# Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A05-2996 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** February 28, 2005 - **Citation:** 70 FR 9706 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 60 [OAR-2005-0031; FRL-7873-8] RIN 2060-AM80 Standards of Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed amendments. SUMMARY: Pursuant to section 111(b)(1)(B) of the Clean Air Act (CAA), the EPA has reviewed the emission standards for particulate matter (PM), sulfur dioxide (SO 2 ), and nitrogen oxides (NO X ) contained in the standards of performance for electric utility steam generating units, industrial-commercial-institutional steam generating units, and small industrial-commercial-institutional steam generating units. This action presents the results of EPA's review and proposes amendments to standards consistent with those results. Specifically, we are proposing amendments to the PM, SO 2 , and NO X emission standards. We are also proposing to replace the current percent reduction requirement for SO 2 with an output-based SO 2 emission limit. We are also proposing an amendment to the PM emission limit. In addition to amending the emissions limits, we also are proposing several technical clarifications and corrections to existing provisions of the current rules. DATES: Comments on the proposed amendments must be received on or before April 29, 2005. Public Hearing: If anyone contacts EPA by March 21, 2005, requesting to speak at a public hearing, EPA will hold a public hearing on March 30, 2005. Persons interested in attending the public hearing should contact Ms. Eloise Shepherd at (919) 541-5578 to verify that a hearing will be held. ADDRESSES: Submit your comments, identified by Docket ID No. OAR-2005-0031, by one of the following methods: Federal eRulemaking Portal: http://www.regulations.gov . Follow the on-line instructions for submitting comments. Agency Web site: http://www.epa.gov/edocket . EDOCKET, EPA's electronic public docket and comment system, is EPA's preferred method for receiving comments. Follow the on-line instructions for submitting comments. E-mail: Send your comments via electronic mail to a-and-r-docket@epa.gov , Attention Docket ID No. OAR-2005-0031. By Facsimile: Fax your comments to (202) 566-1741, Attention Docket ID No. OAR-2005-0031. Mail: Send your comments to: EPA Docket Center (EPA/DC), Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania Ave., NW., Washington, DC 20460, Attention Docket ID No. OAR-2005-0031. Please include a total of two copies. The EPA requests a separate copy also be sent to the contact person identified below ( see FOR FURTHER INFORMATION CONTACT ). In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503. Hand Delivery: Deliver your comments to: EPA Docket Center (EPA/DC), EPA West Building, Room B108, 1301 Constitution Ave., NW., Washington, DC, Attention Docket ID No. OAR-2005-0031. Such deliveries are accepted only during the normal hours of operation (8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays), and special arrangements should be made for deliveries of boxed information. Instructions: Direct your comments to Docket ID No. OAR-2005-0031. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.epa.gov/edocket , including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through EDOCKET, regulations.gov, or e-mail. The EPA EDOCKET and the Federal regulations.gov Web sites are “anonymous access” systems, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through EDOCKET or regulations.gov , your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Public Hearing: If a public hearing is held, it will be held at EPA's Campus located at 109 T.W. Alexander Drive in Research Triangle Park, NC, or an alternate site nearby. Docket: All documents in the docket are listed in the EDOCKET index at http://www.epa.gov/edocket . Although listed in the index, some information is not publicly available, i.e. , CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically in EDOCKET or in hard copy at the EPA Docket Center (EPA/DC), EPA West Building, Room B102, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the EPA Docket Center is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: Mr. Christian Fellner, Combustion Group, Emission Standards Division (C439-01), U.S. EPA, Research Triangle Park, North Carolina 27711, (919) 541-4003, e-mail fellner.christian@epa.gov . SUPPLEMENTARY INFORMATION: Organization of This Document . The following outline is provided to aid in locating information in this preamble. I. General Information A. Does this action apply to me? B. What should I consider as I prepare my comments for EPA? II. Background Information A. What is the statutory authority for the proposed amendments? B. What is the role of the NSPS program? III. Summary of the Proposed Amendments A. What are the requirements for new electric utility steam generating units (40 CFR part 60, subpart Da)? B. What are the requirements for industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db)? C. What are the requirements for small industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Dc)? IV. Rationale for the Proposed Amendments A. What is the performance of control technologies for steam generating units? B. Regulatory Approach C. How did EPA determine the amended standards for electric utility steam generating units (40 CFR part 60, subpart Da)? D. How did EPA determine the amended standards for industrial-commercial-institutional steam generating units (40 CFR part 60, subparts Db and Dc)? E. What technical corrections is EPA proposing? V. Modification and Reconstruction Provisions VI. Summary of Cost, Environmental, Energy, and Economic Impacts A. What are the impacts for electric utility steam generating units? B. What are the impacts for industrial, commercial, institutional boilers? C. Economic Impacts VII. Request for Comments VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045: Protection of Children from Environmental Health and Safety Risks H. Executive Order 13211: Actions that Significantly Affect Energy Supply, Distribution or Use I. National Technology Transfer Advancement Act I. General Information A. Does This Action Apply to Me? Regulated Entities . Categories and entities potentially regulated by the proposed amendments are new electric utility steam generating units and new, reconstructed, and modified industrial-commercial-institutional steam generating units. The proposed amendments would affect the following categories of sources: Category NAICS code SIC code Examples of potentially regulated entities Industry 221112 Fossil fuel-fired electric utility steam generating units. Federal Government 22112 Fossil fuel-fired electric utility steam generating units owned by the Federal Government. State/local/tribal government 22112 Fossil fuel-fired electric utility steam generating units owned by municipalities. 921150 Fossil fuel-fired electric steam generating units in Indian Country. Any industrial-commercial-institutional facility using a boiler as defined in CFR 60.40b or CFR 60.40c 211 13 Extractors of crude petroleum and natural gas. 321 24 Manufacturers of lumber and wood products. 322 26 Pulp and paper mills. 325 28 Chemical manufacturers. 324 29 Petroleum refiners and manufacturers of coal products. 316, 326, 339 30 Manufacturers of rubber and miscellaneous plastic products. 331 33 Steel works, blast furnaces. 332 34 Electroplating, plating, polishing, anodizing, and coloring. 336 37 Manufacturers of motor vehicle parts and accessories. 221 49 Electric, gas, and sanitary services. 622 80 Health services. 611 82 Educational Services. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be subjected to the proposed amendments. To determine whether your facility may be subject to the proposed amendments, you should examine the applicability criteria in 40 CFR part 60, sections 60.40a, 60.40b, or 60.40c. If you have any questions regarding the applicability of the proposed amendments to a particular entity, contact the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. B. What Should I Consider as I Prepare My Comments for EPA? 1. Submitting CBI . Do not submit information that you consider to be confidential business information (CBI) electronically through EDocket, regulations.gov, or e-mail. Send or deliver information identified as CBI only to the following address: Mr. Christian Fellner, c/o OAQPS Document Control Officer (Room C404-02), U.S. EPA, Research Triangle Park, 27711, Attention Docket ID No. OAR-2005-0031. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section. 2. Tips for Preparing Your Comments. When submitting comments, remember to: a. Identify the proposed amendments by docket number and other identifying information (subject heading, Federal Register date and page number). b. Follow directions. The EPA may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number. c. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes. d. Describe any assumptions and provide any technical information and/ or data that you used in formulating your comments. e. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced. f. Provide specific examples to illustrate your concerns, and suggest alternatives. g. Explain your views as clearly as possible, avoiding the use of profanity or personal threats. h. Make sure to submit your comments by the comment period deadline identified. Docket . The docket number for the proposed amendments to the standards of performance (40 CFR part 60, subpart Da, Db, and Dc) is Docket ID No. OAR-2005-0031. Other dockets incorporated by reference for the standards of performance include Docket ID Nos. A-79-02, A-83-27, A-86-02, and A-92-71. Worldwide Web (WWW) . In addition to being available in the docket, an electronic copy of the proposed amendments is available on the WWW through the Technology Transfer Network (TTN). Following signature, EPA will post a copy of the proposed amendments on the TTN's policy and guidance page for newly proposed or promulgated amendments at http://www.epa.gov/ttn/oarpg . The TTN provides information and technology exchange in various areas of air pollution control. If more information regarding the TTN is needed, call the TTN Help line at (919) 541-5384. II. Background Information A. What Is the Statutory Authority for the Proposed Amendments? New source performance standards (NSPS) implement CAA section 111(b), and are issued for categories of sources which cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. Section 111 of the CAA requires that NSPS reflect the application of the best system of emissions reductions which (taking into consideration the cost of achieving such emissions reductions, any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. This level of control is commonly referred to as best demonstrated technology (BDT). The current standards for steam generating units are contained in the NSPS for electric utility steam generating units (40 CFR part 60, subpart Da), industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db), and small industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Dc). The NSPS for electric utility steam generating units (40 CFR part 60, subpart Da) were originally promulgated on June 11, 1979 (44 FR 33580) and apply to units capable of firing more than 73 megawatts (MW) (250 million British thermal units per hour(MMBtu/hr)) heat input of fossil fuel that commenced construction, reconstruction, or modification after September 18, 1978. The NSPS also apply to industrial-commercial-institutional cogeneration units that sell more than 25 MW and more than one-third of their potential output capacity to any utility power distribution system. The most recent amendments to emission standards under subpart Da, 40 CFR part 60, were promulgated in 1998 (63 FR 49442) resulting in new NO X limitations for subpart Da, 40 CFR part 60, units. Furthermore, in the 1998 amendments, we incorporated the use of output-based emission limits. The NSPS for industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Db) apply to units for which construction, modification, or reconstruction commenced after June 19, 1984 that have a heat input capacity greater than 29 MW (100 MMBtu/hr). Those standards were originally promulgated on November 25, 1986 (51 FR 42768) and also have been amended since the original promulgation to reflect changes in BDT for these sources. The most recent amendments to emission standards under subpart Db, 40 CFR part 60, were promulgated in 1998 (63 FR 49442) resulting in new NO X limitations for subpart Db, 40 CFR part 60, units. The NSPS for small industrial-commercial-institutional steam generating units (40 CFR part 60, subpart Dc) were originally promulgated on September 12, 1990 (55 FR 37674) and apply to units with a maximum heat input capacity greater than or equal to 2.9 MW (10 MMBtu/hr) but less than 29 MW (100 MMBtu/hr). Those standards apply to units that commenced construction, reconstruction, or modification after June 9, 1989. Section 111(b)(1)(B) of the CAA requires the EPA periodically to review and revise the standards of performance, as necessary, to reflect improvements in methods for reducing emissions. B. What Is the Role of the NSPS Program? The NSPS program is one part of the CAA's integrated air quality management program. The primary purpose of the NSPS are to achieve long-term emissions reductions by ensuring that the best demonstrated emission control technologies are installed as the industrial infrastructure is modernized. Since 1970, the NSPS have been successful in achieving long-term emissions reductions at numerous industries by assuring cost-effective controls are installed on new, reconstructed, or modified sources. Recently, however, with the rapid advance of control technologies, the case-by-case new source review (NSR) permitting program has required greater emissions reductions than required by the NSPS, particularly for utility boilers. The existing and proposed market-based cap and trade programs require greater overall emissions reductions from the entire utility industry than the technology-based emission limits of the NSPS can achieve by regulating individual new sources. Utility steam generators are subject to the current cap and trade programs for acid rain, which imposes a national cap on annual utility SO 2 emissions, and for interstate transport of ozone, which