boiler and process heater technologies. 1 26

Chapter 3 profiles existing boilers and process heaters by capacity, fuel type, and industry and presents projections of the future population of units in 2005.

Chapter 4 profiles the industries with the largest number of affected facilities. Included are profiles of the 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), and electrical services ( SIC 49/ NAICS 221) industries.

Chapter 5 describes the methodology for assessing the economic impacts of the National Emission Standard for Hazardous Air Pollutants ( NESHAP).

Chapter 6 presents the results of the economic analysis, including market, industry, and social cost impacts.

Chapter 7 provides the Agency's analysis of the regulation's impact on small entities.

Chapter 8 presents the Agency's analysis of the changes in air quality associated with compliance with the regulation, and a description of the emissions inventories used in the air quality analysis.

Chapter 9 presents the results of the qualitative benefits associated with implementation of this regulation.

Chapter 10 presents the results of the quantitative and monetized benefits associated with implementation of this regulation and a comparison of the benefits to the costs of the rule.

In addition to these chapters, there are five appendicies as well. Appendix A provides information on the databases and equations used in the economic impact analysis, and Appendix B provides details on assumptions behind the operation of the economic model, along with results of sensitivity analyses. Appendix C provides some results from the air quality modeling conducted to determine reductions in concentrations of PM associated with the emissions reductions expected to take place. These results are for the above the floor option 1A only. Appendix D contains the results of sensitivity analyses and alternative calculations for our benefits estimates. Finally, Appendix E contains impact estimates associated with the health based compliance alternatives for HCl and Mn sources. 1 27 References Federal Register, 1993. Executive Order 12866, Regulatory Planning and Review. Vol. 58, October 4, 1993, pg. 51735.

Federal Register, 2001. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use. Vol. 66, May 22, 2001, pg. 28355.

Federal Register, 2002. Executive Order 13258, Amending Executive Order 12866  Regulatory Planning and Review. Vol. 67 , February 28, 2002, pg. 9385.

U. S. Environmental Protection Agency, 1996. Guidance for Providing Environmental Justice Concerns in EPA's NEPA Compliance Analyses ( Review Draft). Office of Federal Activities, Washington, D. C., July 12, 1996.

U. S. Environmental Protection Agency, 1996. Memorandum from Trovato and Kelly to Assistant Administrators. Subject: " Implementation of Executive Order 13045, Protection of Children from Environmental Health and Safety Risks." April 21, 1998. 2 1 CHAPTER 2 BOILER AND PROCESS HEATER TECHNOLOGIES The three categories of combustion devices affected under the regulations are industrial boilers, 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 chapter. This chapter 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 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. 2 2 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 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).

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 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 steampowered to electricity powered machinery would require significant equipment retrofits or replacement. 2 3 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>.

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 This section 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 2 4 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. Five hundred ninety three of the 3,615 units potentially affected by the floor alternative for the proposed regulation are commercial/ institutional units.

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.

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, fielderected 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. 1 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 theNESHAP. 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.

<IP_ADDRESS> 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:

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 5 <IP_ADDRESS> 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 <IP_ADDRESS> and <IP_ADDRESS>.

<IP_ADDRESS> 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.

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.

<IP_ADDRESS> 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.

<IP_ADDRESS> 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 wallfired 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 6 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 proposed 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., steam hydrocarbon 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 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 <IP_ADDRESS> through <IP_ADDRESS> describe combustion chambers setups, combustion air supply, tube configurations, and burners, respectively.

<IP_ADDRESS> 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 2 7 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).

<IP_ADDRESS> 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) 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 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.

<IP_ADDRESS> 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 case by case basis 2 8 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.

<IP_ADDRESS> 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.

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 9 References U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 1993. Alternative Control Techniques Document  NOx Emissions from Process Heaters ( Revised). Research Triangle Park, NC.

U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 1997. Regulatory Impact Analysis of Air Pollution Regulations: Utility and Industrial Boilers. Research Triangle Park, NC.

Fleming, Ian. 1992. " Just How Clean is your Steam? Minimizing Risk of Product Contamination and Prolonging Filter Life." Manufacturing Chemist 63( 10): pp. 37 39.

Plant Engineering. 1991. " Boiler Systems." Plant Engineering 45( 14): pp. 92 94.

