# Standards of Performance for Coal Preparation and Processing Plants > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3AE9-23783 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** October 8, 2009 - **Citation:** 74 FR 51950 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 60 [EPA-HQ-OAR-2008-0260; FRL-8965-3] RIN 2060-AO57 Standards of Performance for Coal Preparation and Processing Plants AGENCY: Environmental Protection Agency (EPA). ACTION: Final rule. SUMMARY: EPA is promulgating amendments to the new source performance standards for coal preparation and processing plants. These final amendments include revisions to the emission limits for particulate matter and opacity standards for thermal dryers, pneumatic coal cleaning equipment, and coal handling equipment (coal processing and conveying equipment, coal storage systems, and coal transfer and loading systems) located at coal preparation and processing plants. These revised limits apply to affected facilities that commence construction, modification, or reconstruction after April 28, 2008. The amendments also establish a sulfur dioxide (SO 2 ) emission limit and a combined nitrogen oxide (NO X ) and carbon monoxide (CO) emissions limit for thermal dryers located at coal preparation and processing plants. In addition, the amendments establish work practice standards to control fugitive coal dust emissions from open storage piles located at coal preparation and processing plants. The SO 2 limit, the NO X /CO limit, and the work practice standards apply to affected facilities that commence construction, modification, or reconstruction of which commences after May 27, 2009. We are also modifying the definition of thermal dryer to include both direct contact and indirect contact thermal dryers drying all coal ranks. We are modifying the definition of pneumatic coal-cleaning equipment to include equipment cleaning all coal ranks. We are also amending the definition of coal for purposes of subpart Y to include coal refuse. The modified definitions of thermal dryer, pneumatic coal cleaning equipment, and coal will be used to determine whether and how the standards apply to facilities that commence construction, modification, or reconstruction after May 27, 2009. DATES: This final rule is effective on October 8, 2009. The incorporation by reference of certain publications listed in the regulation is approved by the Director of the Federal Register as of October 8, 2009. ADDRESSES: EPA has established a docket for this action which is Docket ID No. EPA-HQ-OAR-2008-0260. All documents in the docket are listed in the http://www.regulations.gov index. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, Standards of Performance for Coal Preparation and Processing Plants Docket, EPA West, Room 3334, 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 Docket Center is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy Strategies Group, Sector Policies and Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 27711, telephone number (919) 541-5025, facsimile number (919) 541-5450, electronic mail (e-mail) address: johnson.mary@epa.gov. SUPPLEMENTARY INFORMATION: The supplementary information presented in this preamble is organized as follows: I. General Information A. Does This Action Apply to Me? B. Where Can I Get a Copy of This Document? C. Judicial Review II. Background Information on Subpart Y III. Summary of the Final Amendments to Subpart Y and Changes Since Proposal A. Affected Facilities B. Emission Limits C. Emissions Testing and Monitoring Requirements D. Opacity Testing and Monitoring Requirements E. Recordkeeping and Reporting Requirements F. Electronic Reporting G. Additional Amendments IV. Summary of Significant Comments and Responses A. Regulated Pollutants B. Applicability and Definitions C. Subcategorization D. Coal Drying Standards E. Coal Processing and Conveying Equipment, Coal Storage Systems, Transfer and Loading Systems, and Open Storage Piles Standards F. Testing and Monitoring Requirements G. Recordkeeping and Reporting Requirements H. Assessment of Impacts V. Summary of Cost, Environmental, Energy, and Economic Impacts A. What Are the Primary Air Impacts? B. What Are the Water and Solid Waste Impacts? C. What Are the Energy Impacts? D. What Are the Secondary Air Impacts? E. What Are the Cost and Economic Impacts? VI. 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 Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act I. General Information A. Does This Action Apply to Me? Categories and entities potentially regulated by the final amendments to New Source Performance Standards (NSPS) for Coal Preparation and Processing Plants (40 CFR part 60, subpart Y) include: Category NAICS code 1 Examples of regulated entities Industry 212111 Bituminous Coal and Lignite Surface Mining. 212112 Bituminous Coal Underground Mining. 221112 Fossil Fuel Electric Power Generation. 212113 Anthracite Mining. 213113 Support Activities for Coal Mining. 322121 Paper (except Newsprint) Mills. 324199 All other petroleum and coal products manufacturing. 325110 Petrochemical Manufacturing. 327310 Cement Manufacturing. 331111 Iron and Steel Mills. 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. 1 North American Industry Classification System. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this final action. To determine whether your facility would be regulated by this final action, you should examine the applicability criteria in 40 CFR 60.250 and definitions in § 60.251 (subpart Y). If you have any questions regarding the applicability of this final action to a particular entity, contact the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. B. Where Can I Get a Copy of This Document? In addition to being available in the docket, an electronic copy of this final action is available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides information and technology exchange in various areas of air pollution control. C. Judicial Review Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of this final rule is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by December 7, 2009. Under section 307(b)(2) of the CAA, the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements. Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for us to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460. II. Background Information on Subpart Y NSPS implement CAA section 111(b) and are issued for categories of sources which have been identified as causing, or contributing significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. The primary purpose of the NSPS are to help States attain and maintain ambient air quality 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 in numerous industries by assuring cost-effective controls are installed on new, reconstructed, and modified sources. CAA section 111 requires that the NSPS reflect the degree of emission limitation achievable through 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). Standards of performance for coal preparation plants (40 CFR part 60, subpart Y) were promulgated in the Federal Register on January 15, 1976 (41 FR 2232). The standards are applicable to facilities which process more than 181 megagrams (Mg) (200 tons) of coal per day that commenced construction, reconstruction, or modification after October 24, 1974. CAA section 111(b)(1)(B) requires EPA to periodically review and revise the standards of performance, as necessary, to reflect improvements in methods for reducing emissions. The first review of the coal preparation plants NSPS was completed on April 14, 1981 (46 FR 21769). The second review of the coal preparation plants NSPS was completed on April 3, 1989 (54 FR 13384). EPA did not make changes to the NSPS as a result of either review. We proposed amendments to the coal preparation plants NSPS on April 28, 2008 (73 FR 22901) as a result of the current review. We received a total of 42 comments from coal preparation plants, industry trade associations, control technology vendors, environmental groups, and State environmental agencies during the comment period. After reviewing those comments and considering additional data, EPA decided to publish a supplemental proposal which revised some of the emission limits and monitoring requirements proposed on April 28, 2008, added additional limits, and applied the requirements to additional affected facilities. The supplemental action was proposed on May 27, 2009 (74 FR 25304). A total of 44 comments were received from coal preparation plants, other types of industrial facilities, industry associations, environmental groups, and State environmental agencies. This final rule reflects our consideration of all the comments we received regarding the April 2008 and May 2009 proposals. Detailed responses to the comments not included in this preamble are contained in the Summary of Public Comments and Responses document which is included in the docket for this rulemaking. III. Summary of the Final Amendments to Subpart Y and Changes Since Proposal A. Affected Facilities Subpart Y regulates affected facilities located at coal preparation and processing plants which process more than 181 megagrams (Mg) (200 tons) of coal per day. A coal preparation and processing plant begins at the first hopper ( i.e. , drop point) used to unload coal and ends at the load-out ( i.e. , distribution) of the coal either to a method of transportation ( e.g. , truck, train) or to the end-use piece of equipment ( e.g. , boiler). The affected facilities regulated by this final rule are thermal dryers, pneumatic coal-cleaning equipment, coal processing and conveying equipment (including breakers and crushers), coal storage systems, transfer and loading systems, and open storage piles. This final rule expands applicability of the existing NSPS by revising the definitions of thermal dryers, pneumatic coal-cleaning equipment, and coal. It also establishes work practice standards for open storage piles. The final rule amends the definition of thermal dryer for units constructed, reconstructed, or modified after May 27, 2009, to include both direct and indirect dryers drying all coal ranks ( i.e. , bituminous, subbituminous, lignite, and anthracite coals) and coal refuse. The final rule regulates emissions of SO 2 and NO X /CO only from thermal dryers that receive thermal input from the combustion of coal, coal refuse, or residual oil; PM and opacity are regulated from all thermal dryers. The emissions standards for thermal dryers apply to emissions from the heat source for an indirect thermal dryer only if those emissions are not otherwise regulated under another NSPS. Indirect thermal dryers use a heat transfer medium to supply heat and blow air over the coal to evaporate the water. If the source of heat (the source of combustion or furnace) is subject to another subpart of Part 60, then the furnace and the associated emissions are not considered part of the subpart Y affected facility ( i.e. , the thermal dryer). However, if the source of heat is not subject to another subpart of Part 60, then the furnace and the associated emissions are part of the subpart Y affected facility. In situations where the source of heat is part of the affected facility and its exhaust is combined with the dryer exhaust in a single stack, the combined exhaust is subject to all subpart Y requirements applicable to the thermal dryer exhaust. However, in situations where the furnace is part of the affected facility and its exhaust is not combined with the dryer exhaust, the subpart Y requirements for thermal dryers apply differently to the dryer exhaust and the combustion ( i.e. , heat source or furnace) exhaust. All of the thermal dryer requirements of subpart Y apply to the combustion exhaust, whereas, only a subset of the subpart Y requirements for thermal dryers apply to the dryer exhaust. In addition, thermal dryers that use residual or waste heat from the combustion of coal, coal refuse, or residual oil, or that obtain all of their thermal input from gaseous fuels ( e.g. , blast furnace gas, coke oven gas, natural gas) or distillate oil also are only be subject to certain subset of the subpart Y requirements for thermal dryers. Further, a thermal dryer that is part of an in-line coal mill at a Portland cement manufacturing plant where all of the thermal input is supplied by cement kiln exhaust or clinker cooler exhaust, is not subject to the requirements in subpart Y, but, rather, must meet the applicable requirements in the appropriate Portland Cement kiln regulations (40 CFR 60 subpart F and 40 CFR 63 subpart LLL). The amended subpart Y emissions limits for thermal dryers apply to new, reconstructed, or modified thermal dryers at Portland cement manufacturing plants in situations where the thermal input is not supplied by cement kiln or clinker cooler exhaust. Other subpart Y affected facilities located at Portland cement manufacturing plants ( e.g. , storage systems, conveyors) are also subject to the requirements of subpart Y. Similarly, a coal thermal dryer at an integrated iron or steel manufacturing plant where all of the thermal input is provided by process gases is not regulated under subpart Y, but, rather, under 40 CFR part 60 standards for integrated iron and steel manufacturing plants. Again, the amended emissions limits apply to new, reconstructed, or modified thermal dryers at integrated iron and steel manufacturing plants only in situations where the thermal input is not supplied by process gases. Other subpart Y affected facilities located at integrated iron and steel manufacturing plants also are subject to subpart Y. If an affected facility under subpart Y uses waste-heat or process gases from a process that is subject to emission limits under another NSPS or national emission standard for hazardous air pollutant (NESHAP), the process using the waste-heat or process gases is not subject to requirements under subpart Y, but, rather, is subject to the other applicable NSPS or NESHAP. This final rule also amends the definition of pneumatic coal-cleaning equipment for units constructed after May 27, 2009, to include pneumatic coal-cleaning equipment cleaning all coal ranks. Finally, the final rule establishes work practice standards that apply to open storage coal piles constructed, reconstructed or modified after May 27, 2009. B. Emission Limits