imposes a regional cap on summer time utility NO X emissions in the eastern United States. The Administration's proposed Clear Skies Act would impose three trading programs: a national SO 2 trading program tighter than the acid rain trading program and two annual NO X trading programs (one for the eastern United States and one for the remaining part of the country). Alternatively, EPA's Clean Air Interstate Rule (CAIR) proposes two new trading programs for utility steam generators to further control SO 2 and NO X emissions in the eastern United States to reduce the transport of fine particulate matter and ozone. Under these types of cap and trade programs, emissions of the regulated pollutants from all the regulated units are capped at a prescribed level (tons per year). Each affected unit is allocated a number of emission allowances, each of which conveys the right to emit a certain amount of the regulated pollutant. The total number of allowances allocated for any given year equals the emissions cap for that year. Each year, an affected unit must turn in a number of allowances equal to its emissions. Allowances can be bought and sold. Therefore, units can comply either by emitting equal to or less than permitted by the number of allowances they have been allocated or by obtaining additional allowances. This provides units with low cost reduction opportunities an incentive to reduce emissions below their allocated levels and allows units that face high costs for emissions reductions the opportunity to obtain allowances. It is useful to understand the relationship between the NSPS program as it applies to utility steam generators and the various cap and trade programs being implemented or under development. First, the cap and trade program provides an incentive to apply modern emission controls on new sources because installing controls on a new unit is generally less expensive than installing similar controls on an existing unit. Minimizing emissions from a new source minimizes the allowances it must purchase (if no allowances are set aside for new sources) or may even allow it to sell allowances (if allowances are automatically allocated to new sources). Therefore, for source categories and pollutants subject to a stringent industry-wide emissions cap, a stringent NSPS is less important because new sources already have an economic incentive to install state-of-the-art controls. Second, over time, as technology improves, a cap continues to provide an incentive to install better technology, especially on new sources. In contrast, NSPS that are reviewed and amended every 8 years are unlikely to keep pace with technological improvements. Since the normal rulemaking process takes several years, more frequent updating of NSPS are impractical. Finally, for sources and pollutants subject to a tight industry-wide emissions cap, stringent NSPS would have little or no effect on overall emissions in the geographic area regulated by the cap. Even if there were source specific reasons which result in it not making economic sense to install as effective emission controls as would be required under a stringent NSPS, that unit would have to use more allowances. This would result in fewer allowances being available for existing units, which would result in fewer emissions from existing sources. Therefore, for the pollutants, geographic area, and sources regulated by cap and trade programs, tighter NSPS would not necessarily affect total emissions. However, the stringency of the NSPS could affect the cost of achieving these emissions reductions. A cap and trade program allows the market to determine the most cost-effective way to achieve the overall emissions reductions goal. Installing modern controls on new sources will be the most cost-effective choice for most new sources. If there are circumstances where this is not the case, then overly stringent NSPS could limit a new source from using the most cost-effective controls for meeting its allocated portion of the emissions cap, thereby raising the cost of controls without necessarily increasing the environmental benefit. The primary environmental benefit from the proposed amendments to the utility NSPS would come from the reduction of direct PM emissions, because direct emissions of PM are not subject to a cap and trade program (nor has such a program been proposed). For SO 2 (which is subject to a national trading program), the primary effect of the proposed amendments would be to establish the minimum control requirements for any steam generating units that are not subject to NSR. For NO X , the same would be true nationally if Clear Skies were to pass or would be true in the eastern United States if CAIR is promulgated. Also, replacing the percent reduction requirement for SO 2 with an emission limit would harmonize the NSPS with the cap and trade programs by providing sources more flexibility in reducing emissions from new sources to meet the cap, while maintaining the same aggregate emissions. III. Summary of the Proposed Amendments The proposed amendments would amend the emission limits for SO 2 , NO X , and PM from steam generating units in subpart Da, 40 CFR part 60, (Electric Utility Steam Generating Units), and the PM emission limit for subpart Db, 40 CFR part 60, (Industrial-Commercial-Institutional Steam Generating Units), and subpart Dc, 40 CFR part 60, (Small Industrial-Commercial-Institutional Steam Generating Units). Only those units that begin construction, modification, or reconstruction after February 28, 2005, would be affected by the proposed amendments. Steam generating units subject to the proposed amendments but for which construction, modification, or reconstruction began on or before February 28, 2005, would continue to comply with the applicable standards under the current NSPS. Compliance with the proposed emission limits would be determined using the same testing, monitoring, and other compliance provisions set forth in the existing standards. In addition to amending the emission limits, we also are proposing several technical clarifications and corrections to existing provisions of the existing amendments, as explained below. We are proposing language to clarify the applicability of subparts Da, Db, and Dc of 40 CFR part 60 to combined cycle power plants. Heat recovery steam generators that are associated with combined cycle gas turbines burning natural gas or a fuel other than synthetic-coal gas would not be subject to subparts Da, Db, or Dc, 40 CFR part 60, if the unit meets the applicability requirements of subpart KKKK, 40 CFR part 60 (Standards of Performance for Stationary Combustion Turbines). Subpart Da, Db, or Dc of 40 CFR part 60 would apply to a combined cycle gas turbine that burns synthetic-coal gas ( e.g. , integrated coal gasification combine cycle power plants) and meets the applicability criteria of one of the proposed amendments, respectively. We are proposing amendments to the definitions for boiler operating day, coal, coal-derived fuels, oil, and natural gas. The purpose of the proposed amendments is to clarify definitions across the three subparts and to incorporate the most current applicable American Society for Testing and Materials (ASTM) testing method references. Also, we are proposing to clarify the definition of an “electric utility steam generating unit” as applied to cogeneration units. We are proposing several amendments to the provisions of the existing rule related to the use of continuous emission monitoring systems (CEMS) to obtain SO 2 and NO X emission data for determining compliance with the rule requirements. The proposed amendments would eliminate duplicative or conflicting CEMS requirements for utility steam generating units that are subject to both 40 CFR part 60 and 40 CFR part 75 (acid rain). A. What Are the Requirements for New Electric Utility Steam Generating Units (40 CFR Part 60, Subpart Da)? The proposed PM emission limit for electric utility steam generating units is 6.4 nanograms per joule (ng/J) (0.015 lb/MMBtu) heat input regardless of the type of fuel burned. Compliance with this emission limit would be determined using the same testing, monitoring, and other compliance provisions for PM standards set forth in the existing rule. The proposed SO 2 emission limit for electric utility steam generating units is 250 ng/J (2.0 pound per megawatt hour (lb/MWh)) gross energy output regardless of the type of fuel burned with one exception. The proposed SO 2 emission limit for electric utility steam generating units that burn over 90 percent coal refuse is 300 ng/J (2.4 lb SO 2 /MWh) gross energy output. Under the existing subpart Da of 40 CFR part 60, coal refuse is defined as waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. , culm, gob) containing coal, matrix material, clay, and other organic and inorganic material. Compliance with the proposed SO 2 emission limits would be determined on a 30-day rolling average basis using a CEMS to measure SO 2 emissions as discharged to the atmosphere and following the compliance provisions in the existing rule for the output-based NO X standards applicable to new sources that were built after July 9, 1997. The proposed NO X emission limit for electric utility steam generating units is 130 ng/J (1.0 lb NO X /MWh) gross energy output regardless of the type of fuel burned in the unit. Compliance with this emission limit would be determined on a 30-day rolling average basis using the testing, monitoring, and other compliance provisions in the existing rule for the output-based NO X standards applicable to new sources that were built after July 9, 1997. B. What Are the Requirements for Industrial-Commercial-Institutional Steam Generating Units (40 CFR Part 60, Subpart Db)? The proposed PM emission limit for industrial-commercial-institutional steam generating units is 13 ng/J (0.03 lb/MMBtu heat input) for units that burn coal, oil, wood, or a mixture of these fuels with other fuels. This limit would apply to units larger than 29 MW (100 million British thermal units per hour). C. What Are the Requirements for Small Industrial-Commercial-Institutional Steam Generating Units (40 CFR Part 60, Subpart Dc)? The proposed PM emission limit for small industrial-commercial-institutional steam generating units is 13 ng/J (0.03 lb/MMBtu heat input) for units that burn coal, oil, wood, or a mixture of these fuels with other fuels. This limit would apply to units between 8.7 MW and 29 MW (30 to 100 million Btu per hour). IV. Rationale for the Proposed Amendments A. What Is the Performance of Control Technologies for Steam Generating Units? Control technologies for steam generating units are based on either pre-combustion controls, combustion controls, or post-combustion controls. Pre-combustion controls remove contaminants from the fuel before it is burned, and combustion controls reduce the amount of pollutants formed during combustion. Post-combustion controls remove pollutants formed from the flue gases before the gases are released to the atmosphere. Selecting control technologies to reduce emissions of PM, SO 2 , and NO X from a new steam generating unit is a function of the type of fuel burned in the unit, the size of the unit, and other site-specific factors ( e.g. , type of unit, firing and loading practices used, regional and local air quality requirements). All new steam generating units incorporate control technologies to reduce NO X emissions. Natural gas is a gaseous fuel composed of methane and other hydrocarbons with trace amounts of sulfur and no ash. Accordingly, PM and SO 2 emissions from steam generating units firing natural gas are inherently low and generally do not require the use of additional PM or SO 2 control technologies. For new steam generating units firing fuel oils, PM and SO 2 controls may be required depending on the grade and composition of the fuel oil being burned in the unit. New steam generating units firing coal use PM and SO 2 controls. 1. PM Control Technologies Filterable PM emissions from a steam generating unit are predominately fly ash and carbon. Carbon particles are generated from incomplete combustion of the fuel, and fly ash from burning fuels containing ash materials (the mineral and other incombustible matter portion of a fuel). These incombustible solid materials are released during the combustion process and are entrained in the flue gases. Distillate oils contain insignificant levels of ash, but residual fuel oils have higher ash contents, up to 0.5 percent. While different ranks of coals vary in ash content, all coals contain significant quantities of ash. The percentage of ash in a given coal can vary from less than 5 percent to greater than 20 percent depending on the coal source and level of coal cleaning. Control of PM emissions from steam generating units relies on the use of post-combustion controls to remove solid particles from the flue gases. Electrostatic precipitators (ESP) and fabric filters (also called baghouses) are the predominant technologies used to control PM from coal-fired steam generating units. Either of these PM control technologies can be designed to achieve overall PM collection efficiencies in excess of 99.9 percent. Control of PM emissions from oil-fired steam generating units can be achieved by using oil burner designs with improved atomization and fuel mixing characteristics, by implementing better maintenance practices, and by using an ESP. Electrostatic Precipitator. An ESP operates by imparting an electrical charge to incoming particles, and then attracting the particles to oppositely charged metal plates for collection. Periodically, the particles collected on the plates are dislodged in sheets or agglomerates (by rapping the plates) and fall into a collection hopper. The fly ash collected in the ESP hopper is a solid waste that is either recycled for industrial use or disposed of in a landfill. The effectiveness of particle capture in an ESP depends primarily on the electrical resistivity of the particles being collected. The size requirement for an ESP increases with increasing coal ash resistivity. Resistivity of coal fly ash can be lowered by conditioning the particles upstream of the ESP with sulfur trioxide, sulfuric acid, water, or sodium. In addition, collection efficiency is not uniform for all particle sizes. Collection efficiencies greater than 99.9 percent, however, are achievable for small particles (less than 0.1 micrometer (μm)) and large particles (greater than 10 μm). Collection efficiencies achieved by ESP for the portion of particles having sizes between 0.1 μm and 10 μm tend to be lower. Fabric Filters. A fabric filter collects PM in the flue gases by passing the gases through a porous fabric material. The buildup of solid particles on the fabric surface forms a thin, porous layer of solids, which further acts as a filtration medium. Gases pass through this cake/fabric filter, and all but the finest-sized particles are trapped on the cake surface. Collection efficiencies of fabric filters can be as high as 99.99 percent. A fabric filter must be designed and operated carefully to ensure that the bags inside the collector are not damaged or destroyed by adverse operating conditions. The fabric material must be compatible with the gas stream temperatures and chemical composition. Because of the temperature limitations of the available bag fabrics, location of a fabric filter for use by a coal-fired electric steam generating unit is restricted to locations downstream of the air heater. 