Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze and Interstate Visibility Transport Federal Implementation Plan, 9317-9378 [2014-02714]

Download as PDF Vol. 79 Tuesday, No. 32 February 18, 2014 Part II Environmental Protection Agency mstockstill on DSK4VPTVN1PROD with PROPOSALS2 40 CFR Part 51 Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze and Interstate Visibility Transport Federal Implementation Plan; Proposed Rule VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\18FEP2.SGM 18FEP2 9318 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 40 CFR Part 51 [EPA–R09–OAR–2013–0588, FRL–9906–30– Region 9] Promulgation of Air Quality Implementation Plans; Arizona; Regional Haze and Interstate Visibility Transport Federal Implementation Plan Environmental Protection Agency (EPA). ACTION: Proposed rule. AGENCY: This proposed Federal Implementation Plan (FIP) addresses the requirements of the Regional Haze Rule (RHR) and interstate visibility transport for the disapproved portions of Arizona’s Regional Haze (RH) State Implementation Plan (SIP) as described in our final rule published on July 30, 2013. Our final rule on Arizona’s RH SIP partially approved and partially disapproved the State’s plan to implement the regional haze program for the first planning period. Today’s proposed rule addresses the RHR’s requirements for Best Available Retrofit Technology (BART), Reasonable Progress Goals (RPGs) and Long-term Strategy (LTS) as well as the interstate visibility transport requirements for pollutants that affect visibility in Arizona’s 12 Class I areas as well as areas in nearby states. The BART sources addressed in this proposed FIP are Tucson Electric Power (TEP) Sundt Generating Station Unit 4, Lhoist Nelson Lime Plant Kilns 1 and 2, ASARCO Incorporated Hayden Smelter, and Freeport-McMoran Inc. (FMMI) Miami Smelter. The sources with proposed controls for reasonable progress are the Phoenix Cement Clarkdale Plant and the CalPortland Cement Rillito Plant. DATES: Written comments must be submitted to the designated contact at the address in the General Information section of SUPPLEMENTARY INFORMATION on or before March 31, 2014. ADDRESSES: See the General Information section of SUPPLEMENTARY INFORMATION for further instructions on where and how to learn more about this proposal, attend a public hearing, or submit comments. FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9, Planning Office, Air Division, Air, 75 Hawthorne Street, San Francisco, CA 94105. Thomas Webb may be reached at telephone number (415) 947–4139 and via electronic mail at r9azreghaze@ epa.gov. SUPPLEMENTARY INFORMATION: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 SUMMARY: VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 K. Congressional Review Act Table of Contents ENVIRONMENTAL PROTECTION AGENCY I. General Information A. Definitions B. Docket C. Instructions for Submitting Comments to EPA D. Submitting Confidential Business Information E. Tips for Preparing Your Comments F. Public Hearings II. Proposed Actions Background and Overview A. Background B. Regional Haze C. Interstate Transport of Pollutants That Affect Visibility III. Review of State and EPA Actions on Regional Haze A. EPA’s Schedule To Act on Arizona’s RH SIP B. History of State Submittals and EPA Actions C. EPA’s Authority To Promulgate a FIP IV. EPA’s BART Process A. BART Factors B. Visibility Analysis C. Explanation of Visibility Tables V. EPA’s Proposed BART Analyses and Determinations A. Sundt Generating Station Unit 4 B. Nelson Lime Plant Kilns 1 and 2 C. Hayden Smelter D. Miami Smelter VI. EPA’s Proposed Reasonable Progress Analyses and Determinations A. Reasonable Progress Analysis of Point Sources for NOX B. Reasonable Progress Analysis of Area Sources for NOX and SO2 C. Reasonable Progress Goals D. Meeting the Uniform Rate of Progress VII. EPA’s Proposed Long-Term Strategy Supplement A. Emission Reductions for Out-of-State Class I Areas B. Emissions Limitations and Schedules for Compliance To Achieve RPGs C. Enforceability of Emissions Limitations and Control Measures D. Proposed Partial LTS FIP VIII. EPA’s Proposal for Interstate Transport IX. Summary of Proposed Actions A. Regional Haze B. Interstate Transport X. 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 Risks and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 I. General Information A. Definitions (1) The words or initials Act or CAA mean or refer to the Clean Air Act, unless the context indicates otherwise. (2) The initials ADEQ mean or refer to the Arizona Department of Environmental Quality. (3) The words Arizona and State mean the State of Arizona. (4) The initials BACT mean or refer to Best Available Control Technology. (5) The initials BART mean or refer to Best Available Retrofit Technology. (6) The initials BOD mean or refer to boiler operating day. (7) The term Class I area refers to a mandatory Class I Federal area. (8) The initials CEMS refers to continuous emission monitoring system or systems. (9) The initials dv mean or refer to deciview, a measure of visual range. (10) The words EPA, we, us or our mean or refer to the United States Environmental Protection Agency. (11) The initials FGD mean or refer to flue gas desulfurization. (12) The initials FIP mean or refer to Federal Implementation Plan. (13) The initials FLM mean or refer to Federal Land Managers. (14) The initials IMPROVE mean or refer to Interagency Monitoring of Protected Visual Environments monitoring network. (15) The initials IPM mean or refer to Integrated Planning Model. (16) The initials lb/MMBtu mean or refer to pounds per one million British thermal units. (17) The initials LDSCR and HDSCR mean or refer to low and high dust Selective Catalytic Reduction, respectively. (18) The initials LNB mean or refer to low NOX burners. (19) The initials LTS mean or refer to Long-term Strategy. (20) The initials MACT mean or refer to Maximum Achievable Control Technology. (21) The initials MW mean or refer to megawatts. (22) The initials NAAQS mean or refer to National Ambient Air Quality Standards. (23) The initials NEI mean or refer to National Emissions Inventory. (24) The initials NESCAUM mean or refer to Northeast States for Coordinated Air Use Management. (25) The initials NM mean or refer to National Monument. (26) The initials NOX mean or refer to nitrogen oxides. E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules (27) The initials NP mean or refer to National Park. (28) The initials NPS mean or refer to the National Park Service. (29) The initials NSCR mean or refer to non-selective catalytic reduction. (30) The initials NSPS mean or refer to new source performance standards. (31) The initials PM mean or refer