This action promulgates emission limits applicable to certain thermal dryers constructed, reconstructed, or modified after April 28, 2008. It also promulgates emission limits for additional pollutants applicable to certain thermal dryers constructed, reconstructed, or modified after May 27, 2009. Direct-contact thermal dryers that use coal, coal refuse, or residual oil as the dryer heat source and are constructed, reconstructed, or modified after April 28, 2008, are subject to emission limits for PM and opacity. Indirect thermal dryers constructed, reconstructed, or modified after May 27, 2009, are subject to the same PM and opacity limits as direct-contact thermal dryers. Both direct-contact thermal dryers and indirect thermal dryers constructed, reconstructed, or modified after May 27, 2009, are subject to an SO 2 emission limit and a combined NO X -CO emissions limit. In certain instances, thermal dryers are not subject to the SO 2 and/or NO X -CO emission limits. Thermal dryers constructed, reconstructed or modified after May 27, 2009, for which all of the thermal input is supplied from a source other than coal, coal refuse, or residual oil ( i.e., thermal input is from gaseous fuels such as blast furnace gas, coke oven gas, or natural gas, or distillate oil) are not subject to SO 2 or NO X -CO emission limits. Indirect thermal dryers constructed, reconstructed, or modified after May 27, 2009, that use residual or waste heat from the combustion of coal, coal refuse, or residual oil also are not subject to the emission limits for SO 2 or NO X -CO. Indirect thermal dryers that receive all of their thermal input from a source subject to an SO 2 limit, or NO X and/or CO limit, under another Part 60 NSPS are not subject to emission limits under subpart Y for those pollutants ( e.g. , indirect thermal dryers for which the source of heat is subject to a boiler NSPS (subpart Da, Db, or Dc)). In that instance, the furnace ( i.e. , source of thermal input) and the associated emissions are not considered part of the subpart Y thermal dryer facility. However, if the source of heat is not subject to another Part 60 NSPS, then the furnace and the associated emissions are part of the subpart Y thermal dryer facility. In the instance where the furnace is part of the affected facility and its exhaust is combined with the thermal dryer exhaust, the combined exhaust contains all of the applicable pollutants ( i.e. , PM, opacity, SO 2 , NO X , and CO) and all of the subpart Y requirements regarding those emissions from thermal dryers apply. However, in the instance where the furnace is part of the affected facility, but its exhaust is not combined with the dryer exhaust, the furnace exhaust and dryer exhaust are subject to different requirements. The furnace exhaust is subject to emission limits for PM, opacity, SO 2 , and NO X -CO. The dryer exhaust, however, is only subject to the PM and opacity limits because the exhaust does not contain SO 2 , NO , and CO. 1. PM and Opacity Limits for Thermal Dryers Thermal dryers constructed, reconstructed, or modified after April 28, 2008, are subject to emission limits for PM and opacity. The PM and opacity limits in the final rule for new thermal dryers are the same as those proposed in May 2009. EPA determined that thermal dryers undergoing reconstruction could undergo the conversions necessary to also comply with the PM and opacity limits that reflect BDT for new thermal dryers ( i.e. , fabric filter-controlled recirculation thermal dryers and fabric filter-controlled indirect thermal dryers). Thus, the final rule subjects new and reconstructed thermal dryers to a PM limit of 0.023 grams per dry standard cubic meter (g/dscm)(0.010 grains per dry standard cubic foot (gr/dscf)) and an opacity limit of less than 10 percent. The final rule requires modified thermal dryers to continue to comply with the 1976 rule's PM limit of 0.070 g/dscm (0.031 gr/dscf) and the 1976 rule's opacity limit of less than 20 percent. These limits can be achieved using the technology that EPA determined constitutes BDT for modified thermal dryers ( i.e. , venturi scrubbers). 2. SO 2 , NO X , and CO Limits for Thermal Dryers Thermal dryers constructed, reconstructed, or modified after May 27, 2009, must either limit their SO 2 emissions to 85 nanograms per Joule (ng/J) (0.20 pounds per million British thermal units (lb/MMBtu)), or achieve a 90 percent reduction of potential SO 2 emissions and limit their SO 2 emissions to no more than 520 ng/J (1.2 lb/MMBtu). The percent reduction requirement has been revised from the 50 percent requirement proposed in May 2009 to 90 percent in the final rule. In the May 27, 2009, supplemental proposal, EPA concluded that dry sorbent injection into the thermal dryer and spraying caustic onto the coal prior to the thermal dryer were both BDT for SO 2 reduction (74 FR 25310). We also indicated that we were considering an SO 2 percent reduction requirement of between 50 and 90 percent for the final rule (74 FR 25311). We have reassessed the available SO 2 data and believe that the limits established in the final rule are appropriate for new, reconstructed, and modified thermal dryers. Based on our reassessment, we determined that BDT for modified and reconstructed thermal dryers is a wet scrubber with a scrubbing reagent ( e.g. , an upgraded venturi scrubber with sodium hydroxide or packed bed scrubber with lime). For new thermal dryers, we determined that BDT for controlling SO 2 emissions is the injection of sodium hydroxide directly to the venturi scrubber fluid or injection of a sodium-based sorbent into the combustion gases prior to the drying chamber. All three of these technologies are capable of achieving 90 percent SO 2 reduction. In the May 27, 2009, supplemental proposal, EPA determined that BDT for controlling NO X emissions from new, reconstructed, and modified thermal dryers is combustion controls ( e.g. , low NO X burners, staged combustion, co-firing with natural gas or liquefied petroleum gas, and flue gas recirculation). BDT for controlling CO emissions was determined to be good combustion practices ( e.g. , ensuring that there is sufficient oxygen in the combustion zone, maintaining appropriate combustion zone temperature and gas residence time, and conducting proper operation and maintenance of the dryer). For affected thermal dryers that commence construction, reconstruction, or modification after May 27, 2009, the final NO X -CO emissions limits are the same as those proposed in May 2009. Reconstructed and modified thermal dryers are required to comply with a combined NO X -CO limit of 430 ng/J (1.0 lb/MMBtu). New thermal dryers are required to comply with a NO X -CO limit of 280 ng/J (0.65 lb/MMBtu). 3. PM and Opacity Limits for Pneumatic Coal-Cleaning Equipment, Coal Processing and Conveying Equipment, Coal Storage Systems, Transfer and Loading Systems, and Open Storage Piles The PM and opacity limits in the final rule for pneumatic coal-cleaning equipment are the same as those proposed in the May 2009 supplemental proposal. Pneumatic coal-cleaning equipment, cleaning all coal ranks, constructed, reconstructed, or modified after April 28, 2008, must comply with a PM limit of 0.023 g/dscm (0.010 gr/dscf) and an opacity limit of equal to or less than 5 percent. For affected coal-handling equipment (coal processing and conveying equipment (including breakers and crushers), coal storage systems, and transfer and loading systems) constructed, reconstructed, or modified after April 28, 2008, that is mechanically vented to the atmosphere, the final rule requires compliance with the PM limit that was proposed in May 2009. That is, mechanically vented coal-handling equipment constructed, reconstructed, or modified after April 28, 2008, must comply with a PM limit of 0.023 g/dscm (0.010 gr/dscf). The final rule also requires affected coal handling equipment constructed, reconstructed, or modified after April 28, 2008, to maintain opacity levels of less than 10 percent. In the May 27, 2009, supplemental proposal, EPA requested comment on whether an opacity limit of less than 10 percent is more appropriate than a limit of 5 percent as proposed in the supplemental action. We also requested comment on whether the 5 percent limit is achievable on a long-term basis and whether the limit provides an adequate compliance margin. As we pointed out in supporting documentation ( see EPA-HQ-OAR-2008-0260-0083, pp. 3-4), the data used to establish the supplemental proposal's 5 percent opacity level were primarily from initial compliance tests. Upon reconsideration of EPA's data and consideration of public comments and additional supporting data, EPA has determined that an opacity limit of less than 10 percent is more appropriate for all coal handling equipment. An opacity limit of 10 percent will allow for control equipment degradation, adverse conditions, and variability that would not be reflected in initial compliance tests. Although we modified our conclusion regarding the opacity limit achievable by the application of BDT, we did not modify our prior conclusions regarding BDT for coal-handling equipment. BDT for coal-handling equipment used on subbituminous and lignite coals consists of four technologies—fabric filters, passive enclosure containment systems (PECS), fogging systems, and wet extraction scrubbers. BDT for coal-handling equipment processing bituminous coal is the use of chemical suppressants. All of these emissions reduction measures can control PM emissions equally well. See EPA-HQ-OAR-2008-0260-0083, pp. 1-2. EPA also concluded that if a building in which affected coal processing and conveying equipment ( e.g. , breakers, crushers, screens, conveying systems), coal storage systems, and transfer system operations are enclosed is found to be in compliance with the subpart Y limits that apply to the affected facilities enclosed in the building, the affected facilities enclosed in that building also are in compliance. Thus, the final rule provides that buildings containing coal processing and conveying equipment, coal storage systems, and transfer system operations constructed, reconstructed, or modified on or before April 28, 2008, must not exhibit 20 percent opacity or greater. Fugitive emissions from buildings that enclose coal processing and conveying equipment, coal storage systems, and coal transfer system operations constructed, reconstructed, or modified after April 28, 2008, must not exhibit opacity of 10 percent or more. For buildings enclosing coal processing and conveying equipment, coal storage systems, and transfer system operations constructed, reconstructed, or modified after April 28, 2008, that discharge emissions from a mechanical vent, emissions must not contain PM in excess of 0.023 g/dscm (0.010 gr/dscf). 4. Open Storage Pile Requirements EPA's May 27, 2009, supplemental action proposed to establish work practice standards for open storage piles and roadways. EPA determined that it was not feasible to establish opacity or PM limits for these types of affected facilities. At the current time, EPA believes it is difficult and prohibitively expensive to measure actual PM emissions from individual open storage piles or roadways. Further, the size of open storage piles and the mobile nature of coal dust from vehicle tires on roadways currently make the use of Method 9 opacity observations unreasonable in many situations. Based on that determination, we proposed to require owners or operators of open storage piles and roadways associated with coal preparation plants to develop and comply with a fugitive coal dust emissions control plan to control fugitive PM emissions. Commenters pointed out that the Surface Mining Control and Reclamation Act (SMCRA) covers fugitive dust emissions from roads at coal preparation and processing plants at mine sites and requires a fugitive dust plan. EPA believes that coal moving operations, once the coal enters the “coal preparation plant,” will be by conveyor rather than by truck. Therefore, we believe that the requirements of SMCRA are sufficient to address air emissions from roadways that may be found within a coal preparation and processing plant at mine sites. For coal preparation and processing plants at end-user facilities, we believe that, again, once the coal enters the “coal preparation plant,” coal moving operations will be by conveyor rather than by truck. Thus, EPA has decided not to finalize the proposed requirements for roadways. EPA also proposed to require that the fugitive coal dust emissions control plan include procedures for limiting emissions from all types of “coal processing and conveying equipment” at a coal preparation and processing plant. EPA agrees with commenters that subpart Y should specifically designate each type of affected facility subject to the fugitive dust emissions control plan and, therefore, we are not finalizing that proposed requirement. A fugitive coal dust emissions control plan is required for open storage piles, which include the equipment used in the loading, unloading and conveying operations of the affected facility, constructed, reconstructed or modified after May 27, 2009. The owner or operator is required to prepare and operate in accordance with a submitted fugitive coal dust emissions control plan that is appropriate for the site conditions. The fugitive coal dust emissions control plan must identify and describe the control measures the owner/operator will use to minimize fugitive coal dust emissions from each open storage pile. The owner or operator is also required to explain how the measures are applicable and appropriate for the site conditions. For open coal storage piles, the fugitive coal dust emissions plan must require that one or more of the following control measures will be used to minimize to the greatest extent practicable fugitive coal dust: locating the source inside a partial enclosure, installing and operating a water spray or fogging system, applying appropriate chemical dust suppression agents on the source (when additional provisions discussed below are met), use of a wind barrier, compaction, or use of a vegetative cover. The owner or operator must select, from the list provided, the control measures that are most appropriate for the site conditions. Where appropriate chemical dust suppression agents are selected by the owner/operator