2. SO 2 Control Technologies During combustion, sulfur compounds present in a fuel are predominately oxidized to gaseous SO 2 . A small portion of the SO 2 oxidizes further to sulfur trioxide (SO 3 ). One approach to controlling SO 2 emissions from steam generating units is to limit the maximum sulfur content in the fuel. This can be accomplished by burning a fuel that naturally contains low amounts of sulfur or a fuel that has been pre-treated to remove sulfur from the fuel. A second approach is use a post-combustion control technology that removes SO 2 from the flue gases. These technologies rely on either absorption or adsorption processes that react SO 2 with lime, limestone, or another alkaline material to form an aqueous or solid sulfur by-product. Coal Pre-Treatment. Sulfur in coal occurs as either inorganic sulfur or organic sulfur that is chemically bonded with carbon. Pyrite is the most common form of inorganic sulfur. There are two ways to pre-treat coal before combustion to lower sulfur emissions: Physical coal cleaning and gasification. Physical cleaning removes between 20 to 90 percent of pyritic sulfur, but is not effective at removing organic sulfur. The amount of pyritic sulfur varies with different coal types, but it is typically half of the total sulfur for high sulfur coals. Coal gasification breaks coal apart into its chemical constituents (typically a mixture of carbon monoxide, hydrogen, and other gaseous compounds) prior to combustion. The product gas is then cleaned of contaminants prior to combustion. Gasification reduces SO 2 emissions by over 99 percent. Alkali Wet Scrubbing. The SO 2 in a flue gas can be removed by reacting the sulfur compounds with a solution of water and an alkaline chemical to form insoluble salts that are removed in the scrubber effluent. The most commonly used wet flue gas desulfurization (FGD) systems for coal-fired steam generating units are based on using either limestone or lime as the alkaline source. In a wet scrubber, the flue gas enters a large vessel located downstream of the particle control device where it contacts the lime or limestone slurry. The calcium in the slurry reacts with the SO 2 to form reaction products that are predominately calcium sulfite. Because of its high alkalinity, fly ash is sometimes mixed with the limestone or lime. Other alkaline solutions can be used for scrubbing including sodium carbonate, magnesium oxide, and dual alkali. The SO 2 removal efficiency that a wet FGD system can achieve for a specific steam generating unit is affected by the sulfur content of the fuel burned, which determines the amount of SO 2 entering the wet scrubber, and site-specific scrubber design parameters including liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of the alkaline sorbent to SO 2 . Annual SO 2 removal efficiencies have been demonstrated above 98 percent. Advanced wet scrubber designs include limestone scrubbing with forced oxidation (LSFO) and magnesium enhanced lime scrubbing FGD systems. Limestone Scrubbing with Forced Oxidation. Limestone scrubbing with forced oxidation is a variation of the wet scrubber described above and can use either limestone or magnesium enhanced lime. In the LSFO process, the calcium sulfite initially formed in the spray tower absorber is oxidized to form gypsum (calcium sulfate) by bubbling compressed air through the sulfite slurry. The resulting gypsum by-product has commercial value and can be sold to wallboard manufacturers. Also, because of their larger size and structure, gypsum crystals settle and dewater better than calcium sulfite crystals, reducing the required size of by-product handling equipment. The high gypsum content also permits disposal of the dewatered waste without fixation. Spray Dryer Adsorption. An alternative to using wet scrubbers is to use spray dryer adsorber technology. A spray dryer adsorber operates by the same principle as wet lime scrubbing, except that instead of a bulk liquid (as in wet scrubbing) the flue gas containing SO 2 is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas temperatures are in the range of 120 °C to 180 °C (250 °F to 350 °F). The SO 2 is absorbed in the slurry and reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate. The water is evaporated by the hot flue gases and forms dry, solid particles containing the reacted sulfur. Most of the SO 2 removal occurs in the spray dryer vessel itself, although some additional SO 2 capture has also been observed in downstream particulate collection devices. This process produces a dry waste product, which is mostly disposed of in a landfill. The primary operating parameters affecting SO 2 removal are the calcium-reagent-to-sulfur stoichiometric ratio and the approach to saturation in the spray dryer. To decrease sorbent costs, a portion of the solids collected in the spray dryer and the PM collection device may be recycled to the spray dryer. The SO 2 removal efficiencies of new lime spray dryer systems are generally greater than 90 percent. Dry Injection. For the dry injection process, dry hydrated or slaked lime (or another suitable sorbent) is directly injected into the ductwork or boiler upstream of a PM control device. Some systems use spray humidification followed by dry injection. The SO 2 is adsorbed and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas stream, along with fly ash, and then collected by the downstream PM control device. The dry injection process produces a dry, solid by-product that is easier to dispose. However, the SO 2 removal efficiencies for existing dry injection systems are lower than for the other FGD technologies ranging from approximately 40 to 60 percent when using lime or limestone, and up to 90 percent using other sorbants ( e.g. , sodium bicarbonate). Fluidized-bed Combustion with Limestone. One of the appealing features of selecting a steam generating unit that uses a fluidized-bed combustor (FBC) is the capability to control SO 2 emissions during the combustion process. This is accomplished by adding finely crushed limestone along with the coal (or other solid fuel) to the fluidized bed. During combustion, calcination of the limestone (reduction to lime by subjecting to heat) occurs simultaneously with the oxidation of sulfur in the coal to form SO 2 . The SO 2 , in the presence of excess oxygen, reacts with the lime particles to form calcium sulfate. The sulfated lime particles are removed with the bottom ash or collected with the fly ash by a downstream PM control device (for most existing FBC steam generating unit applications, a fabric filter is used as the PM control device). Fresh limestone is continuously fed to the bed to replace the reacted limestone. The SO 2 removal efficiencies for some FBC units are in the range of approximately 80 to 98 percent. 3. NO X Control Technologies Nitrogen oxides are formed in a steam generating unit by the oxidation of molecular nitrogen in the combustion air and any nitrogen compounds contained in the fuel. The formation of NO X from nitrogen in the combustion air is dependent on two conditions occurring simultaneously in the unit's combustion zone: high temperature and an excess of combustion air. Under these conditions, significant quantities of NO X are formed regardless of the fuel type burned. New steam generating units being installed today in the United States routinely include burners and other features designed to reduce the amounts of NO X formed during combustion. Beyond the lower levels of NO X emissions achieved using combustion controls, additional NO X emission control can be achieved for steam generating units by installing post-combustion control technologies. These technologies involve converting the NO X in the flue gas to molecular nitrogen (N2) and water using either a process that requires a catalyst (called selective catalytic reduction (SCR)) or a process that does not use a catalyst (called selective noncatalytic reduction (SNCR)). Both SCR and SNCR technologies have been applied widely to gas-, oil-, and coal-fired steam generating units. NO X Combustion Controls. Combustion controls reduce NO X emission formation by controlling the peak flame temperature and excess air in and around the combustion zone through staged combustion. With staged combustion, the primary combustion zone is fired with most of the air needed for complete combustion of the fuel. The remaining air is introduced into the products of the partial combustion in a second combustion zone. Air staging lowers the peak flame temperature, thereby reducing thermal NO X , and reduces the production of fuel NO X by reducing the oxygen available for combination with the fuel nitrogen. Staged combustion may be achieved internally in the fuel burners using specially designed burner configurations (often referred to as low-NO X burners), or external to the burners by diverting a portion of the combustion air from the burners and introducing it through separate ports and/or nozzles, mounted above the burners (often referred to as overfire air (OFA)). The actual NO X reduction achieved with a given NO X combustion control technology varies from unit to unit. Use of low-NO X burners can reduce NO X emissions by approximately 35 to 55 percent. Use of OFA reduces NO X emissions levels in the range of 15 to 30 percent. Higher NO X emissions reductions are achieved when combustion control technologies are combined ( e.g. , combining OFA with low-NO X burners can achieve NO X emissions reductions in the range of 60 percent). Other NO X combustion control techniques include reburning, co-firing natural gas, and flue gas recirculating. In reburning, coal, oil, or natural gas is injected above the primary combustion zone to create a fuel rich zone to reduce burner-generated NO X to N2 and water vapor. Overfire air is added above the reburning zone to complete combustion of the reburning fuel. Natural gas co-firing consists of injecting and combusting natural gas near or concurrently with the main oil or coal fuel. Flue gas recirculating decreases combustion temperatures by mixing flue gases with the incoming combustion air. For gas and oil units, flue gas recirculating can reduce NO X emissions by 75 percent. SCR Technology. The SCR process uses a catalyst with ammonia (NH 3 ) to reduce the nitrogen oxide (NO) and nitrogen dioxide (NO 2 ) in the flue gas to molecular nitrogen and water. Ammonia is diluted with air or steam, and this mixture is injected into the flue gas upstream of a metal catalyst bed that typically is composed of vanadium, titanium, platinum, or zeolite. The SCR catalyst bed reactor is usually located between the economizer outlet and air heater inlet, where temperatures range from 230 °C to 400 °C (450 °F to 750 °F). The SCR technology is capable of NO X reduction efficiencies of 90 percent or higher. SNCR Technology. A SNCR process is based on the same basic chemistry of reducing the NO and NO2 in the flue gas to molecular nitrogen and water, but does not require the use of a catalyst to promote these reactions. Instead, the reducing agent is injected into the flue gas stream at a point where the flue gas temperature is within a specific temperature range of 870 °C to 1,090 °C (1,600 °F to 2,000 °F). Currently, two SNCR processes are commercially available; one uses ammonia as the reagent, and the other process uses an aqueous urea solution in place of ammonia. The NO X reduction levels for SNCR are in the range of approximately 30 to 50 percent. B. Regulatory Approach We have reviewed emission data and control technology information applicable to criteria pollutants and have concluded that the regulation of NO X , PM, and SO 2 emissions from these sources under the NSPS is appropriate. The proposed amendments to the NSPS reflect the BDT for these sources based on the performance and cost of the emission control technologies discussed above. In amending the emission limits based on BDT, we have incorporated a fuel-neutral concept and, to the extent that it is practical and reasonable, output-based emission limits. These approaches provide the level of emission limitation required by the CAA for the NSPS program and achieve additional benefits of compliance flexibility, increased efficiency, and the use of cleaner fuels. 