Texas Utilities ( TXU). 2000. " Generating Electricity: Steam Turbines." As obtained in September 2000. Found on the Internet at http:// www. txu. com/ knowledge/ energy_ lib/ generating01. html.

CHAPTER 3 PROFILE OF AFFECTED UNITS AND FACILITIES, AND COMPLIANCE COSTS 3 1 The floor level MACT, which is the final industrial boilers and process heaters rule 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. In addition, two above the floor alternatives were investigated at proposal, Options 1A and 1B. 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. Option 1B further expands the affected population to include all distillate fuel oil and natural gas fueled units. Although descriptive statistics on the Option 1B population are included in this section, this alternative was not analyzed for this RIA. More information on these options can be found in the preamble to the proposed regulation.

The economic impact estimates presented in Chapter 6 and the small entity screening analysis presented in Chapter 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 the applying a regulatory alternative to these units. This chapter 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 costeffectiveness ( cost/ ton) estimates by pollutant controlled.

3.1 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. 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 about 4,000 are estimated to be affected by the floor alternative. Of these existing units, a little over half had sufficient information on operating parameters to be included in the floor level EIA. The number of potentially affected units included in the profile for the floor alternative was 2,186. The number of units included in the profile was 3,580 for Option 1A and 22,117 for Option 1B.

3.1.1 Distribution of Existing Boilers and Facilities by Industry Tables 3 1 through 3 3 present 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 floor or above the floor alternatives. For the floor alternative, 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. ( Chapter 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. The distribution of units affected by the Option 1A alternative is similar to that for the floor alternative, although both the number of units and the number of facilities is greater for the Option 1A alternative. For Option 1B, the industries with the greatest number of units shifts to oil and gas exploration, chemical and transportation equipment manufacturing, and petroleum refining.

3.1.2 Technical Characteristics of Existing Boilers 3 2 Figure 3 1 characterizes the population of 2,186 ( 3,580; 22,117) units identified in the Inventory Database by capacity range, fuel type, and level of preexisting control for each alternative. Throughout most of this section, the values in the text are for the MACT floor alternative. Those for the above the floor alternatives follow in parentheses, first for Option 1A then for Option 1B. 3 3 Table 3 1. Units and Facilities Affected by the Floor Alternative 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 42 484 Motor Freight and Warehousing 5 0 5 1 46 486 Pipelines, Except Natural Gas 0 0 0 0 ( continued) 3 4 Table 3 1. Units and Facilities Affected by the Floor Alternative by Industrya ( continued)

SIC Code NAICS Code Description Boilers Heaters Total Units Facilities 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 5 Table 3 2. 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 ( continued) 3 6 Table 3 2. Units and Facilities Affected by the Option 1A Alternative by Industrya ( continued)

SIC Code NAICS Code Description Boilers Heaters Total Units Facilities 49 221 Electric, Gas, and Sanitary Services 371 1 372 185 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 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. 3 7 Table 3 3. Units and Facilities Affected by the Option 1B Alternative by Industrya SIC Code NAICS Code Description Boilers Heaters Total Units Facilities 01 111 Agriculture   Crops 7 0 7 6 02 112 Agriculture   Livestock 6 0 6 1 07 115 Agricultural Services 3 0 3 1 10 212 Metal Mining 55 6 61 20 12 212 Coal Mining 20 6 26 5 13 211 Oil and Gas Extraction 497 657 1,154 371 14 212 Mining/ Quarrying   Nonmetallic Minerals 48 1 49 19 17 235 Construction   Special Trade Contractors 2 0 2 1 20 311 Food and Kindred Products 441 3 444 145 21 312 Tobacco Products 69 0 69 30 22 313 Textile Mill Products 755 6 761 347 23 315 Apparel and Other Products from Fabrics 4 0 4 4 24 321 Lumber and Wood Products 561 40 601 412 25 337 Furniture and Fixtures 499 10 509 297 26 322 Paper and Allied Products 981 0 981 493 27 511 Printing, Publishing, and Related Industries 333 3 336 134 28 325 Chemicals and Allied Products 2,265 415 2,680 913 29 324 Petroleum Refining and Related Industries 322 729 1,051 184 30 326 Rubber and Miscellaneous Plastics Products 508 36 544 268 31 316 Leather and Leather Products 91 2 93 44 32 327 Stone, Clay, Glass, and Concrete Products 423 13 436 184 33 331 Primary Metal Industries 754 197 951 314 34 332 Fabricated Metal Products 771 102 873 388 35 333 Industrial Machinery and Computer Equipment 402 19 421 191 36 335 Electronic and Electrical Equipment 430 13 443 203 37 336 Transportation Equipment 803 207 1,010 291 38 334 Scientific, Optical, and Photographic Equip. 180 2 182 71 39 339 Miscellaneous Manufacturing Industries 123 36 159 65 40 482 Railroad Transportation 4 0 4 1 42 484 Motor Freight and Warehousing 5 2 7 3 46 486 Pipelines, Except Natural Gas 8 3 11 7 ( continued) 3 8 Table 3 3. Units and Facilities Affected by the Option 1B Alternative by Industrya ( continued)