as a control measure to minimize fugitive coal dust emissions, only chemical dust suppressants with Occupational Safety and Health Administration (OSHA)-compliant material safety data sheets (MSDS) are allowed, the MSDS must be included in the fugitive coal dust emissions control plan, and the owner/operator must consider and document in the fugitive coal dust emissions control plan the site-specific impacts associated with the use of such chemical dust suppressants ( e.g. , water run-off, water quality concerns). An owner/operator may petition the Administrator requesting approval of a control measure other than those specified above. The petition process established in the final rule is similar to the process used in 40 CFR Part 60, subpart Db, to establish alternative NO X limits for certain industrial boilers. The petition must demonstrate to the Administrator that the alternate control measure will provide equivalent overall environmental protection or that it is either economically or technically infeasible for the affected facility to use the control measures specified above. The owner/operator must operate in accordance with the plan including the alternative measures and, while operating in accordance with the plan submitted with the petition, is deemed to be in compliance with the fugitive coal dust emissions control plan requirements while the petition is pending. EPA decided to include this petition process in the final rule in response to comments objecting to provisions proposed in the May 2009 supplemental proposal that would have provided for permitting authority approval of the fugitive coal dust emissions control plans and allowed the permitting authorities to approve the use of alternate technologies if it had been determined that the technology provides equivalent overall environmental protection. Each owner/operator must submit their fugitive coal dust emissions control plan to the Administrator or delegated authority to provide an opportunity for the Administrator or delegated authority to object to the fugitive coal dust emissions control plan. The fugitive coal dust emissions control plan must be submitted to the Administrator or delegated authority prior to the startup date for the affected facility. If an objection is raised, the owner/operator has 30 days from receipt of the objection to submit a revised fugitive coal dust emissions control plan. The owner/operator must operate in accordance with the revised fugitive coal dust emissions control plan. The Administrator and delegated authority retain the ability to object to the revised fugitive coal dust emissions control plan. C. Emissions Testing and Monitoring Requirements Based on our review of public comments submitted in response to the May 27, 2009, supplemental proposal and further analysis, minor revisions were made to certain emissions testing and monitoring requirements included in that supplemental proposal. The testing and monitoring requirements of the final rule are described below. All affected facilities subject to emissions limits are required to conduct initial emissions testing to show compliance with the limits included in the final rule. PM emissions must be measured with EPA Method 5, 5B, or 5D of 40 CFR Part 60, appendix A-4, or EPA Method 17 of 40 CFR Part 60, appendix A-7. EPA Method 6, 6A, or 6C of 40 CFR Part 60, appendix A-4, must be used to measure SO 2 emissions. NO X and CO emissions must be measured with EPA Method 7 or 7E, and Method 10, respectively, of 40 CFR Part 60, appendix A-4. In addition, CO and NO X performance testing must be conducted concurrently, or within a 60-minute period. Initial testing for PM emissions is required for coal-handling equipment exhaust that is mechanically vented and for thermal dryer exhaust. Depending on the type of thermal dryer and its fuel type, initial testing for SO 2 , NO X , and CO may also be required. Following initial performance testing, the frequency of subsequent emissions testing is variable. If an affected facility, excluding thermal dryers, has a design controlled potential PM emissions rate, considering controls, of 1.0 Mg (1.1 tons) per year or less, annual performance testing is not required as long as: (1) PM emissions, as determined by the initial performance test, are less than or equal to the applicable PM limit; (2) the manufacturer's recommended maintenance procedures for each control device are followed; and (3) all 6-minute average opacity readings from the most recent Method 9 performance test are equal to or less than half the applicable opacity limit. In addition, for similar, separate affected facilities using identical control equipment, the Administrator or delegated authority may authorize a single emissions test as adequate demonstration for up to four other similar, separate affected facilities as long as: (1) The most recent performance test for each affected facility shows that performance of each affected facility is 90 percent or less of the applicable emissions limit; (2) the manufacturer's recommended maintenance procedures for each control device are followed; and (3) each affected facility conducts a performance test for each pollutant for which they are subject to a limit at least once every 5 years. Affected facilities that, based on their most recent performance test, emit at a level that is 50 percent or less of an applicable emissions limit are only required to conduct performance testing every 24 months, as opposed to every 12 months. Finally, an owner/operator of an affected facility that has not operated for the 60 calendar days prior to the due date of a performance test is not required to perform the performance test until 30 calendar days after the next operating day. The final rule requires the use of bag leak detection systems on subpart Y affected facilities with fabric filters that have a design controlled potential PM emissions rate of 25 Mg (28 tons) or more. This requirement applies to affected facilities constructed, reconstructed, or modified after April 28, 2008. For affected facilities with venturi scrubbers, continuous measurement of the pressure loss through the venturi constriction of the scrubber and of the liquid flow rate to the scrubber is required. If the venturi scrubber is used to control SO 2 emissions, pH of the scrubber liquor also must be continuously measured. For affected facilities using packed bed scrubbers with the addition of lime, the liquid flow rate to the scrubber and the scrubber liquor pH must be continuously measured. The final rule does not require continuous measurement of the temperature of the gas stream at the exit of the thermal dryer for affected facilities constructed, reconstructed, or modified after April 28, 2008. In the supplemental proposal, EPA requested comment on the utility of collecting continuous temperature data and determined that the requirement can be eliminated without risk of a significant increase in emissions. D. Opacity Testing and Monitoring Requirements Numerous comments were submitted to EPA regarding the opacity testing and monitoring requirements included in the May 27, 2009, supplemental proposal. Commenters objected to the proposed procedures as being unreasonable, burdensome, too complex, and confusing. Based on our review of public comments and further analysis, we modified the proposed requirements where we determined the burden could be reduced without compromising the integrity of the overall testing and monitoring requirements. We also attempted to make the requirements in the final rule less complex than those included in the supplemental proposal. All affected facilities subject to emissions limits are required to conduct initial emissions testing to show compliance with the opacity limits included in the final rule. Opacity must be measured with EPA Method 9 of 40 CFR part 60, appendix A-4. The final rule allows the use of a continuous opacity monitoring system (COMS) as an alternative to all other opacity monitoring requirements. The final rule includes a 60-minute observation period for Method 9 performance testing. The observation period may be decreased from 60 minutes to 30 minutes if, during the initial 30 minutes of the observation of a Method 9 performance test, all the 6-minute averages are less than or equal to half the applicable opacity limit. In the final rule, the frequency of subsequent visible emissions testing is based on the 6-minute average opacity readings from the most recent performance test. Owners/operators of affected facilities where any 6-minute average opacity reading in the most recent Method 9 performance test exceeds half the applicable opacity limit are required to conduct a Method 9 performance test within 90 days of the previous performance test. Owners/operators of affected facilities where all 6-minute average opacity readings in the most recent Method 9 performance test are equal to or less than half the applicable opacity limit are required to conduct a Method 9 performance test within 12 months of the previous performance test. Further, if a Method 9 opacity performance test is conducted concurrently with (or within a 60-minute period of) a Method 5, 5B, or 5D PM performance test for affected sources with wet scrubbers that continuously monitor the specified scrubber parameters, no subsequent Method 9 opacity performance testing is required. The final rule allows simultaneous Method 9 opacity performance testing for up to three emissions points as long as all three emissions points are within a 70-degree viewing sector or angle in front of the observer such that the proper sun position can be maintained for all three points. If an opacity reading for any one of the three emissions points is within 5 percent opacity from the applicable standard (excluding readings of zero opacity), the observer must stop taking readings for the other two points and continue reading just that single point. As an alternative to subsequent Method 9 performance testing, the final rule allows owners/operators of affected facilities to elect to conduct monitoring as follows: (1) Monthly visual observations of process and control equipment must be conducted and, if any deficiencies are observed, the necessary maintenance must be performed as expeditiously as possible; and (2) daily walkthrough observations consisting of a single 15-second observation ( i.e., visible emissions or no visible emissions) of each affected facility must be conducted and, if any visible emissions are observed, within 24 hours corrective actions must be conducted and the owner/operator must demonstrate that there are no visible emissions. If visible emissions are still observed, a Method 9 performance test must be conducted within 45 operating days to show compliance with the applicable opacity limit. The final rule requires that Method 9 performance testing must be conducted at least once every 5 years for each affected facility complying with this alternative monitoring option. Each observer determining the presence of visible emissions is required to meet the training requirements of Method 22 of appendix A-7 of 40 CFR Part 60. The final rule also allows the use of a digital opacity monitoring system in lieu of subsequent Method 9 performance testing. The Administrator may approve opacity monitoring plans for owners/operators that elect to use the digital opacity monitoring system to detect the presence of visible emissions. The final rule includes separate opacity testing and monitoring requirements for coal truck dump operations. EPA determined that a different approach for Method 9 opacity performance testing is warranted due to the intermittent nature of coal truck dumping. Coal truck dump operations are subject to the same opacity limits as other coal handling operations. The final rule specifies that compliance with the opacity limit is determined by averaging all Method 9 15-second opacity readings made during the duration of three separate truck dump events. A truck dump event commences when the truck bed begins to elevate and concludes when the truck bed returns to a horizontal position. The final rule requires monthly visual observations of the truck dump equipment and, if any deficiencies are observed, the necessary maintenance must be conducted as expeditiously as possible. Subsequent Method 9 opacity performance testing using the three truck dump procedure is required to be conducted every 90 days. E. Recordkeeping and Reporting Requirements The final rule requires that a logbook be maintained by each owner/operator of a coal preparation and processing plant that commences construction, reconstruction, or modification after April 28, 2008. The logbook must include records of subpart Y requirements regarding manufacturers' recommended maintenance procedures for process and control equipment, visual observations of coal-handling equipment, the amount and type of coal processed, the amount of chemical stabilizer or water purchased, the operational status of dust suppressant systems, compliance with a fugitive coal dust emissions control plan, BLDS operation, and measurement of monitoring parameters ( e.g., scrubber pressure loss, water supply flow rate, pH of scrubber fluid). F. Electronic Reporting The final rule requires owners/operators of affected facilities at coal preparation and processing plants to submit an electronic copy of all performance test reports to an EPA electronic data base (WebFIRE). Data entry requires access to the Internet and is expected to be completed by the stack testing company as part of the work that they are contracted to perform. Submittal to WebFIRE is required as of July 1, 2011. For performance tests not accepted by WebFIRE, owner/operators are required to mail summary results directly to EPA. G. Additional Amendments The final rule confirms the subpart Y title change from Coal Preparation Plants to Coal Preparation and Processing Plants. In addition to revising the definitions for coal, pneumatic coal-cleaning equipment, and thermal dryer as described in section III.A of this preamble, the final rule amends the definition for bituminous coal; adds definitions for anthracite, bag leak detection system, coal refuse, design controlled potential emissions rate, indirect thermal dryer, lignite, mechanical vent, operating day, potential combustion concentration, and subbituminous coal; and