1. Fuel-Neutral Approach We are proposing to amend emission limits using a fuel-neutral approach in most cases. This approach is currently used for the NO X emission standards under subparts Da and Db of 40 CFR part 60 and encourages pollution prevention by recognizing the environmental benefits of combustion controls based on the use of clean fuels. The fuel-neutral approach provides a single emission limit for steam generating units based on BDT without regard to specific type of steam generating equipment or fuel type. This approach provides an incentive to facilities to consider fuel use, boiler type, and control technology when developing an emission control strategy. Therefore, owners and operators of affected sources are able to use the most effective combination of add-on control technologies, clean fuels, and boiler design to meet the emission limit. For example, an owner and operator may decide that the blending of a low sulfur fuel with coal or physically washing the coal in combination with dry-injection technology would be a more cost-effective way of meeting the NSPS than burning a higher sulfur coal and installing a FGD system. Alternatively, if a source does not have long-term access to clean fuels at a reasonable cost, then emission control technology is available to allow units to burn higher sulfur fuels and still comply with the emission limits. To develop a fuel-neutral emission limit, we analyzed emission control performance from coal-fired units to establish an emission level that represents BDT. The higher sulfur, nitrogen, and ash contents for coal compared to oil or gas makes application of BDT to coal-fired units more complex than application to either oil-or gas-fired units. Therefore, emission levels selected for coal-fired steam generating units using BDT would be achievable by oil- and gas-fired electric utility steam generating units. The resulting emission levels from coal-fired units would apply to all boiler types and fuel use combinations. It is appropriate for all fuels to have the same limits to avoid discouraging the use of cleaner fuels. The BDT analysis was conducted separately for 40 CFR part 60, subparts Da, Db, and Dc. 2. Output-Based Emission Standards We have established pollution prevention as one of our highest priorities. One of the opportunities for pollution prevention is maximizing the efficiency of energy generation. An output-based standard establishes emission limits in a format that incorporates the effects of unit efficiency by relating emissions to the amount of useful-energy generated, not the amount of fuel burned. By relating emission limitations to the productive output of the process, output-based emission limits encourage energy efficiency because any increase in overall energy efficiency results in a lower emission rate. Allowing energy efficiency as a pollution control measure provides regulated sources with an additional compliance option that can lead to reduced compliance costs as well as lower emissions. The use of more efficient technologies reduces fossil fuel use and leads to multi-media reductions in environmental impacts both on-site and off-site. On-site benefits include lower emissions of all products of combustion, including hazardous air pollutants, as well as reducing any solid waste and wastewater discharges. Off-site benefits include the reduction of emissions and non-air environmental impacts from the production, processing, and transportation of fuels. While output-based emission limits have been used for regulating many industries, input-based emission limits have been the traditional method to regulate steam generating units. However, this trend is changing as we seek to promote pollution prevention and provide more compliance flexibility to combustion sources. For example, in 1998 we amended the NSPS for electric utility steam generating units (40 CFR part 60, subpart Da) to use output-based standards for NO X (40 CFR 63.44a, 62 FR 36954, and 63 FR 49446). In this action, we are proposing output-based emission limits for SO 2 and NO X under subpart Da of 40 CFR part 60. The format of the proposed output-based limits is mass of pollutant per megawatt hour of gross energy output. We are proposing to base the limits on gross energy output because of the monitoring difficulties in measuring net output. The current output-based emission limit for NO X in subpart Da of 40 CFR part 60 is based on gross energy output. The difficulties of monitoring net energy output are explained in the preamble to the 1998 NO X amendment for subpart Da of 40 CFR part 60 (63 FR 49448). Electrical Generating Units. For subpart Da of 40 CFR part 60, we are proposing amendments which establish output-based emission limits for SO 2 and NO X . For PM, we are proposing an amended input-based emission limit and requesting comments on an output-based limit. The proposed output-based emission limit for SO 2 will replace both the current percentage reduction requirement and input-based emission limit. Industrial-Commercial-Institutional Units. For subpart Db of 40 CFR part 60, we are soliciting comment on an optional output-based NO X emission limit for units that generate electricity. Units that generate electricity have the greatest opportunity for achieving increases in energy efficiency. We would structure the output-based limit as an option because we determined that for some applications of industrial, commercial, and institutional boilers, the monitoring, recordkeeping, and reporting costs for demonstrating compliance with output-based emission limits would be unreasonable. Determining compliance with an output-based emission limit requires the use of a CEMS. Specifically, emission data must be collected in units of pounds per hour to calculate an output-based emission rate. The CEMS currently required by subpart Db of 40 CFR part 60, do not provide that data. A CEMS also would need to collect continuous exhaust flow data to calculate emissions in units of pounds per hour. Additionally, continuous energy monitoring devices would be needed to comply with an output-based limit. Not all electric generating units subject to subpart Db of 40 CFR part 60 may be designed with these monitoring systems. Due to costs, we are not expanding the monitoring requirements under subpart Db of 40 CFR part 60 to require the collection of exhaust flow and electrical generation data, and we are not proposing an output-based emission limit for subpart Db of 40 CFR part 60. Instead, we are proposing that individual facilities be given the option of complying with either the current input-based or an equivalent output-based limit. Output-based limits may be feasible for NO X at units that operate continuous emission flow and electrical generation monitoring equipment. For example, some industrial-commercial-institutional electric generating units may be required to install continuous exhaust flow monitoring systems to demonstrate compliance with State regulatory programs, such as NO X requirements in State implementation plans. Where the required monitors are in place, an output-based emission limit provides an incentive for increased energy efficiency and the use of highly efficient technologies like combined heat and power systems (next section). The use of output-based emission limits is less feasible for PM because current regulations generally do not require industrial-commercial-institutional steam generators to operate PM CEMS. Furthermore, the percent removal format for SO 2 contained in subpart Db of 40 CFR part 60 is not compatible with an output-based standard. 3. Combined Heat and Power Combined heat and power (CHP) is the sequential generation of power (electricity or shaft power) and thermal energy from a common combustion source. The application of CHP captures and uses much of the waste heat that ordinarily is discarded from conventional electrical generation, where two-thirds of the input energy typically becomes waste heat (through exhaust stacks and cooling towers). In a CHP system, this captured energy can be used to provide process heat and space cooling or heating. By recovering waste heat, CHP systems achieve much higher fuel efficiencies than separate electric and thermal generators, and emit less pollution. Using CHP is a method for industry not only to decrease criteria pollutants and hazardous air pollutants, but also to move forward on addressing concerns about increasing levels of heat trapping gases in the atmosphere. Because CHP units produce both electrical and thermal energy, the proposed amendments must account for both types of energy in demonstrating compliance with an output-based emission limit. Energy output for CHP units is the sum of gross electrical output and the useful energy of the process steam. For the output-based emission limits currently contained in subpart Da of 40 CFR part 60, we defined the useful energy of the process steam from CHP units as 50 percent of the thermal output. We chose the 50 percent allowance at that time because using an allowance as if the steam would be converted to electricity (up to 38 percent efficiency) would not account for the environmental benefits of CHP applications, and allowing 100 percent could potentially overstate the environmental benefits of CHP applications. Additionally, this approach to CHP units was consistent with a Federal Energy Regulatory Commission (FERC) regulation determining the efficiency of CHP units. In the proposed amendments, we are soliciting comments on the appropriateness of giving more than 50 percent credit for thermal output, and on a different approach to account for the thermal energy from CHP units. The proposed approach would account for the efficiency benefits of the thermal output based on the amount of avoided emissions that a conventional boiler system would otherwise emit had it provided the same thermal output as the CHP system. The avoided emissions would be determined for each unit based on individual unit operating factors. The proposed compliance procedures for CHP units follow this logic: (1) Determine the emission rate of the combustion source that provides energy to the CHP unit (in units of pounds per hour) from the continuous emission and flow monitoring system; (2) Calculate the avoided emissions (in units of pounds per hour) for the amount of thermal energy generated from the CHP unit; and (3) Subtract the avoided emissions from the total emissions of the CHP unit and divide that value by the gross electrical output of the CHP unit. This approach more accurately reflects the environmental benefits of CHP units and accounts for site-specific differences in system design, operation, and various power-to-heat ratios (the ratio of gross electrical energy generation to useful thermal energy generation). If a CHP unit demonstrates compliance with the output-based emission limit, an output-based emission rate would be calculated based on the following equation: Echp = [Et − THa]/Oe  (Eq. 1) Where: Echp = CHP emission rate (lb/MWh) Et = total emissions (pounds per hour (lb/hr)) THa = avoided thermal emissions (lb/hr) Oe = electrical output (MW) The avoided thermal emissions (A) would be calculated based on the following equation: A = [E/0.8] * Oth  (Eq. 2) Where: A = avoided thermal emissions (lb/hr) E = applicable NSPS emission limit for the displaced boiler (pound per million British thermal units heat input (lb/MMBtu)) 0.8 = assumed boiler efficiency (percent) Oth = thermal output (MMBtu/hr) Under this approach, the avoided emission rate for the displaced steam generating capacity would be calculated using the input-based 40 CFR part 60, subpart Db, NSPS emission limit applicable to the steam generating unit. This is appropriate since, in the absence of the CHP facility, the thermal energy would be provided by a new boiler subject to 40 CFR part 60, subpart Db. The NSPS limit would be converted from an input- to a thermal output-based emission rate by dividing the input-based emission limit by an assumed thermal system efficiency of 80 percent. We have chosen a boiler thermal efficiency of 80 percent because it is considered reasonable and takes into consideration all fuels and a variety of design configurations used for boilers in CHP facilities. Then, the avoided emission rate is converted to units of pounds per hour by multiplying by the recovered useful thermal output of the CHP system. We are soliciting comments both on this approach and other methods of determining displaced thermal emissions besides a boiler subject to 40 CFR part 60, subpart Db. C. How Did EPA Determine the Amended Standards for Electric Utility Steam Generating Units (40 CFR Part 60, Subpart Da)? New source performance standards for electric utility steam generating units in the proposed amendments would apply only to affected sources that begin construction, modification, or reconstruction after February 28, 2005. As discussed earlier in this preamble, the regulatory approach we are using to develop the proposed standards is based on our determination of BDT for control of PM, SO 2 , and NO X from electric utility steam generating units. Furthermore, we decided that the proposed standards should use a fuel-neutral and an output-based emission limit format, to the extent that it is practical and reasonable. To set the proposed output-based standards at new plants, we used measured output-based emissions where available. When gross output information was unavailable, we selected emission limits based on heat input and used a gross electrical efficiency to determine the output-based standard. Recent technical publications assert that new supercritical plants will be able to achieve net efficiencies as high as 45 percent, and analysis of EPA's Clean Air Markets Division data indicates that the top 10 percent of utility units are presently operating at a gross efficiency of 38 percent or greater. However, to account for variations in boiler designs and to allow efficiency as a control technology, we selected 36 percent gross efficiency (top 25 percent of existing units) as our conversion factor. We are soliciting comments on this approach and the appropriateness of the selected value. Only three new coal utility units have been built since the prior NSPS amendments in 1998. The plants are the Red Hills facility in Mississippi, the Hawthorn facility in Missouri, and the Northside facility in Florida. These plants are designed to burn lignite, subbituminous, and bituminous coal, respectively. To provide a broader set of data to base the proposed amendments on, we also analyzed older plants that have been retrofitted with controls. 