SIC Code NAICS Code Description Boilers Heaters Total Units Facilities 49 221 Electric, Gas, and Sanitary Services 1,227 140 1,367 615 50 421 Wholesale Trade   Durable Goods 4 0 4 2 51 422 Wholesale Trade   Nondurable Goods 2 0 2 1 55 441 Automotive Dealers and Gasoline Service Stations 0 2 2 2 58 722 Eating and Drinking Places 0 3 3 1 60 522 Depository Institutions 3 0 3 1 59 445   454 Miscellaneous Retail 1 0 1 1 70 721 Hotels and Other Lodging Places 3 0 3 2 72 812 Personal Services 2 0 2 1 76 811 Miscellaneous Repair Services 58 0 58 28 80 621 Health Services 27 0 27 25 81 541 Legal Services 2 0 2 0 82 611 Educational Services 144 0 144 57 83 624 Social Services 4 0 4 2 86 813 Membership Organizations 1 0 1 1 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 7 0 7 5 92 922 Justice, Public Order, and Safety 36 0 36 10 94 923 Administration of Human Resources 2 0 2 2 96 926 Administration of Economic Programs 11 0 11 5 97 928 National Security and International Affairs 51 3 54 15 NA SIC Information Not Available 6,163 335 6,498 2,378 19,126 2,991 22,117 8,573 a Based on the Inventory Database. 3 9 Input Capacity ( million Btu) Preexisting Control Technology Fuel Type Coal 31%

Coal and Wood 5% Wood 18% Other 3% Other Biomass 9% Bagasse 2% > 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%

Input Capacity ( million Btu) Preexisting Control Technology Fuel Type Cyclone 5%

No Control 88% Wet Scrubber 2% Fabric Filter 3% ESP 3%

Coal 5%

Natural Gas 78% Distillate Fuel Oil 6% Residual Fuel Oil 5% Wood, Bagasse, and Other 6% 0 to 10 1% Floor Alternative ( n= 2,186)

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%

Option 1B Alternative ( n= 22,117)

> 250 5%

10 to 100 36% 100 to 250 7% 0 to 10 52%

Figure 3 1. Characteristics of Units Affected by Alternatives 3 10 <IP_ADDRESS> Floor Alternative

Capacity Range: Unit input capacities in the population are expressed in four ranges: 0   10, 10   100, 100   250, and > 250 MMBtu/ hr. Fifty two 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: Eighty three percent of units have some type of control device already installed; 289 do not. Typical control devices include fabric filters, wet scrubbers, and electrostatic precipitators.

<IP_ADDRESS> Option 1A Alternative

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.

<IP_ADDRESS> Option 1B Alternative

Capacity Range: More than half of the 22,117 units affected by the Option 1B alternative have input capacities less than 10 MMBtu/ hr. Thirty six percent have input capacities between 10 and 100 MMBtu/ hr. The remaining 12 percent have input capacities in excess of 100 MMBtu/ hr.

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.

3.2 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, which is the proposed alternative, as well as other alternatives, are 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. 3 11 Components of capital cost include:

S purchased equipment cost of the primary device and auxiliary equipment,

S instrumentation,

S sales tax and freight, and S 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.

Components of annual cost include:

S raw materials,

S utilities ( electricity, fuel, steam, air, water),

S waste treatment and disposal,

S labor ( operating, supervisory, maintenance),

S maintenance materials,

S replacement parts,

S overhead,

S property taxes,

S insurance,

S administration charges, and S 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 appendicies 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.

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 3 12 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 website( 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.

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 judgement 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. 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 13 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 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 rule includes emission limits for HCl, PM, metallic HAP, and mercury. Additionally, as mentioned in Chapter 1 of this RIA 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 4. 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.