deletes the definition for cyclonic flow. The definition of coal refuse in the final rule has been modified to be consistent with the definition of coal refuse in 40 CFR part 60, subpart Da. Also, EPA is not finalizing the April 28, 2008, proposed revision to the definition of coal processing and conveying equipment, but is clarifying that equipment located at the mine face is not considered to be part of the coal preparation plant. In addition, the May 27, 2009, proposed revision to the definition of coal storage system is also not being promulgated. Rather, the final rule adds a definition for open storage pile. IV. Summary of Significant Comments and Responses As explained in Section II of this preamble, EPA proposed amendments to the coal preparation plants NSPS on April 28, 2008, (73 FR 22901) and received a total of 42 comments from coal preparation plants, industry trade associations, control technology vendors, environmental groups, and State environmental agencies. After reviewing those comments and considering additional data, EPA decided to publish a supplemental proposal ( see 74 FR 25304, May 27, 2009) which revised some of the requirements proposed on April 28, 2008. A total of 44 comments regarding the supplemental proposal were received from coal preparation plants, other types of industrial facilities, industry associations, environmental groups, and State environmental agencies. Responses to comments regarding the April 28, 2008, proposal are not discussed in this preamble. In many instances, the May 27, 2009, supplemental proposal either addressed the comment or made revisions that negated the comment. Significant comments received regarding the May 27, 2009, supplemental proposal and EPA's responses to those comments are discussed below. Detailed responses to the comments not included in this preamble, including responses to the comments regarding the April 28, 2008, proposal, are contained in the Summary of Public Comments and Responses document which is included in the docket for this rulemaking. A. Regulated Pollutants Comment: Many commenters stated that EPA's authority to promulgate NSPS requires an endangerment finding for the coal preparation plant source category and the pollutant(s) of interest. Because EPA has not made such a finding for SO 2, NO X , or CO emissions from coal preparation plants, the commenters contend that emissions standards for SO 2 , NO X , or CO applicable to coal preparation plants under subpart Y cannot be set. Response: CAA section 111(b)(1)(A) requires the Administrator to publish a list of categories of stationary sources and include a category of sources on that list if he finds that “in his judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” 42 U.S.C. 7411(b)(1)(A) (CAA section 111(b)(1)(A)). The plain language of section 111(b)(1)(A) provides that such findings are to be made for source categories, not for specific pollutants emitted by the source category. Therefore, once the Administrator determines that the source category causes or contributes significantly to air pollution which may endanger public health or welfare, the Administrator must add the source category to the section 111(b)(1)(A) list and subsequently establish standards of performance for the sources in that source category. Determinations regarding the specific pollutants to be regulated are made, not in the initial endangerment finding, but at the time the performance standards are promulgated. In addition, CAA section 111(b)(1)(B) requires EPA to review and revise, if appropriate, the standards at least every eight years. In conducting that review, EPA has discretion to revisit its original determination regarding which pollutants emitted from the source category should be regulated. Neither the text of the CAA nor subsequent statements of EPA provide any support for the argument that an endangerment finding must be made for specific pollutants or for the argument that the scope of the revised NSPS must be limited to the pollutants (or affected facilities) regulated in the initial NSPS. The text of section 111(b)(1)(A) provides no support for the argument that section 111 endangerment findings must be made for each pollutant emitted by the source category before that pollutant can be regulated in the NSPS. In contrast, the statutory text calls for a list of “categories of stationary sources.” It does not require, at the time of listing, an identification of all the specific pollutants emitted by the source category that may endanger public health or welfare. Instead, it requires only a general determination that emissions from the category cause or contribute to air pollution that may endanger public health or welfare. The endangerment finding is used to identify categories of sources for regulation, not to dictate the substantive content of the required standards of performance. The endangerment finding neither requires regulation of each pollutant emitted by the source category, nor limits EPA's discretion to determine (in the initial regulation or in subsequent revisions) which pollutants should be regulated. Instead, section 111(b)(1)(B) requires the Administrator, after publishing proposed regulations and providing an opportunity for comment, to promulgate such standards as the Administrator “deems appropriate.” The statutory scheme thus provides EPA with significant discretion to determine which pollutant(s) should be regulated under the NSPS. The Agency has long interpreted section 111(b)(1)(B) as providing the Administrator with this flexibility. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 n.27 (DC Cir. 1980) (explaining reasons for not promulgating standards for NO X , SO 2 and CO from lime plants); see also National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 1221, 1228-1230 (DC Cir. 2007) (finding that the “deems appropriate” language in CAA section 231 provides a “delegation of authority” that is “both explicit and extraordinarily broad”). EPA has, in prior NSPS rulemakings, exercised its discretion to identify pollutants for regulation. It has sometimes exercised this discretion to defer regulation of specific pollutants to a later date. See, e.g., 52 FR 36678, 36682 (September 30, 1987) (noting in subpart DDD proposal that “standards development for this industry is focusing initially on limiting emissions of VOC”); 49 FR 2656, 2659 (Jan 20, 1984) (explaining why SO 2 and VOC were the only pollutants in the natural gas production industry selected for regulation under subpart LLL “at this time.”); 48 FR 37338, 37340-42 (Aug. 17, 1983) (declining to regulate in subpart AAa, emissions of pollutants for which adequately demonstrated control technology was not currently available). EPA has also exercised this discretion to promulgate, during 8-year review rulemakings, new performance standards for pollutants not previously covered by the NSPS in question. See, e.g., 52 FR 24624, 24710 (July 1, 1987) (considering PM 10 controls in future rulemakings); 71 FR 9866 (Feb. 27, 2006) (establishing new PM standards for boilers); 73 FR 35838 (June 24, 2008) (adding NO X limits for fluid catalytic cracking units, NO X limits for fluid coking units and NO X limits for process heaters to the refineries NSPS). In addition, EPA has previously noted its disagreement with comments implying that an additional endangerment finding would be required to support regulation of a pollutant not previously regulated in that specific NSPS. See, e.g., 73 FR 35838, 35859 n2 (June 24, 2008). Further, the argument that EPA must issue a separate endangerment finding before regulating a pollutant not previously regulated in the NSPS for a source category is illogical. Once EPA has determined that a source category causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare emissions from a source category, the recognition that the source has emissions above and beyond those discussed in the original endangerment finding could only serve to strengthen the basis for the endangerment finding for the source category. Further, the listing of the source category is only the first step in the process. Once the finding is made, the statute allows the more detailed analysis of which pollutants are actually emitted and should be regulated to be conducted in the rulemaking process used promulgate and revise the standards for the source category. Finally, it is worth noting that EPA previously addressed this topic in the context of the subpart Y NSPS for coal preparation and processing plants. Coal preparation plants were listed under section 111(b)(1)(A) on October 24, 1974, pursuant to the Administrator's determination that such plants “may contribute significantly to air pollution which causes or contributes to the endangerment of public health or welfare.” 39 FR 37,807 (Oct. 24, 1974). The Background Information Document for the subpart Y standards proposed at that time explains the process to be used for setting NSPS and explicitly notes that “[a]lthough a source category may be selected to be covered by a standard of performance, treatment of some of the pollutants of facilities within that source category may be deferred.” Background Information for Standards of Performance: Coal Preparation Plants Volume 1: Proposed Standards at ix. For these reasons, EPA disagrees with the comment suggesting that EPA cannot set SO 2 , NO X , or CO emissions standards applicable to coal preparation plants under subpart Y. Comment: One commenter stated that EPA should recognize its obligation to promulgate NSPS for emissions of carbon dioxide (CO 2 ), nitric oxide (N 2 O), and black carbon (a component of PM) from coal preparation and processing plants. The commenter asserts that because these pollutants are the result of incomplete fuel combustion, they are emitted at coal prep plants, particularly by thermal dryers heated by coal or other fossil fuels. Emissions of each pollutant, the commenter asserts, carries individual and distinct risks and is controlled by different technologies so EPA must fully analyze each pollutant and set separate NSPS for each. Response: At this time EPA is not aware of any emissions or mitigation data for the pollutants noted by the commenter for this source category. Hence, we lack sufficient information on which to base an NSPS for emissions of CO 2, N 2 O, and black carbon from the source category at this time. Rough estimates of CO 2 from this source category suggest that this source category would be among the smaller CO 2 -emitting NSPS categories. At this time, we are not making any final determination regarding whether it would be appropriate to set such standards. In addition, to the extent the comment suggests that EPA should utilize its authority under other provisions of the CAA to require sources to gather and report GHG emissions and to the extent it raises issues not opened for public comment in the supplemental proposal, it is beyond the scope of this rulemaking. Comment: One commenter asserts that CAA section 111 carries a mandate for EPA to set NSPS for the pollutants emitted by a source. The commenter cites to language in section 111(a)(3) that defines a stationary sources as any building, structure, facility or installation which emits or may emit any air pollution and language in section 111(b)(4) defining a modification as a physical or operational change which increases the amount of any air pollution emitted by the source. In addition, the commenter cites to the Supreme Court's decision in Massachusetts v. EPA, 549 U.S. 497, 529 (2007) and EPA's April 2009 Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases (74 FR 18886 (Apr. 24, 2009)). Response: The Agency has long exercised its discretion to regulate only a subset of the pollutants emitted by a source category or to defer regulation of certain pollutants to a later date. See e.g., National Lime Assoc. v. EPA, 627 F.2d 416, 426 n.27 (DC Cir. 1980) (explaining reasons for not promulgating standards for NO X , SO 2 , and CO from lime plants); National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 1221, 1228-1230 (DC Cir. 2007) (finding that the “deems appropriate” language in CAA section 231 provides a “delegation of authority” that is “both explicit and extraordinarily broad”); 52 FR 36678, 36682 (September 30, 1987) (explaining Subpart DDD standards' initial focus on limiting emissions of VOC); 49 FR 2656, 2659 (January 20, 1984) (explaining Subpart LLL regulates only emissions of SO 2 and VOC); 48 FR 37338, 37340-42 (August 17, 1983) (explaining why Subpart AAa does not regulate emissions of pollutants for which adequately demonstrated control technology was not currently available). B. Applicability and Definitions Comment: Many commenters stated that EPA proposed to add “processing” to the title of subpart Y and, although EPA indicated in the preamble to the May 27, 2009, supplemental proposal, that it did not intend to change the applicability of subpart Y, the commenters are concerned that EPA has not adequately justified the need to make the change. Subpart Y already defines “processing equipment” as “machinery used to reduce the size of coal or to separate coal from refuse.” Despite EPA's stated intentions, commenters believe that the risk exists that EPA, in future applicability interpretations, will determine that additional, non-preparation operations meet the meaning of processing, and will thereby bring them under subpart Y purview. To avoid confusion, the commenters stated that EPA should remove “processing” from the title. Response: In the preamble to the supplemental proposal, EPA indicated that the proposed title change was for clarification purposes ( i.e., to more accurately reflect the affected facilities subject to subpart Y). The affected facilities covered by subpart Y since its 1976 promulgation include both preparation and processing units. We do not intend the title change to have any impact on the extent of EPA's authority to regulate specific affected facilities now or in the future. The final action promulgates the proposed title change “Standards of Performance for Coal Preparation and Processing Plants.” Comment: Many commenters acknowledged that in its May 27, 2009, supplemental action, EPA proposed to amend the definition of “coal” to include “coal refuse” and “petroleum coke.” These commenters objected to EPA's proposed inclusion of “coal