1. Selection of the Proposed PM Standard Direct particulate matter emissions from steam generating units firing coal result from the entrainment of fly ash in the flue gases and, to a lesser extent, from unburned fuel particles and downstream post-combustion reactions. Currently, 40 CFR part 60, subpart Da, limits PM emissions from electric utility steam generating units to 0.03 lb/MMBtu heat input regardless of the fuel burned in the unit. Coal-fired electric utility steam generating units meeting the current PM emission limit under subpart Da, 40 CFR part 60, predominately use either a fabric filter or ESP to remove PM from the flue gases. Over the years, the performance of fabric filters and ESP installed on coal-fired steam generating units has improved as a result of advanced control device designs and other performance enhancements ( e.g. , use of new bag materials for fabric filters and use of computer modeling and improved rapper and electrical system designs for ESP). We concluded that fabric filters and ESP represent BDT for continuous reduction of PM emissions from coal-fired electric utility steam generating units. To assess performance levels achievable by fabric filters and ESP installed on new coal-fired electric utility steam generating units, we reviewed the permits of three recent facilities covered under subparts Da of 40 CFR part 60. The permit limits for the Hawthorn, Red Hills, and Northside facilities are 0.018, 0.015, and 0.011 lb PM/MMBtu heat input respectively. The Hawthorn limit includes condensible PM, and the facility is achieving filterable PM control of 0.012 lb/MMBtu. The Northside facility is achieving filterable PM control of 0.004 lb/MMBtu. Based on this information, we concluded that current fabric filter and ESP control technologies being installed on new electric utility steam generating units can achieve PM emission levels below the level of the existing PM standard, and that amending this PM standard for new electric utility steam generating units is warranted. To select a level for the proposed PM standard, we evaluated the cost-effectiveness of two limits (0.018 lb PM/MMBtu and 0.015 lb PM/MMBtu) along with the ability of a broad range of coal types and boiler configurations to achieve the standard. The annual reduction and incremental cost of reducing PM emissions from the existing NSPS (0.03 lb/MMBtu) to 0.018 lb/MMBtu is 420 tons at an average incremental cost of $3,100/ton. The annual reduction and incremental cost of reducing the PM standard from 0.018 lb/MMBtu to 0.015 lb/MMBtu is 110 tons at an average incremental cost of $8,400/ton. We selected a level for the proposed standard considering the above performance information, non-air quality health effects, and effects on energy production associated with achieving these emission levels. The proposed PM standard is 6.5 ng/J (0.015 lb/MMBtu heat input). Based on information from the Department of Energy Cost and Quality of Fuels for Electric Utility Plants 2001, 75 percent of existing coal utility units would be able to comply with the proposed limit using either an ESP or fabric filter operating at a 99.8 percent collection efficiency, and 95 percent would be able to comply with either an ESP or fabric filter operating at a 99.9 percent collection efficiency. The remaining 5 percent would be able to comply with either a high efficiency ESP or fabric filter operating at a 99.95 percent collection efficiency or coal washing in conjunction with a less efficient PM control device. We are particularly interested in soliciting comments providing information to guide this determination. In the event data is presented indicating a more stringent standard is achievable, we would consider a 4.7 ng/J (0.011 lb/MMBtu heat input) standard. If data is presented demonstrating that this standard will pose significant technical difficulties for a range of fuels, we would consider a standard of 8.6 ng/J (0.02 lb/MMBtu heat input). 2. How Did EPA Select the Proposed SO 2 Standard? The current SO 2 standard in 40 CFR part 60, subpart Da, uses a percent reduction format in conjunction with a maximum emission limit but provides an allowance for a lower percent reduction requirement if a target emission limit is demonstrated. Effectively, these standards require a new coal-fired steam generating unit to achieve a 90 percent reduction of the potential combustion concentration of SO 2 ( i.e. , the theoretical amount of SO 2 that would be emitted in the absence of using any emission control systems), and meet an emission limit of 1.2 lb SO 2 /MMBtu heat input. However, if a unit can demonstrate an SO 2 emission rate less than 0.6 lb/MMBtu heat input, then the unit is only required to achieve a 70 percent reduction. As discussed earlier in this preamble, a number of SO 2 control technologies are currently available for use with new coal-fired electric utility steam generating units. The SO 2 control strategy used for a particular new electric utility steam generating unit project is fundamentally determined by the type of combustion technology that is selected for the new unit. Owners and operators building a new steam generating unit using integrated gasification combined cycle (IGCC) or fluidized-bed combustion technology generally use different control strategies than owners and operators building a new steam generating unit using pulverized coal combustion technology. Another important factor influencing the selection of SO 2 control technology for a new unit is the sulfur content of the coals expected to be burned. According to the most recent Department of Energy data (FERC form-423 and form EIA-423), non-refuse coal-fired power plants in the United States had an average uncontrolled sulfur emissions potential of 1.8 lb SO 2 /MMBtu heat input in 2002. Since 1995, eight new coal-fired electric utility steam generating units have been built in the United States, and these units have an average uncontrolled SO 2 emission level of 1.6 lb SO 2 /MMBtu heat input and a maximum of 2.1 lb SO 2 /MMBtu heat input. We concluded that new electric utility steam generating projects will use either IGCC technology, state-of-the-art SO 2 controls, or burn low- and medium-sulfur content coals to achieve reductions. New steam generating projects that use IGCC technology will inherently have only trace SO 2 emissions because over 99 percent of the sulfur associated with the coal is removed by the coal-gasification process. New steam generating units that use fluidized-bed combustion technology can control SO 2 during the combustion process by coal washing, coal blending, adding limestone into the fluidized-bed, and installing polishing scrubbers. However, to date, application of fluidized-bed combustion technology has been limited to the lower end of the steam generating unit sizes expected for new electric utility projects (the largest FBC unit built to date is 350 MW). For SO 2 controls applied to steam generating units using pulverized coal combustion technology, control strategies involve the burning of low sulfur coals, coal washing, coal blending, the use of post-combustion controls to remove SO 2 from the flue gases, and co-firing with natural gas, low sulfur fuel oil, or biomass. The majority of new electric utility steam generating units will use pulverized coal combustion technology. Therefore, using the fuel-neutral approach discussed earlier, we decided to base the BDT determination for development of an amended SO 2 standard on application of SO 2 control technologies to pulverized coal-fired steam generating units. We reviewed the SO 2 control technologies currently available for application to pulverized coal-fired electric utility steam generating units. We concluded that FGD is BDT for these units. The type of FGD system used for a given new unit depends on a number of site-specific factors, including unit size, sulfur content of coal to be burned in the unit, and the overall economics of each application. Existing wet FGD systems used for pulverized coal-fired electric utility steam generating units, especially the scrubber technologies installed in the last 10 years, are capable of consistently achieving SO 2 removal efficiencies of 95 percent and higher. Multiple plants have demonstrated that this level of control is achievable on a long-term basis. Enhanced wet FGD systems are capable of achieving high removal efficiencies and can be used for units burning the highest sulfur content coals. In addition, dry FGD technologies such as lime spray dryer (LSD) systems can be used to achieve significant reductions in SO 2 emissions under certain conditions. Typically, LSD systems have been used for smaller size electric utility steam generating units burning lower sulfur content coals. There are several LSD systems designed for 90 percent or higher SO 2 removal efficiencies. Based on this information, we concluded that current FGD systems being installed on new electric utility steam generating units can achieve SO 2 emission levels below the level of the existing SO 2 standard, and that amending this SO 2 standard for new electric utility steam generating units is warranted. To assess the SO 2 control performance level of utility units, we reviewed new and retrofitted facilities with SO 2 controls. Since 1995, the Harrison coal-fired power plant in West Virginia has used a FGD system based on wet scrubbing technology that has achieved annual SO 2 emissions of approximately 1 lb/MWh gross output from an uncontrolled level of 5.4 lb/MMBtu heat input. Based on hourly acid rain data from 1997 to 2000, the highest 30-day average from the three stacks ranged between 1.3 to 1.5 lb SO 2 /MWh gross output. The Conemaugh facility in Pennsylvania has maintained 30-day average emissions under 1.4 lb SO 2 /MWh gross output over the same period using coal with uncontrolled emissions of 3.4 lb SO 2 /MMBtu heat input. Based on the performance of the Harrison facility, we are selecting a single limit for all fuels of 0.21 lb SO 2 /MMBtu heat input as the basis for the proposed standard. We realize many new units will operate below this value, but the proposed limit would allow the highest sulfur coals (uncontrolled emissions of 7 lb SO 2 /MMBtu) to meet the limit using similar technology as the Harrison facility. Using a gross electrical generating efficiency of 36 percent, the proposed standard is 250 ng/J (2.0 lb/MWh) of SO 2 . Based on the third quarter 2004 emissions data from EPA's Clean Air Markets Division, eleven percent of existing coal units are presently operating at or below this limit. We are soliciting comments on the proposed limit and are considering the range of 120 to 250 ng/J (0.9 to 2.0 lb/MWh) for the final rule. Of the coals used in existing electric utility plants, 70 percent could comply with the proposed standard using spray dryers. Eighty nine percent could meet the standard with conventional wet FGD technology, and ninety nine percent with enhanced wet scrubbing. Only one percent of existing coal utilities use coal with uncontrolled SO 2 emissions greater than 7 lb/MMBtu. If a utility were to elect to use a fuel with uncontrolled SO 2 emissions above 7 lb/MMBtu heat input, technology is available that would allow the unit to meet the proposed standard. Options include physical coal washing, blending with low sulfur fuels, combining SO 2 control technologies like those applied at the JEA Northside facility, super-critical high-efficiency boilers, combined heat and power, and gasification. In addition, emerging SO 2 control technologies will allow the direct use of any fuel in a conventional coal plant without fuel blending or pretreatment. Therefore, regardless of the sulfur content of the bituminous, subbituminous, or lignite coal burned by a new electric utility steam generating unit, SO 2 emission control technologies are available that would allow the unit owner or operator to comply with the proposed SO 2 standard at a reasonable cost. Coal refuse (also called waste coal) is a combustible material containing a significant amount of coal that is reclaimed from refuse piles remaining at the sites of past or abandoned coal mining operations. Coal refuse piles are an environmental concern because of acid seepage and leachate production, spontaneous combustion, and low soil fertility. Advancements in fluidized-bed combustion technology allow reclaimed coal refuse to be burned in power plants and cogeneration facilities. Facilities that burn coal refuse provide special multimedia environmental benefits by combining the production of energy with the clean up of coal refuse piles and by reclaiming land for productive use. Consequently, because of the unique environmental benefits that coal refuse-fired power plants provide, these units warrant special consideration so as to prevent the amended NSPS from discouraging the construction of future coal refuse-fired power plants in the United States. We reviewed emissions data and title V permit information for the existing coal refuse-fired power plants currently operating in the United States. Based on our review, we concluded that the PM and NO X emission levels for these facilities were comparable to the emission levels from other coal-fired electric utility power plants using similar control technology. Thus, coal refuse-fired electric utility steam generating units can achieve the same PM and NO X emission standards being proposed for bituminous, subbituminous, and lignite coals. However, there is a possibility that coal refuse from some piles will have sulfur contents at such high levels that they present potential economic and technical difficulties in achieving the same SO 2 standard that we are proposing for higher quality coals. Therefore, so as not to preclude the development of these projects, we are proposing a separate SO 2 emission limit that we concluded is achievable for the full range of coal refuse piles remaining in the United States. The proposed standard is 0.25 lb SO 2 /MMBtu heat input for facilities that burn over 90 percent coal refuse. Using the same baseline efficiency of 36 percent, the proposed standard is 300 ng/J (2.4 lb/MWh) of SO 2 for units that burn coal refuse. We are requesting comment on the proposed limit and are considering the range of 180 to 360 ng/J (1.4 to 2.8 lb/MWh) for the final rule. 3. How Did EPA Select the Proposed NO X Standard? In 1998, we amended the NO X emission limits for new electric utility steam generating units built or reconstructed after July 9, 1997 (63 FR 49444, September 9, 1998). At that time, we concluded that SCR represented BDT for continuous reduction of NO X emissions from electric utility steam generating units. The level of the amended NO X emission limit was selected based on the performance data of SCR control technology in combination with combustion controls on coal-fired steam generating units. The existing NSPS is 200 ng/J of gross output (1.6 lb/MWh) for new units and 65 ng/J of heat input (0.15 lb/MMBtu) for reconstructed units (63 FR 49444). We reviewed the NO X control technologies currently available for application to electric utility steam generating units, and concluded that SCR remains BDT for continuous reduction of NO X emissions from these sources. However, since