Table 3 4. Testing and Monitoring Costs for Units Covered by the Proposed Rule 3 14 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 ($) Annual Capital Recovery  Testing and Monitoring ( 1999$) Total Annual Costs of Testing and Monitoring ( 1999$)

Regular Use Units Coal 2,328 0 151,169,238 63,608,655 59,828,340 8,265,169 123,436,995 Coal/ Wood/ NFFa Liquid/ NFF Solid 169 0 8,847,579 2,444,456 1,302,784 280,698 3,747,240 Gas 30,473 13,481 0 0 0 0 0 Gas/ Wood/ Other Biomass/ Liquid FF 201 0 9,831,749 2,909,994 2,327,840 447,120 5,237,834 Distillate Liquid FF 2,921 353 0 0 0 0 0 NFF Liquid/ NFF Solid/ Gas 115 11 7,452,131 3,074,918 2,930,348 404,077 6,005,266 Wood 663 42 26,446,200 5,268,614 6,392,240 1,411,706 11,660,854 Wood/ Other Biomass/ NFF Liquid/ NFF Solid 147 0 8,180,852 3,003,146 2,001,492 299,112 5,004,638 Residual Liquid FF 2,036 674 0 0 0 0 0 Bagasse/ Other 132 0 5,821,106 490,000 2,891,728 412,546 3,381,728 Total for Regular Use Units 39,185 14,561 217,748,855 80,799,783 77,674,772 11,520,428 158,114,555 Limited Use Units Coal 198 0 6,427,715 1,584,000 1,716,416 457,169 3,330,416 Coal/ Wood/ NFF Liquid/ NFF Solid 4 0 119,600 32,000 29,772 8,268 61,772 Gas 2,314 624 0 0 0 0 0 Gas/ Wood/ Other Biomass/ Liquid FF 8 0 290,366 64,000 105,020 21,366 169,020 Distillate Liquid FF 672 31 0 0 0 0 0 NFF Liquid/ NFF Solid/ Gas 4 1 156,800 40,000 39,696 11,024 79,696 Wood 28 0 1,074,549 224,000 331,200 80,279 555,200 Wood/ Other Biomass/ NFF Liquid/ NFF Solid 6 0 194,000 48,000 49,620 13,780 97,620 Residual Liquid FF 533 31 0 0 0 0 0 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 ($) Annual Capital Recovery  Testing and Monitoring ( 1999$) Total Annual Costs of Testing and Monitoring ( 1999$)

3 15 Total for Limited Use Units 3,767 687 8,263,030 1,992,000 2,271,724 591,886 4,263,724 Grand Total 42,952 15,248 226,011,885 82,791,783 79,946,496 12,112,314 162,738,279 a NFF = costs for units that are not fossil fueled; FF = units that are fossil fueled.

Costs to Control Non Air Effects Related to Rule Implementation The EPA 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 EPA 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 Uncertainties The primary limitation to the cost estimates developed for the proposed 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 proposed 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.

3.3 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%), natural gas ( 6.3%), residual fuel oil ( 7.4%), distillate fuel oil ( 12.0%), and biomass ( 11.5%). It should be noted that 1998 was a 3 16 Number of New Units

Total energy consumed ( 2005) [ MMBtu/ yr]

Avg capacity [ MMBtu/ hr] × 8,760 [ hr/ yr]   Number of Units ( 1998) 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.

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:

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 and the Option 1A alternative. 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 6 presents the projected number of new boilers and process heaters for the MACT floor and Option1A above the floor alternatives. 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). New source estimates by industry were not developed for the Option 1B above the floor alternative.

3.4 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 floor alternative and 9,163 units may be affected by the Option 1A above the floor alternative. These populations were used to estimate national engineering costs. The population estimates were determined by unit configuration, not by industry. Thus, the distribution of units by industry shown in Tables 3 6 and 3 7 was determined by weighting existing units by the estimates by unit configuration and tallying weighted units by SIC code. The average cost of control by unit configuration was multiplied by the weighted number of units to determine industry level control cost estimates.

Table 3 8 presents industry level population and cost estimates for boilers and process heaters for both the floor and above the floor alternatives. 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 $ 863.0 million, with an average per unit additional control cost of $ 155,157. The Option 1A cost of control for the 9,163 potentially affected units is $ 1,995.8 million, with an average per unit cost of $ 217,811.