to particulate matter. (32) The initials PM2.5 mean or refer to fine particulate matter with an aerodynamic diameter of less than 2.5 micrometers. (33) The initials PM10 mean or refer to particulate matter with an aerodynamic diameter of less than 10 micrometers. (34) The initials PSAT mean or refer to Particulate Source Apportionment Technology. (35) The initials PSD mean or refer to Prevention of Significant Deterioration. (36) The initials PTE mean or refer to potential to emit. (37) The initials RH mean or refer to regional haze. (38) The initials RHR mean or refer to the Regional Haze Rule, originally promulgated in 1999 and codified at 40 CFR 51.301–309. (39) The initials RMC mean or refer to Regional Modeling Center. (40) The initials RP mean or refer to Reasonable Progress. (41) The initials RPG or RPGs mean or refer to Reasonable Progress Goal(s). (42) The initials SCR mean or refer to Selective Catalytic Reduction. (43) The initials SIP mean or refer to State Implementation Plan. (44) The initials SNCR mean or refer to Selective Non-catalytic Reduction. (45) The initials SO2 mean or refer to sulfur dioxide. (46) The initials SOFA mean or refer to Separated Overfire Air. (47) The initials SRP mean or refer to Salt River Project Agricultural Improvement and Power District. (48) The initials tpy mean tons per year. (49) The initials TSD mean or refer to Technical Support Document. (50) The initials TSF mean or refer to tons of stone feed. (51) The initials ULNB mean or refer to ultra-low NOX burners. (52) The initials URP mean or refer to Uniform Rate of Progress. (53) The initials VOC mean or refer to volatile organic compounds. (54) The initials WRAP mean or refer to the Western Regional Air Partnership. B. Docket This proposed action relies on documents, information and data that are listed in the index on http:// www.regulations.gov under docket VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 number EPA–R09–OAR–2013–0588. Previous proposed and final actions regarding Arizona’s RH SIP are under docket number EPA–R09–OAR–2012– 0904 and EPA–R09–OAR–2012–0021. Although listed in the index, some information is not publicly available (e.g., Confidential Business Information (CBI)). Certain other material, such as copyrighted material, is publicly available only in hard copy form. Publicly available docket materials are available either electronically at http:// www.regulations.gov or in hard copy at the Planning Office of the Air Division, AIR–2, EPA Region 9, 75 Hawthorne Street, San Francisco, CA 94105. EPA requests that you contact the individual listed in the FOR FURTHER INFORMATION CONTACT section to view the hard copy of the docket. You may view the hard copy of the docket Monday through Friday, 9–5 PST, excluding Federal holidays. C. Instructions for Submitting Comments to EPA Written comments must be submitted on or before March 31, 2014. Submit your comments, identified by Docket ID No. EPA–R09–OAR–2013–0588, by one of the following methods: • Federal Rulemaking portal: http:// www.regulations.gov. Follow the on-line instructions for submitting comments. • Email: r9azreghaze@epa.gov. • Fax: 415–947–3579 (Attention: Thomas Webb). • Mail, Hand Delivery or Courier: Thomas Webb, EPA Region 9, Air Division (AIR–2), 75 Hawthorne Street, San Francisco, California 94105. Hand and courier deliveries are only accepted Monday through Friday, 8:30 a.m. to 4:30 p.m., excluding Federal holidays. Special arrangements should be made for deliveries of boxed information. EPA’s policy is to include all comments received in the public docket without change. We may make comments available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be CBI or other information for which disclosure is restricted by statute. Do not submit information that you consider to be CBI or that is otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site is an ‘‘anonymous access’’ system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to EPA, without going through http://www.regulations.gov, we will include your email address as part PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 9319 of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD–ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption, and be free of any defects or viruses. D. Submitting Confidential Business Information Do not submit CBI to EPA through http://www.regulations.gov or email. Clearly mark the part or all of the information that you claim as CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of the disk or CD ROM as CBI and identify electronically within the disk or CD ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, you must submit a copy of the comment that does not contain the information claimed as CBI for inclusion in the public docket. We will not disclose information so marked except in accordance with procedures set forth in 40 CFR part 2. E. Tips for Preparing Comments When submitting comments, remember to: • Identify the rulemaking by docket number and other identifying information (e.g., subject heading, Federal Register date and page number). • Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes. • Describe any assumptions and provide any technical information and/ or data that you used. • If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced. • Provide specific examples to illustrate your concerns, and suggest alternatives. • Explain your views as clearly as possible, avoiding profanity or personal threats. • Make sure to submit your comments by the identified comment period deadline. To provide opportunities for questions and discussion, EPA will hold an open house prior to the public hearing. During the open house, EPA staff will be available informally to E:\FR\FM\18FEP2.SGM 18FEP2 9320 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules answer questions on our proposed rule. Any comments made to EPA staff during the open house must still be provided formally in writing or orally during a public hearing to be considered in the record. The open house and public hearing schedule is as follows. F. Public Hearings EPA will hold two public hearings at the dates, times and locations stated below to accept oral and written comments into the record. To request interpretation services or to request reasonable accommodation for a disability, please contact the person in the FOR FURTHER INFORMATION CONTACT section by February 14, 2014. Public Hearing in Phoenix: Date: February 25, 2014. Open House: 4–5 p.m. Public Hearing: 6–8 p.m. Location: Phoenix Convention Center, Rooms 150–153, 33 South 3rd Street, Phoenix, Arizona 85004. Public Hearing in Tucson: Date: February 26, 2014. Open House: 4–5 p.m. Public Hearing: 6–8 p.m. Location: Tucson High