the time we selected the current NO X emission limits, the number of electric utility steam generating units in the United States using SCR control technology has substantially increased. In 2002, more than 50 electric utility steam generating units were operating SCR controls, with additional facilities installing or planning to install the technology. In addition, at units operating SCR controls, the installation of NO X CEMS allows the collection of long-term data on SCR control performance. As a result, we now have access to significantly more data on the performance of SCR control technology than was available to us in 1998. The design NO X reduction efficiencies of the SCR controls in use on specific electric utility steam generating units vary depending on site-specific conditions ( e.g. , retrofit to existing units versus new unit applications, facility's air permit requirements, other NO X combustion controls used), but operating data indicate that NO X emission reduction levels of 90 percent or more can consistently be achieved for coal-fired electric utility steam generating units. Two units built after the 1998 NO X NSPS amendments for utility units are the JEA Northside facility in Florida and the Hawthorn facility in Missouri. Both are operating within their permit limits of 0.09 lb NO X /MMBtu heat input and 0.08 lb NO X /MMBtu heat input, respectively. These values are below the current standard of 1.6 lb/MWh, which is based on 0.15 lb NO X /MMBtu heat input. Based on the incorporation of combustion control technologies into new electric utility steam generating unit designs and the demonstrated SCR performance for recently built units, we concluded that amending this NO X standard for new electric utility steam generating units is warranted. While the WA Parish coal facility in Texas has demonstrated control of approximately 0.04 lb NO X /MMBtu heat input, we are proposing a level of 0.11 lb/MMBtu heat input as the basis for the proposed standard. This emission limit allows for the possibility of using fluidized beds and advanced-combustion controls as an alternative to SNCR or SCR. Advanced combustion controls reduce compliance costs, parasitic energy requirements, and ammonia emissions. We converted this value to the corresponding value in units of lb/MWh using an overall efficiency factor of 36 percent. Therefore, we are proposing for the NO X standard a level of 130 ng/J (1.0 lb/MWh) gross electricity output as determined on a 30-day rolling average. Based on third quarter 2004 emissions data from EPA's Clean Air Markets Division, approximately 14 percent of existing units are achieving this limit. We are soliciting comments on this approach and are particularly interested in additional data on the achievable NO X levels of fluidized beds without additional NO X controls and pulverized coal units with advanced combustion controls. The range of values we are presently considering for the final rule is 60 to 170 ng/J (0.47 to 1.3 lb/MWh). D. How Did EPA Determine the Amended Standards for Industrial-Commercial-Institutional Steam Generating Units (40 CFR Part 60, Subparts Db and Dc)? New source performance standards for industrial-commercial-institutional steam generating units in the proposed amendments would apply only to affected sources that begin construction, modification, or reconstruction after February 28, 2005. In this action, we are proposing an amended emission limit for PM under 40 CFR part 60, subparts Db and Dc, and no change to the emission limits for SO 2 and NO X . However, we are requesting public comments on the concept of adopting a single, fuel-neutral emission limit for SO 2 to replace the current 90 percent reduction requirement in the final rule. We are also requesting comment on the possibility of lowering the SO 2 emission limits in 40 CFR part 60, subpart Dc, for units with heat input capacities of 10 MMBtu/hr to 75 MMBtu/hr and developing NO X emission limits for units subject to 40 CFR part 60, subpart Dc. 1. How Did EPA Select the Proposed PM Limit? The current PM standards under 40 CFR part 60, subpart Db, for industrial, commercial, and institutional boilers greater than 100 MMBtu/hr heat input range from 0.051 lb/MMBtu heat input to 0.2 lb/MMBtu heat input, depending on the type and amount of fuels burned. The current PM standards under 40 CFR part 60, subpart Dc, for industrial, commercial, and institutional boilers with heat input capacities of 30 MMBtu/hr to 100 MMBtu/hr range from 0.051 lb/MMBtu heat input to 0.3 lb/MMBtu heat input, depending on the type and amount of fuels burned. We are proposing a PM limit of 0.03 lb/MMBtu heat input for units that burn coal, oil, wood or a mixture of these fuels with other fuels and have a heat input capacity greater than 30 MMBtu/hr. The emission limit is based on the use of fabric filters or high efficiency ESP, which represents BDT. Fabric filters have been shown to achieve greater than 99 percent reduction in PM emissions and may achieve as high as 99.99 percent reduction for some units. To determine the appropriate limit, we reviewed boiler permit limits and emission information gathered for industrial, commercial, and institutional boilers. Based on this information, we concluded that new boilers can achieve an emission limit of 0.03 lb/MMBtu heat input using a fabric filter or high-efficiency ESP. An emission limit of 0.03 lb/MMBtu heat input is achievable by all industrial, commercial, and institutional boilers considering the wide variety of fuels fired and the range of operating conditions under which those boilers are run. The proposed NSPS emission limits would not pose significant new costs. New industrial-commercial-institutional steam generating units that are major sources of hazardous air pollutants will be covered also by the National Emission Standards for Hazardous Air Pollutants (NESHAP) for industrial, commercial, institutional boilers and process heaters (40 CFR part 63, subpart DDDDD). The industrial, commercial, institutional boiler and process heater NESHAP require all boilers with a heat input greater than 10 MMBtu/hr and firing solid fuels to meet either a PM limit of 0.025 lb/MMBtu heat input or a total selected metals limit of 0.0003 lb/MMBtu heat input. Liquid-fired units with heat inputs greater than 10 MMBtu/hr must meet a PM limit of 0.03 lb/MMBtu heat input. Accordingly, for most boilers the proposed NSPS would not impose any additional costs because these units are already required to comply with equivalent or more stringent emission limits in the industrial, commercial, institutional boiler and process heater NESHAP. However, the industrial, commercial, institutional boiler and process heater NESHAP also allow several compliance alternatives that would allow some sources to comply without installing a fabric filter. These alternatives include demonstrating that emissions are below a risk threshold, meeting an alternative metals emission limit, or by demonstrating the metal hazardous air pollutant (HAP) content in the fuel is below the metals emission limit. A review of the data gathered for the industrial, commercial, institutional boiler and process heater NESHAP shows that some wood-fired units are expected to be able to use the alternative compliance options, because wood has a low HAP-to-PM ratio. Therefore, the primary impact of the proposed NSPS would be to require wood-fired boilers to install more efficient controls than would be needed to demonstrate compliance with the industrial, commercial, institutional boiler and process heater NESHAP. For wood-fired boilers, there is a significant flamability risk with fabric filter bags due to particulate loading. Therefore, we analyzed the cost and emissions reductions achieved using a high-efficiency ESP to meet the NSPS limits. Emission test information from industrial, commercial, institutional boilers and utility boilers shows that ESP can achieve the same emissions reductions as fabric filters for these units. We are projecting that 13 wood-fired units with heat inputs larger than 100 MMBtu/hr will be constructed over the next 5 years. Annual PM emissions would be reduced by 888 tons per year (tpy), from 1,300 tpy, based on the current subpart Db, 40 CFR part 60, emission limits, to 412 tpy with the proposed PM emission limit. The incremental annualized cost of installing and operating an ESP on wood-fired units would be about $2,300 per ton of PM removed. For the 30 to 100 million Btu/hr size range, we project that four wood-fired units will be constructed over the next 5 years. For these units, annual PM emissions would be reduced by 43 tpy, from about 62 tpy, under the current subpart Dc, 40 CFR part 60, emission limits, to 19 tpy with the proposed PM emission limit. The incremental annualized cost of installing and operating an ESP on a wood-fired unit would be $3,200 per ton of PM removed. 2. How Did EPA Select the Proposed SO 2 Emission Limit? The existing SO 2 standard for coal- and oil-fired units larger than 75 MMBtu/hr is 90 percent reduction of potential SO 2 emissions and a maximum emission limit of 1.2 lb/MMBtu heat input for coal and 0.8 lb/MMBtu heat input for oil. These limits are based on the use of FGD systems or lime spray dryers. The percent reduction requirement does not apply to units burning fuel oil that have an SO 2 emission potential of 0.5 lb/MMBtu heat input or less. Fluidized bed boilers burning refuse coal are subject to an 80 percent reduction requirement. For small boilers (less than 75 MMBtu/hr) the existing NSPS are based on low sulfur fuels (1.2 lb SO 2 /MMBtu heat input). Based on our review, we are proposing to retain the current SO 2 standard for industrial, commercial, and institutional boilers. In determining BDT, we reviewed the performance of available control technologies and the permits issued for new coal-fired industrial, commercial, and institutional boilers constructed since the publication of 40 CFR part 60, subparts Db and Dc. Based on a review of the information in the Reasonably Available Control Technology/Best Available Control Technology/Lowest Achievable Emission Rate (RACT/BACT/LAER) Clearinghouse, all NSPS units smaller than 75 MMBtu/hr were issued permits to use low sulfur coal. For units greater than 75 MMBtu/hr, the technology used was either lime spray dryers, duct injection, or fluidized-bed boilers with limestone injection. These technologies have been demonstrated to achieve a 90 percent reduction in SO 2 . No industrial-commercial-institutional units were found to use wet FGD systems. To determine BDT, we evaluated two options. Option 1 was to amend subparts Db and Dc, 40 CFR part 60, to adopt a 95 percent reduction requirement for units larger than 75 MMBtu/hr (the size range currently required to meet a 90 percent reduction). Option 2 was to amend subpart Dc, 40 CFR part 60, to require a 90 percent reduction for units smaller than 75 MMBtu/hr. Option 1 would achieve a 5th year emission reduction of 1,400 tons SO 2 per year (50 percent reduction from the current NSPS) at an incremental cost of about $4,000 per ton removed (table 1 of this preamble). The costs range from $605 per ton removed for some units larger than 250 MMBtu/hr to $12,000 per ton for some units between 100 and 250 MMBtu/hr. The relatively high incremental cost would occur because meeting the 95 percent limit would require a technology switch to more expensive wet FGD systems for many new units. Most new units currently achieve 90 percent reduction using either sorbent injection or spray dryers. Under Option 1, these units would switch to wet FGD systems, because spray dryers and injection technology have not been demonstrated to achieve a 95 percent SO 2 emission reduction. The annualized cost of wet FGD is higher than for these technologies. The cost of wet FGD is about 20 percent higher for large coal-fired units and about 50 percent higher for coal-fired units between 100 and 250 million Btu/hour. Option 2 would achieve a 5th year emission reduction of 111 tons SO 2 per year (68 percent reduction) for subpart Dc, 40 CFR part 60, units (table 1 of this preamble). The incremental cost-effectiveness would range from about $3,000 to more than $8,000 per ton removed. This cost range represents the cost of applying injection technologies on units of 50 MMBtu/hr and 25 MMBtu/hr, respectively. The relatively high incremental cost would occur because this option would achieve a relatively small additional emissions reductions compared to the current NSPS. Under the current NSPS, units are achieving compliance using low sulfur coals with an emission potential of 1.2 lb SO 2 /MMBtu heat input. If the NSPS were changed to require a 90 percent reduction, we project that many new units would select higher sulfur coals because of the reduced fuel cost. For those units that select a higher sulfur coal, a 90 percent reduction in potential SO 2 emission would result in less than a 90 percent reduction in emissions compared to the current NSPS. Considering these potential impacts, we determined that the current NSPS continues to reflect BDT for 40 CFR part 60, subparts Db and Dc, industrial, commercial, and institutional boilers. The current performance levels can be met by using low sulfur fuels for smaller units and cost-effective control technologies for larger units. Requiring additional control technology would impose unacceptable compliance costs that are not warranted for the emissions reductions that would be achieved. Table 1.—National 5th Year Impacts of SO 2 Controls on Industrial Boilers 2004$ Option Unit size range (MMBtu/hr) Emission reduction (tpy) Annualized cost (million $) Incremental cost-effectiveness ($/ton) Overall Range 95 percent 1 75-250 232 1.68 7,220 6,320-12,060 >250 1,163 1.56 1,340 610-1,960 90 percent 2 3 <75 111 0.48 4,280 2,970-8,890 1 Baseline emissions and emissions reductions used on Option 1 for units greater than 75 MMBtu/hr assume 90 percent SO 2 reduction using a mix of medium sulfur content bituminous coal (2.38 lb SO 2 /MMBtu) and subituminous coal (1.41 lb SO 2 /MMBtu). 2 Baseline emissions for units less than 75 MMBtu/hr assume bituminous coal with a 1.2 lb SO 2 /MMBtu emission potential. 3 Emissions reductions were calculated for Option 2 assuming a fuel switch to a 2 to 1 ratio of medium sulfur coal (1.41 lb/MMBtu) to high sulfur coal (6.81 lb/MMBtu). 