The Agency estimates that Option 1B will potentially affect 62,215 boilers and process heaters. The Option 1B cost of control for the 62,215 potentially affected units is $ 2,944.8 million. Option 1B costs are not presented by industry because approximately one third of the units did not have SIC code ( and, hence, no NAICS code) information. 3 17 To provide additional information on the magnitude of the cost estimates, Table 3 5 shows the cost effectiveness ( cost/ ton reduced estimates) for the HAP and non HAP pollutants whose emissions are reduced by this rule.

Table 3 5. 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 ($) 833,273,781b 810,422,230 669,353,690 141,068,540 22,851,551 PM Emissions Reduction ( Tons/ Year) 565,900 563,060 359,920 203,140 2,840 C/ E ($/ ton PM) 1,472a 1,439 1,860 694 8,046 Metals Emissions Reduction ( Tons/ Year) 1,093 1,087 591 496 6 C/ E ($/ ton metals) 762,373a 745,558a 1,132,578a 284,412a 3,808,592a HCl Emissions Reduction ( Tons/ Year) 46,515 46,515 45,136 1,379  3 18 C/ E ($/ ton HCl) 17,914a 17,422a 14,830a 102,298a

HAP Emissions Reduction ( Tons/ Year) 47,608 47,602 45,727 1,875 6 C/ E ($/ ton HAP) 17,502 17,025 14,638 75,236 3,808,500 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 19 Table 3 6. New Unit Projections by Industry, MACT Floor and Option 1A Alternatives SIC Code NAICS Code Floor Alternative Option 1A Alternative Description New Units Cost New Units Cost 01 111 Agriculture   Crops         02 112 Agriculture   Livestock         07 115 Agricultural Services         10 212 Metal Mining 6 $ 47,040 6 $ 47,040 12 212 Coal Mining 1 $ 7,840 1 $ 7,840 13 211 Oil and Gas Extraction 89 $ 697,760 89 $ 697,760 14 212 Mining/ Quarrying   Nonmetallic Minerals 6 $ 87,740 6 $ 87,740 17 235 Construction   Special Trade Contractors         20 311 Food and Kindred Products 63 $ 801,836 63 $ 11,170,93 1 21 312 Tobacco Products 7 $ 54,880 7 $ 54,880 22 313 Textile Mill Products 73 $ 1,329,391 73 $ 1,463,682 23 315 Apparel and Other Products from Fabrics         24 321 Lumber and Wood Products 61 $ 1,748,655 61 $ 10,621,23 2 25 337 Furniture and Fixtures 47 $ 1,354,701 47 $ 4,306,979 26 322 Paper and Allied Products 96 $ 1,526,704 96 $ 15,984,33 2 27 511 Printing, Publishing, and Related Industries 19 $ 148,960 19 $ 148,960 28 325 Chemicals and Allied Products 295 $ 3,793,738 295 $ 3,883,243 29 324 Petroleum Refining and Related Industries 198 $ 1,552,320 198 $ 1,552,320 30 326 Rubber and Miscellaneous Plastics Products 44 $ 385,660 44 $ 385,660 31 316 Leather and Leather Products 5 $ 39,200 5 $ 39,200 32 327 Stone, Clay, Glass, and Concrete Products 37 $ 549,975 37 $ 549,975 33 331 Primary Metal Industries 80 $ 2,873,492 80 $ 2,873,492 34 332 Fabricated Metal Products 53 $ 496,920 53 $ 496,920 35 333 Industrial Machinery and Computer Equipment 35 $ 396,500 35 $ 396,500 36 335 Electronic and Electrical Equipment 40 $ 313,600 40 $ 313,600 37 336 Transportation Equipment 80 $ 1,133,423 80 $ 1,357,219 38 334 Scientific, Optical, and Photographic Equipment 11 $ 86,240 11 $ 86,240 39 339 Miscellaneous Manufacturing Industries 9 $ 162,323 9 $ 254,722 40 482 Railroad Transportation         42 484 Motor Freight and Warehousing 1 $ 48,540 1 $ 48,540 ( continued) 3 20 Table 3 6. New Unit Projections by Industry, MACT Floor and Option 1A Alternatives ( continued)