Magnet School, Auditorium, 400 North 2nd Avenue, Tucson, Arizona 85705. The public hearing will provide the public with an opportunity to present views or information concerning the proposed RH FIP for Arizona. EPA may ask clarifying questions during the oral presentations, but will not respond to the presentations at that time. We will consider written statements and supporting information submitted during the comment period with the same weight as any oral comments and supporting information presented at the public hearing. Please consult section I.C, I.D and I.E of this preamble for guidance on how to submit written comments to EPA. We will include verbatim transcripts of the hearing in the docket for this action. The EPA Region 9 Web site for the rulemaking, which includes the proposal and information about the public hearing, is at http://www.epa.gov/region9/air/ actions. II. Proposed Actions Background and Overview mstockstill on DSK4VPTVN1PROD with PROPOSALS2 A. Background The Clean Air Act (CAA) establishes as a national goal the prevention of any future, and the remedying of any existing man-made impairment of visibility in 156 national parks and wilderness areas designated as Class I areas. Arizona has a wealth of such areas. The sources addressed in this FIP affect many Class I areas in the State of VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Arizona and adjacent states. This FIP will ensure that progress is made toward natural visibility conditions at these national treasures, as Congress intended when it directed EPA to improve visibility in national parks and wilderness areas. Please refer to our previous rulemaking on the Arizona RH SIP for additional background regarding the CAA, regional haze and EPA’s RHR.1 B. Regional Haze We propose to promulgate a FIP as described in this notice and summarized in this section to address those portions of Arizona’s RH SIP that we disapproved on July 30, 2013.2 We disapproved in part Arizona’s BART control analyses and determinations for four sources, Reasonable Progress Goal (RPG) analyses and determinations, and Long-term Strategy (LTS) for making reasonable progress. The proposed FIP includes emission limits, compliance schedules and requirements for equipment maintenance, monitoring, testing, recordkeeping and reporting for all affected sources and units. The regulatory language for the proposed FIP requirements is under Part 52 at the end of this notice. 1. Proposed BART Determinations EPA conducted BART analyses and determinations for four sources: Sundt Generating Station Unit 4, Nelson Lime Plant Kilns 1 and 2, Hayden Smelter and Miami Smelter. The results of our BART evaluations are summarized here for each source and are shown in Table 1. We are seeking comments on our proposals. Sundt: We propose that Sundt Unit 4 is BART-eligible and subject to BART for sulfur dioxide (SO2), nitrogen oxides (NOX) and particulate matter with aerodynamic diameter less than 10 micrometers (PM10). For NOX, we propose an emission limit of 0.36 lb/ MMBtu as BART based upon an annual capacity factor of 0.49, which is consistent with the use of Selective Non-Catalytic Reduction (SNCR) as a control technology. For SO2, we propose an emission limit of 0.23 lb/MMBtu as BART on a 30-day boiler operating day (BOD) rolling basis, which is consistent with dry sorbent injection (DSI) as a control technology. For PM10, we propose a filterable PM10 emission limit of 0.030 lb/MMBtu as BART based on the use of the existing fabric filter baghouse. We also are proposing a switch to natural gas as a better-than1 77 2 78 PO 00000 FR 75704, 75707–75702 (December 21, 2012). FR 46142. Frm 00004 Fmt 4701 Sfmt 4702 BART alternative to the other proposed controls for all three pollutants. Nelson Lime Plant: We propose that Nelson Lime Kilns 1 and 2 are subject to BART for NOX, SO2 and PM10. For NOX, we propose a BART emission limit at Kiln 1 of 3.80 lb/ton lime and at Kiln 2 of 2.61 lb/ton lime on a 30-day rolling basis as verified by continuous emission monitoring systems (CEMS). This emission limit is consistent with the use of low-NOX burners (LNB) and SNCR as control technologies. We propose that BART for SO2 is an emission limit of 9.32 lb/ton for Kiln 1 and 9.73 lb/ton for Kiln 2 on a 30-day rolling basis, which is consistent with the use of a lower sulfur fuel blend. For PM10, we propose a BART emission limit of 0.12 lb/tons of stone feed (TSF) to control PM10 at Kilns 1 and 2 based on the use of the existing fabric filter baghouses. This level of control is commensurate with the MACT standard that applies to this source. Hayden Smelter: We propose that the Hayden Smelter is subject to BART for NOX, and propose BART emission limits for NOX and SO2. EPA previously approved the State’s determination that the Hayden Smelter is subject to BART for SO2. For NOX, we propose to find that controlling emissions from the converters and anode furnaces is costeffective, but would not result in sufficient visibility improvement to warrant the cost. Therefore, we are proposing an annual emission limit of 40 tpy NOX emissions from the BARTeligible units, which is consistent with current emissions from these units. For SO2 from the converters, we propose a BART control efficiency of 99.8 percent on a 30-day rolling basis on all SO2 captured by primary and secondary control systems, which can be achieved with a new double contact acid plant. For SO2 from the anode furnaces, we propose to find that controlling the 37 tons per year (tpy) of SO2 emissions from these furnaces, while costeffective, is not warranted as BART given the potential for only minimal visibility improvement. We propose as an emission limitation for the anode furnace a work practice standard requiring that the furnaces only be charged with blister copper or higher purity copper. We previously approved Arizona’s determination that BART for PM10 at the Hayden Smelter is no additional controls. In order to ensure the enforceability of this determination, we are proposing to incorporate emission limitations and associated compliance requirements from the National Emission Standard for Hazardous Air Pollutants (NESHAP) for E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Primary Copper Smelting at 40 CFR Part 63, Subpart QQQ, as part of the LTS. Miami Smelter: EPA proposes that the Miami Smelter is subject to BART for NOX, and proposes BART emission limits for NOX and SO2. EPA previously approved the State’s determination that the Miami Smelter is subject to BART for SO2. For NOX, we propose to find that controlling the small amount of emissions from the converters and electric furnace is cost-effective, but would not result in sufficient visibility improvement