3. How Did EPA Select the Proposed NO X Emission Limit? The current NSPS for NO X apply to fossil fuel-fired industrial-commercial-institutional steam generating units greater than 100 MMBtu/hr. The NO X emission limit is 0.2 lb NO X /MMBtu heat input for units burning coal, oil, or natural gas. Units burning 90 percent or more non-fossil fuel are not required to meet a NO X emission limit (51 FR 42768). Low heat release rate units that burn more than 30 percent natural gas or distillate oil are required to meet a limit of 0.1 lb NO X /MMBtu heat input. There are currently no NO X emission limits for new industrial-commercial-institutional steam generating units less than 100 MMBtu/hr. The current emission limits for fossil fuel-fired units are based on the application of SCR in combination with combustion controls ( i.e. , low-NO X burners). We are not aware of a more effective NO X control technology for new industrial-commercial-institutional steam generating units. Based on available performance data and cost considerations, the Administrator has concluded that application of SCR with combustion controls represents the BDT (taking into account costs, non-air quality health and environmental impacts, and energy requirements) for coal- and residual oil-fired units. We, therefore, are proposing to retain the current emission limits for subpart Db, 40 CFR part 60, units. In the 1998 amendments, we presented information that showed that SCR can reduce NO X emissions from coal-fired utility units to 0.15 lb/MMBtu heat input. However, an emission limit of 0.2 lb/MMBtu heat input was chosen for industrial-commercial-institutional units based on the cost associated with applying flue gas treatment to the wide range of boiler types used in industrial-commercial-institutional applications. Since the 1998 proposal, only eight coal-fired units subject to subpart Db, 40 CFR part 60, have been permitted. Therefore, only limited information is available on the performance of SCR on new coal-fired industrial-commercial-institutional units today. No new performance information or emissions data have been gathered since the 1998 amendments to indicate that lower limits are consistently achievable across the full range of boiler types that may be constructed in the future. In addition, we re-evaluated the costs of SCR. Recent cost information indicates that the cost of operating SCR technology at lower levels than the current standard has not decreased significantly since 1998. We concluded, therefore, that the current emission limits for fossil fuel-fired units constitute BDT (taking into account costs, nonair quality health and environmental impacts, and energy requirements). We are requesting comments and supporting emissions data on the ability of SCR to achieve lower emission limits on fossil fuel-fired industrial-commercial-institutional steam generators and the cost of achieving any lower emission limits. We are proposing no NO X emission limits for units with heat input capacities of 100 MMBtu/hr or less (subpart Dc, 40 CFR part 60, units). Information in the RACT/BACT/LAER Clearinghouse shows that in the last 14 years only one coal-fired unit and 16 solid fuel-fired units with heat inputs less than 100 MMBtu/hr have been permitted. Over this same period, 204 units firing natural gas were permitted. This trend is expected to continue. Consequently, new units under 100 MMBtu/hr are expected to be predominantly natural gas-or oil-fired. One possible control option is to adopt an emission limit based on the performance of low-NO X burners. This option would have almost no impact on emissions, because most new industrial, commercial, and institutional boilers today are equipped with low-NO X burners. The primary impact would be to require the installation of a CEMS and impose recordkeeping and reporting requirements to demonstrate that units are continuously meeting the NO X emission limits. It is unclear that these measures would result in a significant emissions reductions. We, therefore, concluded that the cost of a CEMS to monitor low-NO X burners is not reasonable for units smaller than 100 MMBtu/hr given that little or no emissions reductions is likely. We also considered the impact of adopting a 0.2 lb/MMBtu heat input emission limit based on the use of SCR on coal-fired units (table 2 of this preamble). This option would reduce NO X emissions from subpart Dc of 40 CFR part 60 units by 250 tpy, or about a 10 percent reduction. Given that baseline NO X emissions from gas-fired units are less than 0.2 lb/million Btu, this limit would have no effect on emissions for the largest projected subset of units operating between 10 and 100 million Btu/hr. Gas-fired units, however, would incur some costs due to monitoring and reporting requirements. Incremental control costs would range from $3,000 to $17,000 per ton removed. Based on these costs, and the factors discussed above, we are proposing not to adopt NO X emission limits for industrial-commercial-institutional units smaller than 100 MMBtu/hr heat input. Table 2.—National 5th Year Impacts of NO X Control Option for Industrial Units Subject to 40 CFR Part 60, Subpart Dc 2004$ Size range (MMBtu/hr) Fuel Number of units Emission reduction (tpy) Annual cost (million$) Incr. cost effect. ($/ton) 30-100 Gas 61 0 2.42 Coal 1 34 0.20 5,830 Liquid 8 126 0.38 3,040 Wood 4 52 0.90 17,320 10-30 Gas 20 0 0.79 Liquid 3 21 .14 6,850 Wood 2 20 0.18 9,160 Total 99 253 5.02 * Liquid and gas units can meet the 0.2 lb/MMBtu limit with a Low-NO X Burner (LNB). Coal and wood units require an SCR to meet the 0.2 limit. E. What Technical Corrections Is EPA Proposing? We are proposing several technical corrections to the current subparts Da, Db, and Dc of 40 CFR part 60 requirements in the proposed amendments. The amendments are being proposed to clarify the intent of the current requirements, correct inaccuracies, and correct oversights in previous versions that were promulgated. Heat Recovery Steam Generators Heat recovery steam generating units are used to recover energy from the exhaust of combustion turbines. Some heat recovery steam generators use duct burners or other types of supplemental heat supply to increase the amount of steam production. Depending on the heat input capacity of the supplemental heat in a heat recovery generator, these units may meet the applicability requirements of 40 CFR part 60, subparts Da, Db, and Dc. However, we recognized that these units would be more appropriately regulated as part of the combustion turbine NSPS. In recognition of this, 40 CFR 60.40a(b) and 40 CFR 60.40b(i) provide that when the emission limits for heat recovery steam generators are incorporated into 40 CFR part 60, subpart GG, these units would be subject to 40 CFR part 60, subpart GG, and 40 CFR part 60, subparts Da and Db, would no longer apply. This language was inadvertently left out of 40 CFR part 60, subpart Dc. In a separate action, we are proposing to amend the NSPS for combustion turbines that would be codified as subpart KKKK of 40 CFR part 60 instead of amending subpart GG of 40 CFR part 60. The proposed subpart will include requirements for heat recovery steam generators. Therefore, we are proposing to amend subparts Da, Db, and Dc of 40 CFR part 60 to require heat recovery steam generators to comply with either subpart GG of 40 CFR part 60 or subpart KKKK of 40 CFR part 60 as applicable. The proposed rule language states that “* * * Heat recovery steam generators that are associated with combustion turbines and meet the applicability requirements of subpart KKKK of 40 CFR part 60 of this part are not subject to this subpart. If the heat recovery steam generator is subject to this subpart, only emissions resulting from combustion of fuels in the steam-generating unit are subject to this subpart. (The combustion turbine emissions are subject to 40 CFR part 60, subpart GG, or 40 CFR part 60, subpart KKKK, as applicable, of this part.)” NO X Monitoring Requirements for Units Without NO X Emission Limits During the 1998 amendments to 40 CFR part 60, subpart Db, we amended the monitoring requirements of 40 CFR 60.48b(b) to allow units that are subject to 40 CFR part 75 (acid rain regulations) to demonstrate compliance with the NSPS by using CEMS that meet the requirements of part 75. In making these amendments, we made a drafting error by inadvertently excluding a phrase from the original NSPS language. The amended 1998 language could be interpreted to require the use of NO X CEMs for units that are not subject to the NO X emission limits of 40 CFR part 60, subpart Db. The intended language of 40 CFR 60.48b(b) was, “* * *, the owner or operator of an affected facility subject to the nitrogen oxides standards of 60.44b shall comply with either * * * *” (emphasis added to the missing phrase). We did not intend for units without a NO X emission limit to install CEMS for NO X . In the proposed amendments, we are adding the inadvertently removed phrase. Definition of Coal We are proposing to amend the definition of coal in 40 CFR part 60, subpart Dc, to reflect the most recent testing methods published by the ASTM. Definitions for 40 CFR Part 60, Subpart Da We are proposing to add definitions of coal, bitimunous coal, petroleum, and natural gas to 40 CFR part 60, subpart Da, to clarify applicability and make the rules more uniform. We are also proposing to amend the definition of boiler operating day for new utility units to be consistent with the existing definition for industrial units. The proposed limits reflect the amended procedure utility units would use to calculate 30-day averages. Our preliminary analysis of the hourly CEM data from the Harrison facility indicates that the standards would be approximately 3 percent lower if the existing definition of boiler-operating day is maintained. The amended definition also more accurately reflects environmental performance since less data is excluded from the calculation. Harmonization of 40 CFR Part 60 and 40 CFR Part 75 Monitoring Requirements As a continuation and expansion of the “turbine initiative” begun by EPA in 2001, we are proposing to harmonize portions of the 40 CFR part 60 continuous emission monitoring regulations with similar provisions in 40 CFR part 75. Background. In the late 1990's, the electric utility industry began planning and constructing numerous combustion turbine projects, to meet the rising demand for electrical generating capacity in the United States. Essentially all of these new turbines are subject to both 40 CFR part 60, subpart GG, of the NSPS regulations (40 CFR 60.330 through 60.335) and the Acid Rain regulations (40 CFR part 72 through 40 CFR part 78). In an August 24, 2001 Federal Register action (66 FR 44622), EPA estimated that as a result of the new turbine projects, the number of combustion turbines in the Acid Rain Program would increase from 400 to more than 1,000 within a few years. The compliance requirements for combustion turbines under the NSPS and the Acid Rain Program intersect in a number of key places. For instance, under both programs, the owner or operator of an affected combustion turbine is accountable for the SO 2 and NO X emissions from the unit. In cases such as this, where two Federal regulations affect the same unit for the same pollutant(s), it is always desirable to simplify compliance, to the extent possible. In view of this, in the previously-cited August 24, 2001 Federal Register action, EPA requested comments from stakeholders on ways to streamline and harmonize the 40 CFR part 60 and 40 CFR part 75 regulations, in order to facilitate compliance for sources that are subject to both sets of rules. EPA's initiative was directed principally at 40 CFR part 60, subpart GG, combustion turbines that are also in the Acid Rain Program. However, the Agency also asked for comments on “other needed changes to the regulations,” at places where the 40 CFR part 60 and 40 CFR part 75 monitoring and reporting requirements overlap. EPA received several sets of comments in response to the August 24, 2001, Federal Register action. After careful consideration of these comments, the Agency proposed substantive amendments to 40 CFR part 60, subpart GG, on April 14, 2003 (68 FR 18003), incorporating many suggestions provided by the commenters. The amendments to 40 CFR part 60, subpart GG, were promulgated on July 8, 2004 (69 FR 41346). The final amendments, which differed little from the proposal, harmonized the 40 CFR part 60, subpart GG, and 40 CFR part 75 regulations in a number of key areas. For example: (1) Amended 40 CFR part 60, subpart GG, allows the use of a certified 40 CFR part 75 NO X monitoring system to demonstrate continuous compliance with the NO X emission limit in 40 CFR 60.332; (2) If a fuel is documented to be natural gas according to the criteria in appendix D, 40 CFR part 75, then the 40 CFR part 60, subpart GG, requirement to monitor the sulfur content of the fuel is waived; and (3) A 40 CFR part 60, subpart GG, turbine that combusts fuel oil may use the oil sampling and analytical methods in appendix D, 40 CFR part 75 to demonstrate compliance with the 40 CFR part 60, subpart GG, sulfur-in-fuel limit. The July 8, 2004 revisions to 40 CFR part 60, subpart GG, significantly simplify compliance with the 40 CFR part 60 and 40 CFR part 75 regulations, where both sets of rules apply to the same combustion turbine. However, the area of overlap between 40 CFR part 60 and 40 CFR part 75 extends beyond combustion turbines. Many electric utility and industrial boilers regulated under 40 CFR part 60, subparts D, Da, Db and Dc, are also subject to 40 CFR part 75. Therefore, a more comprehensive approach to 40 CFR part 60 versus 40 CFR part 75 compliance is needed. A number of stakeholders pointed this out in their comments on the August 24, 2001, Federal Register action. In particular, the commenters requested that EPA address the following problematic areas in the 40 CFR part 60 and 40 CFR part 75 continuous emission monitoring provisions: (1) Inconsistent definitions of operating hours; (2) Inconsistent CEMS data validation criteria; (3) Duplicative quality-assurance (QA) test requirements. For instance, many sources with gas monitors are required to perform both 40 CFR part 75 linearity checks and 40 CFR part 60 cylinder gas audits; (4) Lack of alternative calibration error and relative accuracy specifications in 40 CFR part 60 for low-emitting