refuse” because its inclusion further expands the subpart Y applicability with no data specific to “coal refuse” on what constitutes adequately demonstrated technologies and their respective levels of achievable emissions. Specifically, one commenter is concerned that subpart Y's definition of “coal refuse” could create the potential for the unintended application of such definition to the overburden from surface mines or to mine-development waste associated with underground mining. The commenter stated that the final rule must make clear that the definition of “coal refuse” does not apply to these types of operations and suggested using the SMCRA definition instead (Coal refuse is defined as “any waste coal, rock, shale, slurry, culm, gob, boney, slate, clay and related materials, associated with or near a coal seam, which are either brought aboveground or otherwise removed from a coal mine in the process of mining coal or which are separated from coal during the cleaning or preparation operations. The term includes underground development wastes, coal processing wastes, excess spoil, but does not mean overburden from surface mining activities”). In contrast, several other commenters stated either that they support, or that they have no objections to, including “coal refuse” in the definition of “coal” for subpart Y. Response: EPA is including “coal refuse” in the final rule's definition of “coal” for the purposes of subpart Y because it is handled in the same machinery as other types of coal at coal preparation and processing plants. “Coal refuse” is separately defined, as well as included in the definition of “coal” in other NSPS ( e.g., 40 CFR part 60 subparts Da and Db), and its inclusion here provides consistency with other EPA regulations. EPA has modified the definition of “coal refuse” in subpart Y to be consistent with the definition in 40 CFR subpart Da. Given the historical inclusion of “coal refuse” in these other NSPS and the fact that the constituents and emission characteristics of “coal” and “coal refuse” are believed to be the same, EPA has concluded that inclusion of “coal refuse” in subpart Y is appropriate. Comment: Many commenters objected to EPA extending the applicability of subpart Y to facilities producing petroleum coke by adding “petroleum coke” to the subpart Y definition of “coal”. They noted that the emission standards in the May 27, 2009, supplemental proposal appear to have been developed primarily for coal processing plants, and do not seem to reflect the differences between coal and petroleum coke, or contemplate the emissions associated with petroleum coke handling operations. Without more information on these emissions, the commenters contend that it is inappropriate for EPA to broaden the definition of “coal” to include “petroleum coke” in this final rulemaking at this time. However, if “petroleum coke” is included, several commenters recommended petroleum coke operations that should be specifically exempted from being subject to subpart Y. Reasons cited by commenters include: (1) “Petroleum coke” is a petroleum product that should not be subject to a rule ( i.e., NSPS subpart Y) intended to pertain to standards of performance for coal preparation and processing plants; (2) petroleum refining operations that include petroleum coke production are subject to numerous NSPS rules to ensure protection of public health and the environment, to two separate maximum achievable control technology (MACT) rules specific to air emissions from process units, including petroleum coke production, and to the NSR permitting process to ensure compliance with National Ambient Air Quality Standards (NAAQS) for PM; (3) EPA did not provide adequate notice that petroleum coke manufacturing equipment ( e.g., refinery coker units) was being considered for new standards; (4) EPA neither gathered or requested data to determine if petroleum coke manufacturing equipment should be included in the affected sources subject to subpart Y; and (5) standards for coal processing and conveying equipment, coal storage systems, and transfer and loading system operations are not suitable for petroleum coke. Two commenters suggested that EPA change the approach to include end-user petroleum coke processing in the existing NSPS for Coal Preparation and Processing Plants by retaining the existing definition of “coal” and adding “petroleum coke” as a separate material with associated provisions. If EPA expands the source category by including facilities that handle only “petroleum coke” (and not “coal”), the commenters believe it should do so only for end-users of “petroleum coke” used as fuel. Numerous commenters presented arguments that petroleum coke calciners are not same as coal thermal dryers and, therefore, believe it is inappropriate to apply the subpart Y thermal dryer standards to coke calciners. The commenters explained that the purpose and function of a petroleum coke calciner is to fundamentally change the material by rearranging carbon molecules and, thus, it acts as a reactor, not a “dryer”. In addition, commenters noted that calciners in the petroleum industry operate at much higher temperatures than typical coal dryers, intuitively would have different emission profiles, and use different methods than coal thermal dryers to control PM emissions. Response: Based on a review of the comments received and because of the limited amount of currently available data, EPA has decided not to include “petroleum coke” in the subpart Y definition of “coal” at this time. EPA plans on obtaining additional data on petroleum coking activities at petroleum refineries through current actions on the refinery NSPS review (40 CFR part 60 subpart J). In addition, additional data will also be obtained on petroleum coke activities at end-user locations ( e.g., coal-fired power plants). Comment: Several commenters supported EPA's proposal to distinguish between indirect and direct contact thermal dryers. The commenters anticipate that more electric utilities will use indirect contact thermal dryers in the future. Commenters agreed with EPA's decision to exclude indirect thermal dryers from the coal dryer SO 2 and NO X /CO standards “[i]f the source of heat (the source of combustion or furnace) is subject to a boiler NSPS (subpart Da, Db, or Dc). However, one commenter stated that in the case of one facility, the waste heat being used for the facility's coal dryer does not come from the exhaust gases of a boiler, but rather from the condensing water from steam turbines. In that case, there is no affected source to which the combustion pollutant emission limits can apply. Thus, the commenter agreed that the thermal dryer would only be subject to the PM limit, but not because it is subject to another NSPS. The commenter further stated their belief that subpart Y coal dryer emission limits should not apply to the source of heat for an indirect thermal dryer. Response: It is EPA's intent to regulate, at this time, emissions from thermal dryers only in circumstances where coal, coal refuse, or residual oil are used to provide thermal input. Thermal dryers that use residual or waste heat from the combustion of these fuels are only subject to the PM and opacity standards. As pointed out by the commenters, indirect thermal dryers for which the source of heat is subject to a boiler NSPS are not subject to the emission limits for SO 2 and NO X /CO because those pollutants would not be present in the thermal dryer exhaust. In addition, EPA has concluded that affected thermal dryers for which all of the thermal input is supplied by gaseous fuels ( e.g., blast furnace gas, coke oven gas, natural gas) or distillate oil also should not be subject to the emission limits for SO 2 and NO X /CO. Those pollutants are relatively small from these types of thermal dryers and the testing requirements will not result in any emissions reductions. As is the case with the facility described by the commenter, if there is no combustion process providing the heat for the dryer, then there is no practicality in having emission limits for SO 2 and NO X /CO. Comment: Several commenters stated that emissions from thermal dryers integrated with in-line coal mills at cement manufacturing plants should not be subject to subpart Y and instead be subject to the standard for the affected facility as part of the cement manufacturing process. According to the commenters, the unique coal processing and handling systems found at Portland cement plants are best addressed by the Portland Cement NSPS (40 CFR part 60, subpart F) and NESHAP (40 CFR part 63, subpart LLL). The commenters requested that the subpart Y definition of “thermal dryer” be revised to read “Thermal dryer does not include drying of coal that occurs intentionally or incidentally in the manufacture of Portland cement through direct or indirect contact with hot gases generated by cement manufacturing process units, such as cement kilns, preheaters, precalciners, or clinker coolers.” Commenters explained that this approach would (a) clearly distinguish between separately fired, stand-alone thermal dryers that are located at a cement plant, versus thermal dryers or coal mills that are integrated into a cement manufacturing line, and (b) avoid any potential confusion about incidental drying of coal that occurs in the cement-making process. Reasons presented by commenters to support the requested exemption are summarized below. • In a 1995 determination, EPA stated that when “gases originate in one affected facility and pass through another affected facility as part of the manufacturing process, EPA applies the standard for the affected facility from which the gases are discharged directly into the atmosphere.” [Applicability Determination 9600082 “Alternative Monitoring and Opacity Limit Clarification for San Juan Cement Company,” John B. Rasnic (May 12, 1995)]. However, a year later EPA qualified this guidance when it concluded that an in-line raw mill was subject to the 40 CFR part 60, subpart F, kiln standards, stating ”This determination clarifies that for dry process Portland cement plants with an “in-line” kiln/raw mill configuration, the raw mill does not exist as a separate affected facility and; hence, the appropriate emission limit is that which applies to the kiln.” [Applicability Determination 9600083; “Opacity Limitation for `In-line' Portland Cement Plants,” John B. Rasnic (September 7, 1996)]. • Just as emissions from the in-line raw mill in Applicability Determination 9600083 were subject to 40 CFR Part 60, subpart F, NSPS, PM mass and opacity limitations for cement kilns, so should emissions from an in-line coal mill at a cement plant where kiln gases are used to heat and dry the coal be treated as an extension of the kiln and subject to subpart F NSPS and 40 CFR Part 63, subpart LLL, NESHAP cement kiln PM and opacity limits. This approach is consistent with multiple different applicability determinations stating that kiln exhaust gases are subject to the Portland cement NESHAP (40 CFR part 63, subpart LLL) regardless of whether they are routed through the coal mill prior to discharge to the atmosphere. It is also consistent with the data that EPA has reviewed in establishing the proposed subpart Y limits. In the absence of data related to emissions from in-line coal mills, EPA would not have a rational basis supported by evidence in the record for establishing limits that apply to these unique gas streams. • As Portland cement plants have striven to increase energy efficiency, a common plant configuration has been to employ kiln exhaust gas or heated gas from the plant's clinker cooler to thermally dry coal before it is combusted. Cement kiln exhaust gas is extremely hot, and one of the primary means of improving energy efficiency has been to route this gas back through the process to extract as much heat as reasonably possible. Likewise, the product leaving the kiln (referred to as clinker) will enter a cooling area where gases are blown through the clinker to accelerate the cooling process. In some plants this heated gas is then used to heat the coal entering the combustion process. Both kilns and clinker coolers are affected facilities under 40 CFR part 60, subpart F, NSPS. The use of waste heat from the kiln or the clinker cooler is highly energy efficient, driving down the combustion emissions, including GHG emissions, from the plant as a whole. • Some cement plants have stand-alone thermal dryers for coal, where the heat for drying is provided by a dedicated combustion source ( e.g., coal or natural gas). Those thermal dryers generally should have similar emissions, and similar possibilities for emissions control, as comparable-size thermal coal dryers at other facilities. But where coal drying is integrated into the cement-making process, through direct or indirect exposure of the coal to heat in exhaust gases from units such as cement kilns, preheater/precalciners, or clinker coolers, the emissions from that coal drying, and the potential for controlling those emissions, is very different from a stand-alone thermal dryer. • To the extent that subpart Y may apply to coal drying that occurs using waste heat from the manufacture of Portland cement, EPA's assessments of control technology and derivation of emission standards under subpart Y have not taken into account cement-process-related loadings of SO 2 , NO X , and CO. EPA has not shown, for example, that it would be feasible for a cement plant to demonstrate compliance with SO 2 mass limits or percent reduction requirements where exhaust gases from coal drying are combined with cement kiln gases, which include SO 2 from fuel consumption and from raw materials. Similarly, NO X limits that may be achievable through combustion controls on a standalone thermal dryer may not be achievable in exhaust gases mixed with cement kiln gases containing both fuel NO X and thermal NO X from the cement-making process. • The supplemental proposal would not impose SO 2 , NO X , and CO limits on indirect thermal dryers where the source of the heat is subject to NSPS under 40 CFR Part 60, subpart Da, Db, or Dc. Although EPA has not really explained the basis for that exclusion, it is inferred that EPA believes the BDT determinations associated with the NSPS for the source of heat are more appropriate and should be applied. The same rationale should be