to warrant the cost. Therefore, we are proposing an annual emission limit of 40 tpy NOX emissions from the BART-eligible units, which is consistent with current emissions. For SO2 from the converters, we propose a BART control efficiency of 99.7 percent on a 30-day rolling basis on all SO2 emissions captured by the primary and secondary control systems as verified by CEMS. This control efficiency could be met through improvements to the primary capture system, construction of a secondary capture system, and application of the MACT QQQ 9321 standards to the capture systems. For SO2 emissions from the electric furnace, we propose as BART the work practice standard to prohibit active aeration. We previously approved Arizona’s determination that BART for PM10 at the Miami Smelter is the NESHAP for Primary Copper Smelting. We now propose to find that the federally enforceable provisions of the NESHAP, which apply to the Miami Smelter and are incorporated into its Title V Permit, are sufficient to ensure the enforceability of this determination. TABLE 1—PROPOSED EMISSION LIMITS ON BART SOURCES Source Units Pollutants Limit Sundt Generating Station. Unit 4 ........................ NOX ......... SO2 ......... PM10 ........ NOX ......... SO2 ......... PM10 ........ NOX ......... SO2 ......... PM10 ........ NOX ......... SO2 ......... PM10 ........ NOX ......... SO2 ......... SO2 ......... NOX ......... SO2 ......... 0.36 0.23 0.030 0.25 0.00064 0.010 3.80 9.32 0.12 2.61 9.73 0.12 40 99.8 None 40 99.7 lb/MMBtu .................. SO2 ......... None None ......................... Unit 4 (Alternative) ... Chemical Lime Nelson Kiln 1 ........................ Kiln 2 ........................ Hayden Smelter ......... Converters 1, 3–5 ..... Miami Smelter ............ Anode Furnaces 1, 2 Converters 2–5 ......... Electric Furnace ....... 2. Proposed RP Determinations Point Sources of NOX: EPA conducted an extensive RP analysis of NOX point sources that resulted in proposed determinations for nine sources and proposed controls on two sources as shown in Table 2. We are proposing an emissions limit of 2.12 lb/ton on Kiln 4 Measure Corresponding control technology lb/MMBtu .................. lb/ton feed ................. ................................... tpy ............................. Control efficiency ...... None ......................... tpy ............................. Control efficiency ...... of the Phoenix Cement Clarkdale Plant based on a 30-day rolling average, which is consistent with SNCR as a control technology. We are proposing an emissions limit of 2.67 lb/ton on Kiln 4 of the CalPortland Cement Rillito Plant based on a 30-day rolling average, which also is consistent with SNCR Selective Non-Catalytic Reduction. Dry Sorbent Injection. Fabric filter baghouse (existing). Switch to natural gas. Selective Non-Catalytic Reduction. Lower sulfur fuel. Fabric filter baghouse (existing). Selective Non-Catalytic Reduction. Lower sulfur fuel. Fabric filter baghouse (existing). None. New double contact acid plant. Work practice standard. None. Improve primary and new secondary capture systems. Work practice standard. control technology. We are also taking comment on the possibility of requiring a rolling 12-month cap on NOX emissions in lieu of a lb/ton emission limit. For Phoenix Cement, this cap would be 947 tpy and apply to Kiln 4. For CalPortland, this cap would be 2,082 tpy and apply to Kilns 1–4. TABLE 2—PROPOSED EMISSION LIMITS ON RP SOURCES Units Pollutants Phoenix Cement .......................... CalPortland Cement .................... mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Source Kiln 4 ................. Kiln 4 ................. NOX .................. NOX .................. Area Sources of NOX and SO2: We propose to find that it is reasonable not to require additional controls on these sources at this time. Primarily, these area source categories are distillate fuel oil combustion in industrial and commercial boilers and in internal combustion engines, and residential natural gas combustion. The State’s area sources, which currently contribute a relatively small percentage of the visibility impairment at impacted Class I areas, would benefit from better VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Limit Measure 2.12 2.67 lb/ton ................. lb/ton ................. emission inventories and an improved RP analysis in the next planning period. Reasonable Progress Goals: EPA is proposing RPGs consistent with a combination of control measures that include those in the approved Arizona RH SIP as well as the approved and proposed Arizona RH FIP. While not quantifying a new set of RPGs based on these control measures, we propose that it is reasonable to assume improved levels of visibility at Arizona’s 12 Class I areas by 2018 since the measures in PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 Corresponding control technology Selective Non-Catalytic Reduction. Selective Non-Catalytic Reduction. the FIP are significantly beyond what was in the State’s plan. Demonstration of Reasonable Progress: EPA proposes to find that it is not reasonable to provide for rates of progress at the 12 Class I areas consistent with the uniform rate of progress (URP) in this planning period.3 Given the variety and location of sources contributing to visibility impairment in Arizona, EPA considers 3 40 E:\FR\FM\18FEP2.SGM CFR 51.308(d)(1)(ii). 18FEP2 9322 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules it unlikely that Arizona’s Class I areas will meet the URP in 2018. We propose to find that the RP analyses underlying our actions on the Arizona SIP 4 and in this proposal are sufficient to demonstrate that it is not reasonable to provide for rates of progress in this planning period that would attain natural conditions by 2064.5 This is consistent with our proposed and final rules on the Arizona RH SIP in which we approved Arizona’s determinations that it is not reasonable to require additional controls to address organic carbon, elemental carbon, coarse mass and fine soil during this planning period.6 We also approved the State’s decision not to require additional controls (i.e., controls beyond what the State or we determine to be BART) on point sources of SO2.7 3. Long-Term Strategy Proposal EPA proposes to find that provisions in today’s proposal in combination with provisions in the approved Arizona SIP and FIP 8 fulfill the requirements of 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F). These requirements are to include in the LTS measures needed to achieve emission reductions for out-of-state Class I areas, emissions limitations and schedules for compliance to achieve the reasonable progress goals, and