sources; (5) Inconsistent span and range requirements for gas analyzers; and (6) For infrequently-operated units, the difficulty of performing the 40 CFR part 60 calibration drift test over 7 consecutive calendar days. Today's proposed amendments would address the chief concerns expressed by the stakeholders in their comments on the August 24, 2001, Federal Register action, by amending a number of key sections in 40 CFR part 60. The proposed amendments are discussed in detail in the paragraphs below. Operating Hours and CEMS Data Validation. For all CEMS except opacity monitors, 40 CFR 60.13(h) in the General Provisions of the NSPS requires a minimum of four equally-spaced data points to calculate an hourly emissions average. However, the underlying assumption in the proposed rule text is that the unit operates for the whole hour, and no guidelines are given for validating partial operating hours. Section 60.13(h) also appears to conflict with 40 CFR 60.47a(g), subpart Da, and 40 CFR 60.47b(d) and 40 CFR 60.48b(d), subpart Db, which require only two valid data points to calculate hourly SO 2 and NO X emission averages. Further, all four of these sections ( i.e. , 40 CFR 60.13(h), 40 CFR 60.47a(g), 40 CFR 60.47b(d) and 40 CFR 60.48b(d)) are inconsistent with 40 CFR 75.10(d)(1) and with 40 CFR 60.334(b)(2) of the recently-amended 40 CFR part 60, subpart GG, which require you to obtain at least one valid data point in each 15-minute quadrant of the hour in which the unit operates, except for hours in which required QA and maintenance activities are performed for these hours, you may calculate the hourly averages from a minimum of two data points (one in each of two 15-minute quadrants). Today's proposed amendments would make the CEMS data validation requirements of 40 CFR 60.13(h), 40 CFR 60.47a(g), 40 CFR 60.47b(d) and 40 CFR 60.48b(d) consistent with 40 CFR 75.10(d)(1) and 40 CFR 60.334(b)(2), as follows: (1) First, a clear distinction would be made in 40 CFR 60.13(h) between full and partial operating hours. A full operating hour would be a clock hour in which the unit operates for 60 minutes, and a partial operating hour would be one with less than 60 minutes of unit operation. To calculate an hourly emissions average for a full operating hour, at least one valid data point would be required in each of the four 15-minute quadrants of the hour. For a partial operating hour, at least one valid data point would be required in each 15-minute quadrant in which the unit operates; (2) Second, for hours in which required QA or maintenance activities are performed, 40 CFR 60.13(h) would be amended to allow the hourly averages to be calculated from a minimum of two data points (if the unit operates in two or more of the 15-minute quadrants) or one data point (if the unit operates in only one quadrant of the hour); (3) Third, 40 CFR 60.13(h) would be amended to require all valid data points to be used in the calculation of each hourly average; (4) Fourth, 40 CFR 60.13(h) would require invalidation of any hour in which a calibration error test is failed, unless in that same hour, a subsequent calibration error test is passed and sufficient data are captured after the passed calibration to validate the hour; (5) Fifth, 40 CFR 60.13(h) would be amended to make it clear that hourly averages are not to be calculated for certain partial operating hours, where specified in an applicable NSPS subpart ( e.g. , hours with <30 minutes of unit operation are to be excluded from the calculations under 40 CFR 60.47b(d)); and (6) Sixth, 40 CFR part 60.47a(g), 40 CFR part 60.47b(d) and 40 CFR part 60.48b(d) would be amended by removing the provisions that allow hourly averages to be calculated from only two data points. Rather, these sections would specify that hourly averages must be calculated according to amended 40 CFR 60.13(h). These proposed revisions would provide a single, consistent method of calculating hourly emission averages from CEMS data for sources that are subject to both 40 CFR part 60 and 40 CFR part 75. Thus, the same basic set of CEM data could be used for both 40 CFR part 60 and 40 CFR part 75 compliance, although certain differences between the two programs would still remain. For instance, 40 CFR part 75 requires substitute data to be reported for each hour in which sufficient quality-assured data is not obtained to validate the hour, whereas 40 CFR part 60 requires these hours to be reported as monitor down time. Also, 40 CFR part 75 requires a bias adjustment factor (BAF) to be applied to SO 2 and NO X data when a CEMS fails a bias test, whereas 40 CFR part 60 does not require adjustment of the emissions data for bias. And for certain partial operating hours, data that is reported as quality-assured under 40 CFR part 75 is excluded from the 40 CFR part 60 emission calculations ( e.g. , see 40 CFR 60.47b(d)). However, these differences between the 40 CFR part 60 and 40 CFR part 75 programs are relatively minor, and in no way detract from the benefits of having a unified approach to reducing the CEMS data to hourly averages. As noted above, EPA is proposing to remove the provisions in 40 CFR 60.47a(g) of subpart Da and in 40 CFR 60.47b(d) and 40 CFR 60.48b(d) of subpart Db, which require only two valid data points to calculate hourly SO 2 and NO X emission averages. The reason for this is that these rule texts do not properly communicate the Agency's original intent. The idea of basing an hourly average on two data points was first presented in the preamble for subpart Da, 40 CFR part 60 (44 FR 33581, June 11, 1979). In that preamble, EPA clearly stated that whenever required QA activities such as daily calibration error checks are performed, the Agency would allow the hourly average (assuming it was a full operating hour) to be based on a minimum of two data points instead of the usual four points required by 40 CFR 60.13(h). This relaxation in the data capture requirement for certain operating hours was made with the realization that for many CEMS, calibration checks can take up to 30 minutes, preventing any emissions data from being collected. However, it was never the Agency's intent to replace the four-point data capture requirement of 40 CFR 60.13(h) with a less stringent two-point requirement. The authors of the original 40 CFR part 75 rule understood this, and cited the subpart Da, 40 CFR part 60, preamble as the basis for CFR 75.10(d)(1) (56 FR 63067-68, December 3, 1991). In 40 CFR 75.10(d)(1), at least one valid data point is required to be obtained in each 15-minute quadrant of the hour in which the unit operates, except that two data points, separated by at least 15 minutes may be used to calculate an hourly average if required QA tests or maintenance activities are performed during that hour. More recently, these same minimum data capture requirements have been incorporated into 40 CFR 60.334(b)(2) of subpart GG. In view of these considerations, it is appropriate to remove the two-point minimum data capture provisions from 40 CFR 60.47a(g), 40 CFR 60.47b(d) and 40 CFR 60.48b(d), and simply to require that the SO 2 and NO X emission averages be calculated according to amended 40 CFR 60.13(h). CEMS Certification and Quality-Assurance. Today's proposed amendments would add two sections to appendix F, 40 CFR part 60, pertaining to the on-going quality-assurance requirements for CEMS. These proposed amendments would apply to sources that are subject to the QA requirements of both appendix F, 40 CFR part 60 and appendix B, 40 CFR part 75 and would serve a three-fold purpose: (1) To eliminate duplicative QA test requirements; (2) to allow a single set of data validation criteria to be applied to the CEMS data; and (3) to allow certain alternative 40 CFR part 75 performance specifications for low-emitting sources to be used for 40 CFR part 60 compliance. Today's proposed amendments also would amend section 8.3.1 of performance specification 2 (PS-2) in appendix B, 40 CFR part 60, to allow the 7-day calibration drift test to be performed on 7 consecutive unit operating days, rather than 7 consecutive calendar days. EPA proposes to add new sections 4.5 and 5.4 to appendix F, 40 CFR part 60. Under proposed section 4.5, sources would be allowed to implement the daily calibration error and calibration adjustment procedures in sections 2.1.1 and 2.1.3 of appendix B, 40 CFR part 75, instead of (rather than in addition to) the calibration drift (CD) assessment procedures in section 4.1 of appendix F, 40 CFR part 60. Sources electing to use this option would be required to follow the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B, 40 CFR part 75 instead of the excessive CD and out-of-control criteria in section 4.3 of appendix F, 40 CFR part 60. Proposed section 5.4 of appendix F, 40 CFR part 60 would allow sources to perform the quarterly linearity checks described in section 2.2.1 of appendix B, 40 CFR part 75, instead of (rather than in addition to) performing the cylinder gas audits described in section 5.1.2 of appendix F, 40 CFR part 60. If a source elected to use this option, then: (1) The linearity checks would be performed at the frequency prescribed in section 2.2.1 of appendix B, 40 CFR part 75; (2) the linearity error specifications in section 3.2 of appendix A, 40 CFR part 75 would have to be met; (3) the data validation criteria in section 2.2.3 of appendix B, 40 CFR part 75 would be applied in lieu of the excessive audit inaccuracy criteria in section 5.2 of appendix F, 40 CFR part 60; and (4) the grace period provisions in section 2.2.4 of appendix B, 40 CFR part 75 would apply. Proposed section 5.4 of appendix F, 40 CFR part 60 also would allow sources to perform the on-going quality-assurance relative accuracy test audit (RATA) of their NO X -diluent and SO 2 -diluent monitoring systems according to section 2.3 of appendix B, 40 CFR part 75. If a source elected to use this option, then: (1) The RATA frequency would be as specified in section 2.3.1 of appendix B, 40 CFR part 75; (2) the applicable relative accuracy specification in Figure 2 of appendix B, 40 CFR part 75 would have to be met; (3) the data validation criteria in section 2.3.2 of appendix B, 40 CFR part 75 would be applied in lieu of the excessive audit inaccuracy criteria in section 5.2 of appendix F, 40 CFR part 60; and (4) the grace period provisions in section 2.3.3 of appendix B, 40 CFR part 75 would apply. These proposed amendments to appendix F, 40 CFR part 60 would greatly simplify compliance without sacrificing data quality. Currently, sources that are required to perform periodic QA testing under both appendix F, 40 CFR part 60, and appendix B, 40 CFR part 75, have two reference frames for CEMS data validation. Neither the CEMS performance specifications nor the out-of-control criteria are the same in the two appendices. Generally speaking, the 40 CFR part 75 specifications and data validation criteria are more stringent than those of 40 CFR part 60. For example, when daily calibrations are performed, appendix F, 40 CFR part 60, allows the calibration drift of an SO 2 or NO X monitor to exceed 5 percent of span for 5 consecutive days before the monitor is declared out-of-control. Under appendix B, 40 CFR part 75, however, a monitor is considered out-of-control whenever the results of a daily calibration check exceed 5 percent of span. For a 40 CFR part 75 linearity check, three calibration gases are used (as opposed to two gases for a part 60 cylinder gas audit (CGA)), and the linearity error (LE) specification ( i.e. , LE ≤5 percent of the reference gas concentration) is much more stringent than the CGA acceptance criterion of 15 percent. For RATA, the principal 40 CFR part 75 relative accuracy specification is 10 percent, whereas the appendix F, 40 CFR part 60, specification is 20 percent. Thus, it is safe to say that the data from a CEMS that meets the quality-assurance requirements of appendix B, 40 CFR part 75 may be used with confidence for the purposes of 40 CFR part 60 compliance. Allowing sources to perform the 40 CFR part 75 QA in lieu of (rather than in addition to) appendix F, 40 CFR part 60, is actually consistent with section 1.1 of appendix F, 40 CFR part 60, which encourages sources to “develop and implement a more extensive QA program or continue such programs where they already exist.” It also harmonizes with 40 CFR 60.47a(c)(2) of subpart Da, 40 CFR 60.48b(b)(2) of subpart Db, and 40 CFR 60.334(b)(3)(iii) of subpart GG, which allows certified 40 CFR part 75 NO X monitoring systems to be used to demonstrate compliance with the applicable NO X emission limits. However, despite these clear statements in the amendments, today's proposed amendments to appendix F, 40 CFR part 60 are needed to eliminate any doubt that meeting the quality-assurance testing requirements of appendix B, 40 CFR part 75, fully satisfies the requirements of appendix F, 40 CFR part 60. Many operating permits have required sources to implement both appendix B, 40 CFR part 75, and appendix F, 40 CFR part 60, QA procedures for their CEMS. This has proved to be burdensome, not only because of the previously-mentioned differences in the specifications and data validation criteria between the two appendices, but also because 40 CFR part 60 cylinder gas audits and 40 CFR part 75 linearity checks are so similar in nature ( i.e. , they are essentially two tests of the same type). Since the linearity check is far more stringent than the CGA, many sources have questioned why CGA are necessary if quarterly linearity checks are being performed. Today's proposed amendments would effectively eliminate this duplicative QA test requirement. EPA is also proposing to amend section 8.3.1 of PS-2 in appendix B, 40 CFR part 60, to allow the 7-day calibration drift test, which is performed for the initial certification of a CEMS, to be performed on 7 consecutive unit operating days, rather than 7 consecutive calendar days. The intent of the proposed amendment is to provide regulatory relief to infrequently-operated units. Many new sources (particularly gas turbines) seldom, if ever, operate for 7 consecutive days, making the 7-day drift test difficult to perform. Allowing the test to be performed on 7 consecutive operating days should make the test much easier to complete within the time allotted for in [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A05-2996. Public record. Not legal advice.