applied to thermal drying that is incidental to cement manufacturing, and EPA should exclude exhaust gases that are subject to the 40 CFR part 60, subpart F, NSPS from being subject to the subpart Y SO 2 , NO X , and CO limits. Response: EPA agrees that in the case of a coal dryer at a cement manufacturing facility where all of the thermal input is supplied by cement kiln exhaust or clinker cooler exhaust, the dryer should be regulated under the appropriate Portland Cement kiln regulations (40 CFR part 60, subpart F, and 40 CFR part 63, subpart LLL). This would also imply that any emissions from the thermal dryer are considered as part of the kiln or clinker cooler emissions. The final rule's emissions limits apply to new, reconstructed, or modified thermal dryers at Portland cement manufacturing plants in situations where the thermal input is not supplied by cement kiln or clinker cooler exhaust. Other subpart Y affected facilities located at Portland cement manufacturing plants ( e.g., storage systems, conveyors) also are subject to subpart Y. Comment: One commenter requested that thermal dryers fired with process gases at integrated iron and steel plants be exempted from the subpart Y emission limits for SO 2 and NO X /CO. Reasons presented by commenter to support the requested exemption are summarized below. • The pulverized coal injection systems at some integrated iron and steel plants also burn process gases ( i.e., blast furnace gas or coke oven gas) as the primary fuel in thermal dryers. These process gases are valuable substitutes for other sources of purchased energy and are produced on-site. However, they have lower heating values than natural gas and must be consumed on-site to be utilized most effectively, or be flared. As is the case for waste heat, the use of these gases improves overall plant energy efficiency and reduces GHG emissions and should not be discouraged by applying unachievable emission limits when used for thermal drying of coal. • The use of these process gases for coal drying will not generate any more emissions than if the gases are combusted elsewhere or flared. Instead, if the process gases burned for coal drying were replaced entirely by burning natural gas, emissions (mainly NO X and CO) from the integrated iron and steel plant would actually increase. Establishing emission limits for thermal dryers using these process gas fuels will only serve to discourage their use. • The proposed subpart Y standards are based on the assumption that thermal dryers located at traditional mine sites and coal preparation plants are typically fired with coal, but in the examples noted above, other fuels are normally used. At the very least, the final rule should include a provision to allow operators of thermal dryers fired by natural gas, waste heat, or process gases to apply for a variance upon demonstration that emissions of SO 2 , NO X , CO and/or PM are well below the prescribed standards. Upon such a demonstration, monitoring requirements for these pollutants should be reduced or eliminated. Response: As previously noted, EPA has maintained that coal preparation and processing plants may be found at industrial sites such as those described by the commenter. In the Response to Comments document for the October 24, 1974, proposal, EPA stated “[t]he specific coal processing operations regulated by these standards are affected regardless of whether they are located in coal liquefaction plants, power plants, coke ovens, etc. ” ( see “Background Information for Standards of Performance: Coal Preparation Plants; Volume 3: Supplemental Information. January 1976. p. 22). Thus, EPA has not changed its interpretation. In addition, EPA has made no assumptions as to the source of the heat used in the thermal dryer as the commenter suggests. However, as noted above for Portland cement plants, EPA agrees that in the case of an affected source at an integrated iron and steel manufacturing facility, where the emissions from the thermal dryer would be considered as part of the blast furnace or coke oven emissions, the facility should be regulated under the appropriate steel mill or coke oven NSPS. As previously explained, EPA's intent at this time is to regulate emissions from a thermal dryer only in circumstances where coal, coal refuse, or residual oil are used as thermal input. Thermal dryers that use residual or waste heat from the combustion of these fuels would only be subject to the PM and opacity standards. Indirect thermal dryers for which the source of heat is subject to SO 2, NO X , and/or CO limits under another 40 CFR part 60 subpart would not be subject to the emission limits for SO 2 and NO X /CO. In addition, affected thermal dryers for which all of the thermal input is supplied by gaseous fuels ( e.g., blast furnace gas, coke oven gas, natural gas) or distillate oil also would not be subject to the emission limits for SO 2 and NO X /CO. C. Subcategorization Comment: Numerous commenters stated that when establishing standards of performance for new stationary sources under the CAA, section 111(b)(2) authorizes the Administrator to “distinguish among classes, types and sizes within categories of new sources.” The commenters requested that the final amendments to subpart Y include a distinction between the regulatory requirements for coal preparation plants associated with coal mines ( i.e., the “producers”) and for coal preparation plants at coal-fired power plants and large industrial sources such as cement manufacturing and coke ovens ( i.e., the “users”). The commenters cited the following regulatory requirement and facility characteristics distinctions between coal producers and coal users to support their request. • Most new coal-fired power plants as well as large industrial coal-fired sources ( i.e., the “users”) in the future will be major sources of PM emissions and, therefore, be required to use state-of-the-art control technologies ( i.e., best available control technology (BACT)). In contrast, surface coal mines with coal preparation facilities as well as stand-alone coal preparation facilities associated with coal mines ( i.e., the “producers”) are typically minor sources and will not be subject to BACT under the Prevention of Significant Deterioration (PSD) program but rather to control technology requirements of Minor New Source Review (NSR) programs of individual States. Thus, adoption of industry sectors-based subcategorized emission standards for subpart Y should be considered so that a BACT level of control is not mandated as NSPS for “producers.” • Resource requirements to maintain and demonstrate compliance with the subpart Y emission standards is a function of the number of affected facilities at a particular coal preparation plant. Coal preparation plants of “producers” tend to have more sizing, cleaning and overall “handling” operations than the typical preparation plant at a coal-fired “user.” Consequently, as a general rule, the total number of affected facilities at a “producer's” coal preparation plant will be greater than the number of such facilities at the preparation plant of a “user.” Moreover, a single affected facility associated with coal mining can frequently have multiple points of fugitive emissions. With more affected facilities per source and more emission points per affected facility, preparation plants associated with coal mining generally will have much greater monitoring/recordkeeping/reporting requirements than will its preparation counterparts at coal-fired “user” sources. • Fugitive dust from surface coal mines is already regulated by U.S. Department of the Interior regulations in 30 CFR Parts 700-899 under authority of SMCRA, and the existing air pollution control requirements imposed on coal mines by SMCRA must be accounted for. Commenters believe that an EPA examination of SMCRA's dust control requirements in the context of possible NSPS regulation of preparation facilities at coal mines would result in a conclusion that concurrent regulation with similar CAA requirements is not appropriate. Response: The subpart Y NSPS covers coal preparation and processing plants that may be found, as the commenter notes, both at mine sites (“producers”) and at industrial sites (“users”). In the Response to Comments document for the October 24, 1974, proposal, EPA stated “[t]he specific coal processing operations regulated by these standards are affected regardless of whether they are located in coal liquefaction plants, power plants, coke ovens, etc.” ( See “Background Information for Standards of Performance: Coal Preparation Plants; Volume 3: Supplemental Information.” January 1976. p. 22.) Commenters' request that EPA create a separate category for coal preparation and processing facilities at “producers” appears to be based on the assertion that these facilities should not be required to install and operate emissions control technologies that are currently in use or will be used at coal preparation and processing facilities at “users.” A primary objective of CAA section 111, however, is to require new sources to be built using the best system of emissions reduction that has been adequately demonstrated. Under CAA section 111, EPA is required to set standards of performance ( i.e., standards that reflect the degree of emission limitation achievable through the application of the best system of emission reduction). As the Court has noted, “Section 111 looks toward what may fairly be projected for the regulated future, rather than the state of the art at present, since it is addressed to standards for new plants.” Portland Cement, 486 F.2d at 391. In developing NSPS standards, EPA must identify all technologies in use or being developed for use to determine that the Administrator determinations have been adequately demonstrated. This analysis must take into account the cost of achieving the reductions and any nonair quality health and environmental impacts and energy requirements. This analysis is separate and distinct from any BACT analysis that may be done for an individual plant. Finally, EPA disagrees with the comment to the extent it suggests that EPA should not consider technologies determined to be BACT for an individual plant in its BDT analyses. Control technologies change and can improve over time and EPA does not believe that it would be appropriate for EPA to ignore these developments when evaluating what currently constitutes BDT for this source category. The commenters point out that preparation plants associated with coal mining generally have more affected facilities per source and more emission points per affected facility. Commenters have not suggested, however, and EPA has no reason to believe, that the types of emissions from coal preparation and processing sources associated with coal mines differ from the types of emissions from those same source types at “user” facilities. They further have not demonstrated, and EPA has no reason to believe, that emission control technologies that are adequately demonstrated for facilities at “user” facilities would not be adequately demonstrated for use at facilities located at mines. Thus, EPA continues to believe it is appropriate to regulate these sources in the same manner and sees no need to establish subcategories at this point. Further, the comment could be read to suggest that a separate subcategory should be created for facilities at mines because these facilities are subject to differences in the degree of control required by other regulations or because these facilities are currently achieving different levels of control or using different emission control technologies. EPA does not believe it would be appropriate to create a separate subcategory on these bases. Further, these factors do not affect what technologies could be found to be “adequately demonstrated” or the emission reductions available from those technologies. In addition, the regulation of fugitive dust from surface coal mines under SMCRA by the Department of Interior does not, as commenters suggest, result in a “conclusion that concurrent regulation with similar CAA requirements would not be appropriate.” The October 1974 Background Information Document stated that “Coal preparation” is a segment of the coal industry that encompasses operations between the mining of raw coal and the distribution of product coal. ( See “Background Information for Standards of Performance: Coal Preparation Plants; Volume 1: Proposed Standards. October 1974. p. 1.) The support document for the April 1981 NSPS review states that “[t]he first step in the coal preparation process is the delivery of ROM [run of mine] coal to the plant site.” ( See “A Review of Standards of Performance for new Stationary Sources—Coal Preparation Plants. December 1980. p. 2-3.) EPA's Office of Water has included the following definitions in their regulations for the coal mining industry (at 40 CFR 434.11). (b) The term “active mining area” means the area, on and beneath land, used or disturbed in activity related to the extraction, removal, or recovery of coal from its natural deposits. This term excludes coal preparation plants, coal preparation plant associated areas and post-mining areas. (e) The term “coal preparation plant” means a facility where coal is subjected to cleaning, concentrating, or other processing or preparation in order to separate coal from its impurities and then is loaded for transit to a consuming facility. Thus, EPA, in both the air and water offices, has maintained a distinction between the “active mining area” and the “coal preparation plant.” The process of “coal preparation” generally involves, among other things, separation of coal from impurities ( i.e., “breaking” or “crushing”). As discussed in the response to comment 3.4.1.1.1 in the Response to Comments Document, EPA interprets the “beginning” of the “coal preparation plant” to be the first hopper ( i.e., “drop point”) for receipt of coal from any form of transportation. D. Coal Drying Standards Comment: Two commenters supported EPA's decisions not to set separate limits for fine PM (FPM) ( i.e., PM 2.5 or PM 10 ) or condensable PM (CPM). In contrast, another commenter rejected EPA's rationale presented in the May 27, 2009, supplemental proposal that EPA cannot set limits applicable to PM 10 , PM 2.5 , and CPM emissions because EPA has insufficient data and lacks a