enforceability of emissions limitations and control measures.9 In today’s notice we propose to promulgate emission limits, compliance schedules and other requirements for four BART sources and two RP sources to complete the actions taken in our previous final rule to address these requirements. C. Interstate Transport of Pollutants That Affect Visibility We propose that a combination of SIP and FIP measures will satisfy the FIP obligation for the visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. CAA section 110(a)(2)(D)(i)(II) requires that all SIPs contain adequate provisions to prohibit emissions that will interfere with other states’ required measures to protect visibility. We refer to this requirement herein as the interstate transport visibility requirement. ADEQ submitted SIP revisions to address this requirement in 2007 for the 1997 8-hour ozone NAAQS 10 and 1997 PM2.5 NAAQS 11 (2007 Transport SIP) 12 and in 2009 for the 2006 PM2.5 NAAQS 13 (2009 Transport SIP).14 Each of these SIP revisions indicated that it is appropriate to assess Arizona’s interference with other states’ measures to protect visibility in conjunction with the State’s RH SIP.15 In our final rule published on July 30, 2013, EPA disapproved these SIP submittals with respect to the interstate transport visibility requirement, triggering the obligation for EPA to promulgate a FIP to address this requirement.16 Accordingly, today’s notice describes our proposed FIP for the interstate transport visibility requirement for the 1997 8-hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. III. Review of State and EPA Actions on Regional Haze A. EPA’s Schedule To Act on Arizona’s RH SIP EPA received a notice of intent to sue in January 2011 stating that we had not met the statutory deadline for promulgating RH FIPs and/or approving RH SIPs for dozens of states, including Arizona. This notice was followed by a lawsuit filed by several advocacy groups (Plaintiffs) in August 2011.17 In order to resolve this lawsuit and avoid litigation, EPA entered into a Consent Decree with the Plaintiffs, which sets deadlines for action for all of the states covered by the lawsuit, including Arizona. This decree was entered and later amended by the United States District Court for the District of Columbia over the opposition of Arizona.18 Under the terms of the Consent Decree, as amended, EPA is currently subject to three sets of deadlines for taking action on Arizona’s RH SIP as listed in Table 3.19 TABLE 3—CONSENT DECREE DEADLINES FOR EPA TO ACT ON ARIZONA’S RH SIP EPA actions Proposed rule Final rule Phase 1—BART determinations for Apache, Cholla and Coronado .............................................. Phase 2—All remaining elements of the Arizona RH SIP .............................................................. Phase 3—FIP for disapproved elements of the Arizona RH SIP ................................................... July 2, 2012 1 ............. December 8, 2012 3 .. January 27, 2014 ...... November 15, 2012.2 July 15, 2013.4 June 27, 2014. 1 Published in in 3 Published in 4 Published in 2 Published the the the the Federal Federal Federal Federal Register Register Register Register on on on on July 20, 2012, 77 FR 42834. December 5, 2012, 77 FR 72512. December 21, 2012, 77 FR 75704. July 30, 2013, 78 FR 46142. B. History of State Submittals and EPA Actions mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Because four of Arizona’s 12 mandatory Class I Federal areas are on 4 See proposed actions at 77 FR 75727–75730, 78 FR 29297–292300 and final action at 78 FR 46172. 5 40 CFR 51.308(d)(1)(ii). 6 See 77 FR 75728 for a discussion on sources of organic carbon and elemental carbon (fires), and 78 FR 29297–29299 for a discussion of coarse mass and fine soil. 7 78 FR 46172. 8 77 FR 75512–72580, December 5, 2012. 9 See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)). 10 62 FR 38856, July 18, 1997. 11 62 FR 38652, July 18, 1997. 12 ‘‘Revision to the Arizona State Implementation Plan Under Clean Air Act Section 110(a)(2)(D)(i)— VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 the Colorado Plateau, the State had the option of submitting a RH SIP under CAA section 309 of the RHR. A SIP that is approved by EPA as meeting all of the requirements of section 309 is ‘‘deemed to comply with the requirements for reasonable progress with respect to the 16 Class I areas [on the Colorado Regional Transport,’’ submitted by ADEQ on May 24, 2007. 13 71 FR 61144, October 17, 2006. 14 ‘‘Arizona State Implementation Plan Revision under Clean Air Act Section 110(a)(1) and (2); 2006 PM2.5 NAAQS, 1997 PM2.5 NAAQS, and 1997 8hour Ozone NAAQS,’’ submitted by ADEQ on October 14, 2009, which addressed the requirements of section 110(a)(2)(D)(i) with respect to the 2006 PM2.5 NAAQS in Section 2.4 and Appendix B of the submittal. 15 This concept is also presented in EPA’s 2006 guidance memo on interstate transport, which recommended that states make a submission indicating that it was premature, at that time, to determine whether there would be any interference with other states’ required measures to protect visibility until the submission and approval of regional haze SIPs. See ‘‘Guidance for State Implementation Plan (SIP) Submissions to Meet Current Outstanding Obligations Under Section 110(a)(2)(D)(i) for the [1997] 8-Hour Ozone and PM2.5 National Ambient Air Quality Standards,’’ August 15, 2006. 16 78 FR 46142, July 30, 2013. 17 National Parks Conservation Association v. Jackson (D.D.C. Case 1:11–cv–01548). 18 National Parks Conservation Association v. Jackson (D.D.C. Case 1:11–cv–01548), Memorandum Order and Opinion (May 25, 2012), Minute Order (July 2, 2012), Minute Order (November 13, 2012) and Minute Order (February 15, 2013). 19 Id. PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Plateau] for the period from approval of the plan through 2018.’’ 