SIC Code NAICS Code Floor Alternative Option 1A Alternative Description New Units Cost New Units Cost 46 486 Pipelines, Except Natural Gas 1 $ 7,840 1 $ 7,840 49 221 Electric, Gas, and Sanitary Services 134 $ 2,094,546 134 $ 10,490,757 50 421 Wholesale Trade   Durable Goods         51 422 Wholesale Trade   Nondurable Goods         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 1 $ 7,840 76 811 Miscellaneous Repair Services         80 621 Health Services 6 $ 209,840 6 $ 209,840 81 541 Legal Services         82 611 Educational Services 19 $ 815,855 19 $ 815,855 83 624 Social Services         86 813 Membership Organizations         87 541 Engineering, Accounting, Research, Management and Related Services 2 $ 388,350 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 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 2 $ 97,080 NA SIC Information Not Available 307 $ 2,497,327 307 $ 2,586,832 State Parent is a State Government         1,832 $ 25,909,574 1,832 $ 71,586,861 3 21 Table 3 7. Unit Cost and Population Estimates for the Floor Alternative by Industry, 2005 SIC Code NAICS Code Total Units Total Cost Description Floor Units Percent Floor Costs ( by Unit) Percent 01 111 Agriculture   Crops 5 0.08% $ 628,943 0.07% 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 0.77% 12 212 Coal Mining 6 0.10% $ 683,026 0.08% 13 211 Oil and Gas Extraction 89 1.60% $ 697,760 0.08% 14 212 Mining/ Quarrying   Nonmetallic Minerals 25 0.46% $ 8,253,479 0.96% 17 235 Construction   Special Trade Contractors   0.00%   0.00% 20 311 Food and Kindred Products 312 5.60% $ 37,774,020 4.38% 21 312 Tobacco Products 28 0.51% $ 6,014,216 0.70% 22 313 Textile Mill Products 360 6.47% $ 74,152,804 8.59% 23 315 Apparel and Other Products from Fabrics 4 0.08% $ 679,510 0.08% 24 321 Lumber and Wood Products 483 8.68% $ 48,896,055 5.67% 25 337 Furniture and Fixtures 311 5.59% $ 29,632,880 3.43% 26 322 Paper and Allied Products 565 10.15% $ 123,008,263 14.25% 27 511 Printing, Publishing, and Related Industries 19 0.34% $ 148,960 0.02% 28 325 Chemicals and Allied Products 644 11.58% $ 116,236,183 13.47% 29 324 Petroleum Refining and Related Industries 217 3.91% $ 4,620,563 0.54% 30 326 Rubber and Miscellaneous Plastics Products 73 1.32% $ 6,356,835 0.74% 31 316 Leather and Leather Products 7 0.13% $ 607,530 0.07% 32 327 Stone, Clay, Glass, and Concrete Products 57 1.02% $ 6,253,678 0.72% 33 331 Primary Metal Industries 159 2.85% $ 27,110,619 3.14% 34 332 Fabricated Metal Products 87 1.56% $ 10,042,680 1.16% 35 333 Industrial Machinery and Computer Equipment 84 1.51% $ 11,208,392 1.30%

36 335 Electronic and Electrical Equipment 52 0.93% $ 3,744,828 0.43% 37 336 Transportation Equipment 300 5.39% $ 55,440,341 6.42% 38 334 Scientific, Optical, and Photographic Equipment 26 0.46% $ 3,511,206 0.41%

39 339 Miscellaneous Manufacturing Industries 12 0.22% $ 826,346 0.10% 40 482 Railroad Transportation 9 0.16% $ 1,251,062 0.14% 42 484 Motor Freight and Warehousing 12 0.22% $ 2,128,148 0.25%

( continued) 3 22 Table 3 7. Unit Cost and Population Estimates for the Floor Alternative by Industry, 2005 ( continued)

SIC Code NAICS Code Total Units Total Cost Description Floor Units Percent Floor Costs ( by Unit) Percent 46 486 Pipelines, Except Natural Gas 1 0.02% $ 7,840 0.00%