consistent measurement methodology to collect the needed data. The commenter stated that EPA's failure to gather such data does not excuse EPA from a statutory obligation, that FPM and CPM emissions standards can be set pending resolution of any measurement issues by a future date certain, and, should EPA conclude that an inability to accurately measure emissions of FPM and CPM from dryers renders the implementation of FPM or CPM standards of performance infeasible, EPA must impose a design, equipment, work practice, or operational standard, or combination thereof. Response: EPA stands by the rationale presented in the May 27, 2009, subpart Y supplemental proposal notice. That is, the available PM emissions data for thermal dryers collected by EPA were measured using EPA Method 5 ( see 40 CFR 60, appendix A-3). For this method, solid FPM is collected isokinetically on a filter media (typically glass or quartz fiber) and is then measured gravimetrically to determine FPM emissions. Method 5, when performed correctly, provides an accurate measurement of total FPM (for PM > 0.3 μ), but does not measure FPM emissions by particle size distribution ( i.e., PM 10 or PM 2.5 ), nor does the method measure CPM. EPA is revising existing test methods, EPA Method 201A—Determination of PM 10 Emissions (Constant Sampling Rate Procedure) and EPA Method 202—Determination of Condensible Particulate Emissions from Stationary Sources, to provide test methods that will accurately measure PM 10 , PM 2.5 , and CPM from stationary sources such as coal thermal dryers. Amendments to these test methods were proposed on March 26, 2009 ( see 74 FR 12970). The amendments to Method 201A add a particle-sizing device to allow for sampling of PM 2.5, PM 10 , or both PM 10 and PM 2.5 . The amendments to Method 202 revise the sample collection and recovery procedures of the method to provide for more accurate and precise measurement of CPM. Methods 201A and 202 are not yet finalized and sufficient test data using these methods has not yet been collected for coal-fired thermal dryers. For these reasons, EPA is not currently able to determine whether or not it would be appropriate to add separate PM emission limits to subpart Y for PM 2.5 , PM 10 , or CPM emissions from coal-fired thermal dryers and would not currently be able to establish national standards to address PM 2.5 , PM 10 , or CPM emissions. Comment: One commenter disagreed with EPA's rationale for not setting coal dryer VOC standards. Specifically, the commenter disagrees with (1) EPA's decision to not set standards for VOC and CO that reflect use of a gas recirculation thermal dryers, although EPA asserts that VOC and CO emissions would be minimized because new thermal dryers are likely to use a gas recirculation design; (2) EPA's assertion that not setting a standard for VOC is reasonable because by setting an emissions limit that contains a CO emissions rate, the VOC emissions that result from incomplete combustion also are minimized; and (3) EPA's assertions that VOC standards cannot be established because a method of control beyond combustion controls has not been identified and the variability of VOC emissions from the coal bed preclude determination of a standard that would be achievable nationwide. Response: EPA has discretion to determine which pollutants are appropriate for regulation in a particular NSPS. In this case, for the reasons noted, EPA concluded that it was not appropriate or feasible to establish a standard of performance for VOC emissions from coal preparation and processing plants at this time. This conclusion does not prohibit EPA from establishing such a standard in a future rulemaking. EPA disagrees with the commenter's suggestion that a standard could be based on oxidation of VOC in a recirculation thermal dryer. As noted elsewhere, EPA has concluded that there is no one thermal dryer design that will work in all situations found within the industries utilizing coal preparation and processing plants. Control of VOC emissions through activated carbon absorption or regenerative thermal oxidizers are not utilized on thermal dryers at coal preparation and processing plants; further, EPA did not have other information showing that these technologies are adequately demonstrated for use on coal preparation and processing plant sources. VOC emissions vary, in part, due to the variability in volatile contents of the coals being processed; absent demonstrated control technology, this variability can not be addressed through add-on technology as it is with variable sulfur contents of coal. Thus, EPA believes its decision not to establish VOC emission limits under subpart Y at this time is appropriate. Comment: One commenter stated that the proposed standards for coal drying failed to meet the basic legislative requirements of CAA section 111. The commenter presented the following reasons to support the position that for EPA to comply with CAA section 111, EPA must set standards based on the best demonstrated technologies for drying coal not for the thermal drying of coal through the application of heat generated by coal combustion specifically for that purpose. • CAA section 111 defines “standard of performance” to mean “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated” [42 U.S.C. 7411(a)(1))]. • Another provision in CAA section 111 provides that standards of performance must represent the best “technological system of continuous emission reduction,” see, e.g., 42 U.S.C. 7411(g)(4), which is defined to include “a technological process for production or operation by any source which is inherently low-polluting or nonpolluting” [42 U.S.C. 7411(a)(7)(A)]. This provision further demonstrates that EPA must evaluate mechanical, indirect, and recirculation dryers, as each is inherently low polluting, in comparison to once-through coal-fired thermal dryers. • CAA section 111 requires “specific and rigorous limits on the amounts of pollutants that may be emitted.” ASARCO, Inc. v. EPA, 578 F.2d 319, 322 (DC Cir. 1978). The legislative history of this requirement confirms Congress's determination that “[t]he maximum use of available means of preventing and controlling air pollution is essential to the elimination of new pollution problems * * *” S. Rep. No. 1196, 91st Cong., 2d Sess. at 16. In revising the standards of performance for coal preparation plants, EPA may not simply codify existing levels of performance. • Because NSPS apply only to new, modified, or reconstructed sources and must reflect application of the best demonstrated system of reduction, they do not have to be achievable for all types of existing sources. See Portland Cement, 486 F.2d at 391. Nor can EPA forego setting limits reflecting the best demonstrated system merely because some sources may prefer a different system, ASARCO, 578 F.2d at 322 (“NSPS are designed to force new sources to employ the best demonstrated systems of emission reduction.”). The legislative history of CAA section 111 demonstrates that Congress intended for EPA to prescribe standards that override the design preferences of regulated sources: “[T]he emission standards shall provide that sources of such emissions shall be designed and equipped to prevent and control such emissions to the fullest extent compatible with the available technology and economic feasibility. * * * ” H.R. Rep. No. 1146, 91st Cong., 2d Sess. at 10 (emphasis added). Thus, EPA's assumption that NSPS must be set at levels lenient enough to accommodate all types of existing dryers is contrary to Congress' plainly expressed intent. • CAA section 111 “looks toward what may fairly be projected for the regulated future, rather than the state of the art at present. * * *” Portland Cement Assn v. Ruckelshaus, 486 F.2d 375, 391 (DC Cir. 1973). An “achievable standard is one * * * within the realm of the adequately demonstrated system's efficiency and which, although not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption.” Essex Chemical Corporation v. Ruckelshaus, 486 F.2d 427, 433-34 (DC Cir. 1973). Instead of looking toward a future of mechanical dryers and indirect thermal dryers, or even gas-fired recirculation thermal dryers, the proposed standards attempt to lock-in standards that reflect the performance of coal-fired once-through thermal dryers. • Even assuming for the sake of argument that it is permissible to set a standard for emissions from coal drying that presumes the use of thermal dryers, the proposed rule violates the straightforward intent of Congress. Congress purposefully chose the superlative “best” to describe the system of emissions reductions on which the NSPS were to be based [42 U.S.C. 7411(a)(1)]. Moreover, one of the enumerated purposes of the NSPS was to create incentives for new technology. CAA Conference Report: Statement of Intent; Clarification of Select Provisions, 123 Cong. Rec. 27071 (1977). However, instead of proposing standards based on the performance of the cleanest new coal drying technologies, the proposal sets lax standards and then allows a mix of coal drying technologies to meet those standards. Response: EPA followed the statutory requirements of CAA section 111 in its review of the existing standard of performance for thermal dryers at coal preparation and processing plants. The review was conducted pursuant to the requirement in section 111(b)(1)(B) that EPA review and revise, if appropriate, the previously promulgated standards of performance. Section 111(b)(1)(B) requires EPA, when revising the standards, to follow the procedure required for the promulgation of standards. Section 111b(1)(B) further requires publication of proposed regulations, an opportunity for written comment, and requires the Administrator to promulgate such standards as she “deems appropriate.” The commenter correctly noted that a standard of performance is defined as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” 42 U.S.C. 7411(a)(1). The commenter, however, takes the language from 42 U.S.C. 7411(g)(4) out of context. CAA section 111(g)(4) provides that the Administrator shall revise a standard of performance upon application of the Governor of a State that meets certain criteria. The language quoted by the commenter appears in this section and describes what must be included in the application of the Governor, and does not modify the definition of a standard of performance in section 111(a)(1). To determine the appropriate level for a particular standard of performance, EPA conducts an analysis to determine what emission rates reflect application of “best demonstrated technology” or BDT. This BDT analysis includes consideration of available emission controls and technologies. In the BDT analysis for controlling PM emissions from coal dryers for this final rule, EPA explicitly considered alternate processes for drying coal as well as add-on emission control technologies. For modified facilities, EPA recognized the limitations that may be associated with the physical layout of existing dryers. For reconstructed facilities and new facilities, however, we concluded that design options, and alternative replacement technologies, could be taken into account during the reconstruction or construction process. EPA concluded that recirculation thermal dryers and indirect thermal dryers are both adequately demonstrated and readily available technologies for drying coal. It did not restrict its analysis, or the definition of affected facility, to the once-through direct contact thermal dryers covered by the existing NSPS standards for thermal dryers. Contrary to the commenter's assertions, EPA neither presumed the use of existing once-through direct contact thermal dryers nor merely codified existing levels of performance achieved by such dryers. Instead, EPA concluded that BDT for controlling PM emissions for new and reconstructed thermal dryers is fabric filters applied to recirculation thermal dryers and indirect thermal dryers. The PM standards in the final rule are based on these conclusions. Although mechanical coal drying technologies, because they do not burn fuel, may inherently produce lower air pollutant emissions compared to some thermal drying technologies, they may not be technically applicable, cost-effective, or the most energy efficient for all possible coal drying applications that could be subject to subpart Y. EPA does not, at this time, have data to support a conclusion that standards based on an assumption that mechanical dryers are BDT would be achievable by the industry as a whole ( see National Lime Ass'n v. EPA, 627 F.2d 416, 431 (1980)). Even though the “adequately demonstrated” requirement does not “necessarily impl[y] that any [covered facility] now in existence be able to meet the proposed standards,” Portland Cement, 486 F.2d at 391, EPA must demonstrate that the standard is, in fact, achievable taking into consideration variables that may affect emissions in different circumstances and at different plants. National Lime, 627 F.2d at 433. In fact, the type of coal drying technology used at a given facility is influenced by a variety of factors, including type of facility, coal moisture reduction requirements, availability of waste heat sources at the coal processing location, and drying process energy requirements including electrical power consumption. Mechanical drying techniques are not suitable replacements for thermal dryers under all circumstances. Mechanical drying techniques can remove free moisture adsorbed onto the surface of the coal particles, as well as a portion of the hydroscopic moisture contained by capillary action within microfractures in the coal particles, but are ineffective at removing inherent moisture (and, thus, would only be applicable at preparation plants utilizing coal washing). Some type of thermal energy is required to remove the interstitial and molecular (inherent) moisture from the coal for applications where extremely low moisture content is desirable. Therefore, mechanical drying techniques are not suitable replacements for thermal dryers under all circumstances, and because waste heat is not available at all locations, thermal dryers using waste heat are not a technically possible substitute for thermal dryers in all situations. EPA will continue to follow the development of mechanical drying techniques. To the extent the commenter is suggesting that EPA should require