20 When these regulations were first promulgated, 309 SIPs were due no later than December 31, 2003. Accordingly, ADEQ submitted to EPA on December 23, 2003, a 309 SIP for Arizona’s four Class I Areas on the Colorado Plateau. ADEQ submitted a revision to its 309 SIP, consisting of rules on emissions trading and smoke management, and a correction to the State’s regional haze statutes, on December 31, 2004. EPA approved the smoke management rules submitted as part of the revisions in 2004,21 but did not propose or take final action on any other portion of the 309 SIP. In response to a court decision,22 EPA revised 40 CFR 51.309 on October 13, 2006, making a number of substantive changes and requiring states to submit revised 309 SIPs by December 17, 2007.23 Subsequently, ADEQ sent a letter to EPA dated December 24, 2008, acknowledging that it had not submitted a SIP revision to address the requirements of 40 CFR 51.309(d)(4) related to stationary sources and 40 CFR 51.309(g), which governs reasonable progress requirements for Arizona’s eight mandatory Class I areas outside of the Colorado Plateau.24 EPA made a finding on January 15, 2009, that 37 states, including Arizona, had failed to make all or part of the required SIP submissions to address regional haze.25 Specifically, EPA found that Arizona failed to submit the plan elements required by 40 CFR 51.309(d)(4) and (g). EPA sent a letter to ADEQ on January 14, 2009, notifying the State of this failure to submit a complete SIP. ADEQ decided to submit a SIP under CAA section 308, instead of under section 309. EPA proposed on February 5, 2013,26 to disapprove Arizona’s 309 SIP except for the smoke management rules that we had previously approved. Our final rule partially disapproving Arizona’s 309 SIP was published on August 8, 2013.27 ADEQ adopted and transmitted its 2011 RH SIP under section 308 of the RHR to EPA Region 9 in a letter dated February 28, 2011. The SIP was determined complete by operation of law on August 28, 2011.28 The SIP was properly noticed by the State and 20 40 CFR 51.309(a). FR 28270 and 72 FR 25973. 22 Center for Energy and Economic Development v. EPA, 398 F.3d 653 (D.C. Circuit 2005). 23 71 FR 60612. 24 Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA, dated December 24, 2008. 25 74 FR 2392. 26 78 FR 8083. 27 78 FR 48326. 28 CAA section 110(k)(1)(B). 21 71 VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 available for public comment for 30 days prior to one public hearing held in Phoenix, Arizona, on December 2, 2010. Arizona included in its SIP responses to written comments from EPA Region 9, the National Park Service, the U.S. Forest Service, and other stakeholders including regulated industries and environmental organizations. The 2011 RH SIP is available to review in the docket for this proposed rule.29 As shown in Table 3, the first phase of EPA’s action on the 2011 RH SIP addressed three BART sources. The final rule for the first phase (a partial approval and partial disapproval of the State’s plan and a partial FIP) was signed by the Administrator on November 15, 2012, and published in the Federal Register on December 5, 2012. The emission limits on the three sources will improve visibility by reducing NOX emissions by about 22,700 tons per year. In the second phase of our action, we proposed on December 21, 2012, to approve in part and disapprove in part the remainder of the 2011 RH SIP. ADEQ submitted an Arizona RH SIP Supplement on May 3, 2013, to correct certain deficiencies identified in that proposal. We then proposed on May 20, 2013, to approve in part and disapprove in part the Supplement. Our final rule approving in part and disapproving in part Arizona’s RH SIP was published on July 30, 2013. 9323 [A] plan (or portion thereof) promulgated by the Administrator to fill all or a portion of a gap or otherwise correct all or a portion of an inadequacy in a State implementation plan, and which includes enforceable emission limitations or other control measures, means or techniques (including economic incentives, such as marketable permits or auctions or emissions allowances) . . . Thus, because we determined that Arizona failed to timely submit a Regional Haze SIP, we are required to promulgate a Regional Haze FIP for Arizona, unless we first approve a SIP that corrects the non-submittal deficiencies identified in our finding of January 15, 2009. For the reasons explained below, we approved in part and disapproved in part the Arizona Regional Haze SIP on July 30, 2013. Therefore, we are proposing a FIP to address those portions of the SIP that we disapproved. IV. EPA’s BART Process A. BART Factors Section 302(y) defines the term ‘‘Federal implementation plan’’ in pertinent part, as: The purpose of the BART analysis is to identify and evaluate the best system of continuous emission reduction based on the BART Guidelines 30 as summarized below. Steps 1 through 3 address the availability, feasibility and effectiveness of retrofit control options. In our analysis of control technology options, we expressly include the emission baseline calculation that is a key factor in determining control effectiveness. Step 4 is the five-factor BART analysis that results in selecting the emission limit that represents BART in Step 5. Following the process steps is a short description of each BART factor. Step 1—Identify all available retrofit control technologies. Step 2—Eliminate technically infeasible options. Step 3—Evaluate control effectiveness of remaining control technologies. Step 4—Evaluate impacts and document the results. • Factor 1: Cost of compliance. • Factor 2: Energy and non-air quality environmental impacts of compliance. • Factor 3: Pollution control equipment in use at the source. • Factor 4: Remaining useful life of the facility. • Factor 5: Visibility impacts. Step 5—Select BART. Factor 1: Costs of Compliance: The evaluation of costs is an important part of a five-factor analysis because it influences the cost-effectiveness that is 29 ‘‘Arizona State Implementation Plan, Regional Haze under Section 308 of the Federal Regional Haze Rule,’’ February 28, 2011. 30 See July 6, 2005 BART Guidelines, 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations. C. EPA’s Authority To Promulgate a FIP Under CAA section 110(c), EPA is required to promulgate a FIP within 2 years of the effective date of a finding that a state has failed to make a required SIP submission. The FIP requirement is terminated if a state submits a regional haze SIP, and EPA approves that SIP before promulgating a FIP. See 74 FR 2392. Specifically, CAA section 110(c) provides: (1) The Administrator shall promulgate a Federal implementation plan at any time within 2 years after the Administrator— (A) finds that a State has failed to make a required submission or finds that the plan or plan revision submitted by the State does not satisfy the minimum criteria established under [CAA section 110(k)(1)(A)], or (B) disapproves a State implementation plan submission in whole or in part, unless the State corrects the deficiency, and the Administrator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan. PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9324 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules compared to the visibility benefits. Estimating the cost of compliance primarily depends on the cost estimates and control effectiveness of each technically feasible BART control option. For each of the four BART facilities evaluated in this section, we state the source of the cost-related information and