49 221 Electric, Gas, and Sanitary Services 718 12.91% $ 150,341,645 17.42%

50 421 Wholesale Trade   Durable Goods 6 0.12% $ 2,154,760 0.25%

51 422 Wholesale Trade   Nondurable Goods 4 0.07% $ 1,673,511 0.19%

55 441 Automotive Dealers and Gasoline Service Stations   0.00%   0.00%

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 0.07%

72 812 Personal Services 1 0.02% $ 7,840 0.00%

76 811 Miscellaneous Repair Services 4 0.08% $ 625,531 0.07%

80 621 Health Services 86 1.55% $ 15,172,212 1.76%

81 541 Legal Services   0.00%   0.00%

82 611 Educational Services 251 4.52% $ 60,490,956 7.01%

83 624 Social Services 5 0.08% $ 820,191 0.10%

86 813 Membership Organizations   0.00%   0.00%

87 541 Engineering, Accounting, Research, Management and Related Services 38 0.68% $ 2,240,544 0.26%

89 711/ 514 Services, N. E. C. 2 0.04% $ 918,360 0.11%

91 921 Executive, Legislative, and General Administration 2 0.04% $ 312,765 0.04%

92 922 Justice, Public Order, and Safety 69 1.23% $ 13,707,649 1.59%

94 923 Administration of Human Resources 2 0.04% $ 314,316 0.04%

96 926 Administration of Economic Programs 8 0.15% $ 2,300,308 0.27%

97 928 National Security and International Affairs 64 1.16% $ 18,018,010 2.09%

NA SIC Information Not Available 326 5.86% $ 6,747,652 0.78%

State Parent is a state government   0.00%   0.00%

5,562 $ 862,981,906 3 23 Table 3 8. Unit Cost and Population Estimates for the Option 1A Above the Floor Alternative by Industry, 2005 SIC Code NAICS Code Total Units Total Cost 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% 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%

( continued) 3 24 Table 3 8. Unit Cost and Population Estimates for the Option 1A Above the Floor Alternative by Industry, 2005 ( continued)

SIC Code NAICS Code Total Units Total Cost Description Option 1A Units Percent Option 1A Costs ( by Unit) Percent 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 4 25 References Eastern Research Group. Memorandum to Jim Eddinger, U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Development of the Population Database for the Industrial/ Commercial/ Institutional Boiler and Indirect Fired Process Heater National Emission Standard for Hazardous Air Pollutants ( NESHAP). May 18, 2000.

Eastern Research Group. Memorandum to Jim Eddinger, U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Development of Model Units for the Industrial/ Commercial/ Institutional Boiler and Indirect Fired Process Heater National Emission Standard for Hazardous Air Pollutants ( NESHAP). July, 2000.

U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Industrial Combustion Coordinated Rulemaking, Inventory Database V4.1 Boilers. February 26, 1999.

U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards. Industrial Combustion Coordinated Rulemaking, Inventory Database V4  Process Heaters. November 13, 1998.

CHAPTER 4 PROFILES OF AFFECTED INDUSTRIES 4 1 This chapter contains profiles of the major industries affected by the MACT for industrial 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.

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. 4 2 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.

4.2.1 Supply Side of the Industry This section describes the lumber industry's production processes, output, costs of production, and capacity utilization.

<IP_ADDRESS> 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 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 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.

<IP_ADDRESS> 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 intermediate goods; they are purchased by other industries and incorporated into higher value added 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.

<IP_ADDRESS> 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.

<IP_ADDRESS> 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.

<IP_ADDRESS> 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.

4.2.2 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 4 4 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.

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. Table 4 3. Inputs for the Lumber and Wood Products Industry ( SIC 24/ NAICS 321), 1987   1996 Year Labor Materials ( 1992 $ 106) New Capital Investment ( 1992 $ 106) Quantity ( 103) Payroll ( 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. 4 5 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 noresidential 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 less competitive 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 Herfindahl Hirschmann 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 4 6 criteria for doing so based on HHIs. According to these criteria, industries with HHIs below 1,000 are 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. 4 7 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) ( 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).

4.3 Furniture and Related Product Manufacturing ( SIC 25/ NAICS 337) Table 4 6. Measures of Market Concentration for Lumber and Wood Products Markets SIC Description CR4 CR8 HHI Number of Companie s Number of Facilities 2421 Saw Mills and Planing Mills 14 20 78 5,302 6004 2434 Wood Kitchen Cabinets 19 25 156 4,303 4323 2449 Wood Containers, N. E. C. 34 47 414 217 225 2491 Wood Preserving 17 28 152 408 486 2493 Reconstituted Wood Products 50 66 765 193 288 2499 Wood Products, N. E. C. 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 8 More than 20,000 establishments in the United States produce furniture and furniture related 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).