use of a certain technology for drying coal and coal preparation plants, EPA notes that CAA section 111(h), 42 U.S.C. 7411(h)(1) only allows the Administrator to promulgate design, equipment, work practice, or operational standards if “in the judgment of the Administrator, it is not feasible to prescribe or enforce a standard of performance.” No such finding has been made here. In the BDT analysis for controlling SO 2 emissions from coal dryers for the final rule, EPA determined that BDT for modified and reconstructed thermal dryers is a wet scrubber with a scrubbing reagent ( e.g., an upgraded venturi scrubber with sodium hydroxide or packed bed scrubber with lime). The information that EPA has indicates that all of the once-through direct contact thermal dryers currently use venturi scrubbers for PM control. Thus, the upgraded venturi scrubber with sodium hydroxide or the packed bed scrubber with lime (would be in addition to the venturi scrubber) would provide SO 2 control, along with additional PM control necessary for reconstructed thermal dryers to meet their PM and opacity limits. For new thermal dryers, we determined that BDT for controlling SO 2 emissions is the injection of sodium hydroxide directly to the venturi scrubber fluid or injection of a sodium-based sorbent into the combustion gases prior to the drying chamber. For a new once-through direct contact thermal dryer, the caustic injection into the scrubber fluid for SO 2 control would be in addition to a high-energy venturi scrubber which is the likely control technology that would be used for PM and opacity control. For a new coal recirculation thermal dryer, sorbent injection into the combustion gases for SO 2 control would be used in conjunction with a fabric filter which is the likely control technology that would be used for PM and opacity control. EPA determined that BDT for controlling NO X emissions from new, reconstructed, and modified thermal dryers is combustion controls. Combustion controls can be used across the range of thermal dryers currently in use. Combustion controls include low NO X burners, staged combustion, co-firing with natural gas or liquefied petroleum gas, and flue gas recirculation. BDT for controlling CO emissions was determined to be good combustion practices. Good combustion practices limit the formation of CO (and VOC) by providing sufficient oxygen in the combustion zone such that complete combustion can occur. Maintaining appropriate combustion zone temperature and gas residence time also are good combustion practices, as is proper operation and maintenance of the dryer. Comment: Several commenters stated that the proposed PM emission limit of 0.010gr/dscf for new coal dryers does not reflect an adequate margin of compliance to the fabric filter test data used and that the proposed limit needs to be less stringent because the test data do not represent a demonstration of the performance of control technology over the life of the facility and over the range of operating conditions that may be encountered at thermal dryers. Therefore, the commenters recommended that the PM emission limit remain at the current NSPS emission rate of 0.031 gr/dscf. Other commenters presented an opposing argument that the proposed PM limit needs to be lower. The commenters asserted that the compliance margin of two to three times applied by EPA to fabric filter test data is unjustified in that EPA has not explained why use of a fabric filter to control PM emissions would require such a large margin of safety, given the demonstrated performance of fabric filters for the subject source as well as similar sources in numerous other industries. Response: EPA has reviewed the available PM emissions and permit data for thermal dryers; no additional PM data were provided during the public comment period. We believe that the proposed PM limit of 0.023 g/dscm (0.010 gr/dscf) for new thermal dryers is appropriate. We further believe that, in the presence of limited data showing actual emissions, permit information can be useful in determining whether a particular emission limit is achievable by sources in the source category. EPA has available three emission test data points for fabric filters installed on thermal dryers, including two tests one year apart at one facility. We believe that these three data points provide adequate information on the performance of the technology. However, EPA also has examined the permit data which identifies emission limits agreed upon between State regulators and the regulated community and believe that the emission limits contained in permits constitute limits that could be achieved over the range of operating conditions to be found within the industry. Nat'l. Lime Ass'n. v. EPA, 627 F.2d 416, 431 (DC Cir. 1980) requires EPA to show that the limit selected is achievable under different conditions at an individual plant and conditions at different plants. EPA believes that basing the emission limit on use of the data points from two facilities, including two data sets from one facility, in conjunction with the permit data, adequately accounts for the variability to be found within the industry. Therefore, the final rule reflects no changes to the proposed PM emission limit for new thermal dryers. Comment: Two commenters supported the proposal to revise the PM limit for units reconstructed after April 28, 2008, to 0.045 g/dscm (0.020 gr/dscf) and to maintain the existing 1976 rule's opacity limit of less than 20 percent. In contrast, a third commenter disagreed with the proposed PM standard for reconstructed dryers, which is twice as high as the proposed standard for new dryers (0.010 gr/dscf). The commenter stated that EPA must either require reconstructed dryers to meet the same PM standards as new dryers, or explain why such limits do not reflect BDT for reconstructed dryers. The commenter further stated that EPA has not explained why it would not also be feasible to further modify existing dryers, at the time of reconstruction, by converting them to recirculation dryers or by otherwise modifying them to use fabric filters, and that EPA must examine whether a fabric filter is a feasible option for control of PM emissions from reconstructed dryers. Another commenter recommended that the PM emission limitations not be changed from the current NSPS emission rate of 0.031 gr/dscf. The commenter believes that the limited data EPA has cited to justify reducing the limit by a third for reconstructed dryers using the same control technology is insufficient to conclude that thermal dryers with the specified control equipment would, throughout the life of the facility, be able to continuously meet a lower emission limit than the current NSPS provide. Response: EPA agrees that units undergoing reconstruction as defined in the CAA could undergo the conversions necessary to install BDT for PM emissions control for new thermal dryers and, thus, meet the PM and opacity limits of new facilities. Thus, the regulation has been changed accordingly. Comment: One commenter stated that information in the supplemental proposal preamble and support documentation show that the SO 2 emissions limits for new and reconstructed coal dryers should be set lower than the proposed level. The commenter explained that the proposal preamble states that “[w]et scrubbers designed specifically for SO 2 control are able to achieve greater than 95 percent reduction.” EPA, however, dismisses wet scrubbers from further consideration, as the wet scrubbers currently used on existing thermal dryers are designed for PM control and not specifically for SO 2 controls, and high levels of SO 2 control may be difficult to achieve without redesign of the wet scrubber. The commenter asserted that this is not a valid reason for eliminating a viable technology from consideration, and that wet scrubbers are widely used on similar sources and, as EPA recognizes, routinely achieve greater than 95 percent reduction. Even if EPA ultimately determines that wet scrubbers are not BDT for SO 2 control for some coal dryers, the commenter stated that the subpart Y SO 2 emission limit must be more stringent for those dryers. The commenter cited as support EPA's assertion that sorbent injection controls that use sodium-based agents can meet removal efficiencies of 90 percent. Response: EPA indicated in the May 27, 2009, supplemental proposal that it was considering an SO 2 percent reduction requirement of between 50 and 90 percent for the final rule (74 FR 25311). EPA has reviewed the available data and believes that a 90 percent removal requirement is appropriate for new, reconstructed, and modified thermal dryers. Affected facilities that meet the alternative SO 2 emissions limit of 85 ng/J (0.20 lb/MMBtu) heat input are not required to meet this requirement. Comment: Many commenters stated that EPA's proposal to set a combined NO X and CO emissions limit for coal dryers is inappropriate. Another commenter stated explicitly that separate NO X and CO emissions limits must be set for coal dryers. Reasons cited by individual commenters include the following. • A combined NO X /CO limit enables permitting authorities to trade off higher NO X emissions for lower CO emissions, and vice versa. EPA's proposed approach of allowing States to trade NO X and CO emissions at essentially a 1:1 ratio ignores that CO and NO X are different pollutants that do not have equivalent environmental impacts. • A combined NO X /CO limit violates CAA for the reason that the proposed combined limit is based on an assumed CO emissions rate that does not reflect application of the best system of emission reduction. EPA admits that the presumed levels of CO emissions (0.45 lb/MMBtu for modified and reconstructed dryers and 0.25 lb/MMBtu for new dryers) are levels that are already surpassed by nearly all existing industrial boilers and has not explained why industrial boilers would be capable of meeting more stringent CO limits than thermal dryers. • Test data provided in the docket indicates a wide variation in test results, especially for CO. Test data is almost exclusively based on bituminous coal drying operations, and these data do not support the conclusion that the proposed combined NO X /CO limit is applicable across all grades of coal. • Combustion controls currently represent BDT in use by the source category. Going beyond the demonstrated technologies for the source category ( e.g., incorporating post combustion control technologies, specifically selective non-catalytic reduction (SNCR) on new thermal dyers) is not required in developing NSPS. • EPA does not have sufficient data to support the proposed NO X standards, and EPA has not demonstrated that thermal dryers with different design and function can meet the same limitations as coal-fired boilers. Also, EPA has identified combustion controls that may not be available as the basis for the proposed NO X standards, especially for existing thermal dryers. Response: EPA believes that the use of a combined NO X /CO limit is appropriate because it acknowledges the inherent trade-off between the two pollutants ( i.e., a decrease in emissions of one often leads to an increase in emissions of the other). EPA has based the combined NO X /CO limit on what it believes to be adequate data from thermal dryers at subpart Y facilities; thus, the comparison to industrial boilers is misplaced. In addition, as the Court has noted, “[t]he `adequately demonstrated' requirement does not imply that any [covered facility] now in existence be able to meet the proposed standards. CAA section 111 looks toward what may be fairly be projected for the regulated future, rather than the state of the art at present.” Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (DC Cir. 1973). E. Coal Processing and Conveying Equipment, Coal Storage Systems, Transfer and Loading Systems, and Open Storage Piles Standards Comment: Many commenters acknowledged EPA's decision in the supplemental proposal to add fogging systems and passive enclosure containment systems (PECS) to its list of BDT for coal processing and conveying equipment, but stated that EPA's BDT determination still failed to meet the requirements of CAA § 111. Additional commenters also disagreed with EPA's finding of chemical suppression to be BDT for coal handling equipment processing bituminous coal, stating that EPA's current BDT approach of focusing only on emission control systems with the highest control efficiency is an inappropriate, unjustified departure from its prior technology assessments for coal preparation plants. Commenters stated that EPA's evaluation of technologies for control of fugitive emissions from coal-handling should have included wet suppression. Further, commenters asserted that EPA must explain why it has either rejected or ignored Peabody Energy's compelling comparison of wet suppression costs and chemical suppression costs. The commenters believe that the record demonstrates that cost considerations favor the use of wet suppression instead of chemical suppression for controlling fugitive emissions from preparation facilities at coal mines. Response: As pointed out by the commenters, EPA has added fogging systems and PECS as technologies representative of BDT for coal-handling equipment processing subbituminous and lignite coals (fabric filters and wet extraction scrubbers also are considered representative of BDT). As noted in the supporting documentation ( see EPA-HQ-OAR-2008-0260-0083, pp. 1-2), EPA has reviewed our determination of chemical suppressants as BDT for coal-handling equipment processing bituminous coal. However, as also noted in the support document, an owner/operator may use any combination of controls at a particular site as long as the requirements of subpart Y are met. With respect to Peabody Energy's comparison of wet suppression and chemical suppression costs, their estimates indicate that the incremental cost of chemical suppression as compared to wet suppression is $4,400 per ton of PM removed. Comment: Many commenters stated that the data used by EPA does not demonstrate the continuous achievability of the proposed opacity limit of 5 percent. Commenters further stated that the promulgation of NSPS based upon inadequate proof of achievability would defy the Admi [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%3AE9-23783. Public record. Not legal advice.