how it was used in our analysis. While EPA relies primarily on the cost methods in our Control Cost Manual, we also rely on verified cost estimates from the companies and cost methods used for specific industries. In some cases, certain capital costs and annual operating costs were developed by our contractor based on actual costs associated with specific types of sources. Where possible, we have conducted new cost analyses considering more recent information from ADEQ or from the four BART facilities. Please refer to the TSD for the detailed cost analyses. Factor 2: Energy and Non-air Quality Environmental Impacts: In assessing the potential energy impacts of BART control options, we consider direct and indirect effects on energy availability and costs. An example of a direct energy impact is the cost of energy consumption from the control equipment. Examples of non-air quality impacts include safety issues associated with handling and transportation of anhydrous ammonia or the ability to sell fly ash rather than dispose of it. Factor 3: Pollution Equipment in Use at the Source: The presence of existing pollution control technology at each source is reflected in our BART analysis in two ways. First, we always consider simple retention of existing equipment as a BART candidate. We also consider existing equipment in determining available control technologies that can be used with or replace such equipment. Second, where appropriate, we consider existing equipment in developing baseline emission rates for use in cost calculations and visibility modeling. Pollutant-specific discussions of these issues are included in the following sections. Factor 4: Remaining Useful Life of the Source: We consider each source’s ‘‘remaining useful life’’ as one element of the overall cost analysis as allowed by the BART Guidelines.31 In cases where we are not aware of any enforceable shut-down date for a particular source or unit, we use a 20year amortization period as the remaining useful life per the EPA Cost Control Manual. Factor 5: Anticipated Degree of Visibility Improvement: EPA relied on 31 40 CFR Part 51, Appendix Y, section IV.D.4.k. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 the CALPUFF modeling system (version 5.8) for visibility modeling, which consists of the CALPUFF dispersion model, the CALMET meteorological data processor, and the CALPOST postprocessing program. The initial modeling was performed by our contractor, the University of North Carolina (UNC) at Chapel Hill. In some cases, companies submitted BART analyses including visibility modeling that we used to evaluate visibility benefits. An explanation of the visibility analysis and tables follows this section, a description of the modeling is included in the five-factor discussion for each source, and more details are available in the TSD. B. Visibility Analysis EPA estimated the degree of visibility improvement expected to result from various BART control options based on the difference between baseline visibility impacts prior to controls and visibility impacts with controls in operation. Baseline emissions were based on the highest 24-hour emissions from monitored emissions data when available, otherwise from estimates of production rates and emission factors. Control case emissions were derived from the baseline by applying the percent reduction in emission factor expected from the control. Impacts at all Class I areas within 300 km of each facility were assessed. EPA used the CALPUFF model version 5.8 32 to determine the baseline and post-control visibility impacts, following the modeling approach recommended in the BART Guidelines. Our contractor at UNC developed a modeling protocol and carried out most of the modeling and the post-processing of model output into tables of visibility impacts. EPA supplemented this for certain sources with modeling of additional control scenarios, corrections to some scenarios and post-processing work, and some sensitivity simulations. Also, EPA performed the modeling for the two smelters. Details of the modeling are in the TSD. EPA modeled all units (stacks) and pollutants simultaneously for each 32 EPA relied on version 5.8 of CALPUFF because it is the EPA-approved version promulgated in the Guideline on Air Quality Models (40 CFR part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 2003). EPA updated the specific version to be used for regulatory purposes on June 29, 2007, including minor revisions as of that date; the approved CALPUFF modeling system includes CALPUFF version 5.8, level 070623, and CALMET version 5.8 level 070623. At this time, any other version of the CALPUFF modeling system would be considered an ‘‘alternative model’’, subject to the provisions of Guideline on Air Quality Models section 3.2.2(b), requiring a full theoretical and performance evaluation. PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 source. Modeling of all emissions from all units accounts for the chemical interaction between multiple plumes, and between plumes and background concentrations. This also accounts for the fact that deciview benefits from controls on individual units are not strictly additive. As recommended in the BART Guidelines, the 98th percentile daily impact in deciviews is used as the basic metric of visibility impact. EPA relied on the 98th percentile over the merged 2001–2003 period. The alternative of using the average of the three 98th percentiles from 2001, 2002 and 2003 was also calculated, and the results of using it are provided in the TSD, although they differ little from the merged approach. Both are valid indicators of the 98th percentile.33 EPA also mainly relied on the revised IMPROVE equation for translating pollutant concentrations into deciviews (CALPOST visibility method 8), the recommended method for new visibility analyses. The old IMPROVE equation (method 6) was used by most states in their original SIP submittals and was acceptable at that time. EPA used the best 20 percent of natural background days in calculating delta deciviews. For the original SIP submittals, states were free to use this or the annual average background. Overall, we refer to the method we used as method ‘‘8b’’ (‘‘b’’ for ‘‘best’’). Model results using visibility method 6 and annual average background conditions (‘‘a’’ for average) also are provided in the TSD (i.e., methods 6a, 6b, and 8a, as well as 8b). C. Explanation of Visibility Tables For each facility, this notice provides one or more tables of visibility impacts and visibility improvement from controls in deciviews. Each table has the same format: columns list the Class I areas within 300 km of the facility, the distance,34 baseline modeled visibility impact from the facility for each area, and one or more columns with the 33 For each modeled day, the CALPUFF model provides the highest impact from among the receptor locations for a given Class I area. The baseline impact in the tables is the 98th percentile among these daily values. The improvement in the tables is the difference between that baseline impact and the 98th percentile impact after applying controls. The 98th percentile is represented by the 22nd high over the 2001–2003 period modeled. The TSD includes an alternative, the average of each of the three years’ 8th highs, which yields slightly different values. 34 The distances given are from the facility to the nearest model receptor location; distances to the actual Class I area boundary may be slightly less. Receptor locations are defined for all Class I areas by the National Park Service. See ‘‘Class I Receptors’’ Web site, http://www2.nature.nps.gov/ air/maps/Receptors/. E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules modeled visibility improvement from a candidate control option. A modeling run abbreviation, such as ‘‘base’’ or ‘‘ctrl2’’, is included along with a short description of the option. For several facilities, there are two different baselines incorporating different emission assumptions. For these, there are baseline and control columns for each of the two baselines. For Sundt Unit 4, there are separate tables for SO2 and NOX controls, and an additional table showing the effect of reductions for both SO2 and NOX for the proposed BART controls and for a better-thanBART alternative. At the bottom of each table are five rows showing impacts and improvements from the facility for all the Class I areas considered together, and also two measures of visibility costeffectiveness. The cost-effectiveness here is ‘‘dollars per deciview,’’ where dollars is the annualized total cost of the control in millions of dollars per year, divided by either the sum of deciview improvements over all impacted Class I areas, or the largest single area deciview improvement. Cost-effectiveness in terms of dollars per ton is presented in other tables and has been considered for each source and BART option. The headings for these table rows are: (1) ‘‘Cumulative (sum),’’ the cumulative impact or improvement that is computed as the sum of impact or improvement over all the areas; (2) ‘‘Maximum,’’ single largest impact or improvement that is the maximum over all the areas; (3) ‘‘# CIAs >= 0.5 dv,’’ the number of Class I areas having a baseline impact from the source of at least 0.5 dv (or, for the control columns, the number of areas showing improvement of at least 0.5 dv due to the control); (4) ‘‘Million $/dv (cumul. dv),’’ annual control cost in millions of dollars per deciview considering the improvement at all the Class I areas together; and (5) ‘‘Million $/dv (max. dv),’’ annualized cost per deciview considering the largest single area improvement. The Federal Land Managers have sometimes used $10 million/dv as a comparison benchmark for the $/dv computed from the maximum, and $20 million/dv as a benchmark for $/dv computed from cumulative deciviews. We have not endorsed the use of these or any other $/dv benchmarks as criteria for making BART determinations. 9325 The TSD for this notice provides bar charts and additional visibility tables, including results for individual modeled years and their average, the old IMPROVE equation, and annual average background conditions instead of best 20 percent. There also are model results for various sensitivity analyses. V. EPA’s Proposed BART FIP A. Sundt Generating Station Unit 4 Summary: EPA is proposing to find that Sundt Unit 4 is eligible for and subject to BART. EPA is proposing BART emissions limits on Sundt Generating Station Unit 4 for NOX, SO2 and PM10 based on the corresponding control technologies listed in Table 4 and described in the following BART analyses. For NOX, we propose an emission limit of 0.36 lb/MMBtu consistent with the use of SNCR. For SO2, we propose an emission limit of 0.23 lb/MMBtu consistent with the use of DSI. For PM10, we propose a filterable PM10 emission limit of 0.03 lb/MMBtu based on the use of the existing fabric filter baghouse. Finally, we are also proposing a switch to natural gas as a better-than-BART alternative. TABLE 4—SUNDT 4: SUMMARY OF PROPOSED BART DETERMINATIONS Emission limit (lb/MMBtu) Pollutant NOX .................................................................................................................. SO2 .................................................................................................................. PM10 ................................................................................................................. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Affected Class I Areas: Ten Class I areas are within 300 km of Sundt. Their nearest borders range from 17 km to 247 km away, with Saguaro NP the closest, and Galiuro WA the second closest. The highest baseline visibility impact of Sundt Unit 4 is 3.4 dv at Saguaro. The second highest baseline impact is 1.1 dv at Galiuro. Other areas have visibility impacts of 0.5 dv or less. The cumulative sum of visibility impacts over all the Class I areas is 6.6 dv. Facility Overview: The Sundt Generating Station is an electric utility power plant located in Tucson, Arizona, operated by Tucson Electric Power. The VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 0.36 0.23 0.030 plant consists of four steam electric boilers and three stationary combustion turbines for a total net generating capacity of approximately 500 megawatts (MW).35 Sundt Unit 4 is a steam electric boiler that was manufactured in 1964 and placed into operation in about 1967. Unit 4 is a dry bottom wall-fired boiler with a maximum gross capacity of 130 MW when firing coal. Originally designed to fire natural gas and fuel oil, Sundt Unit 4 was converted to also be able to fire 35 As described in Pima DEQ Permit No. 1052, in the TSD. PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 Control technology Selective Non-Catalytic Reduction. Dry Sorbent Injection. Fabric filter baghouse (existing). coal in the early 1980s as a result of an order issued by the Department of Energy. The unit now fires both coal and natural gas, as explained in more detail below. As part of the coal conversion, the unit was equipped with a fabric filter for particulate matter control. Unit 4 was upgraded in 1999 with LNB and overfire air (OFA) designed to meet Phase II Acid Rain Program requirements. At present, Unit 4 operates with the pollution control equipment and is subject to the emission limits listed in Table 5 that reflects a coal-operating scenario. E:\FR\FM\18FEP2.SGM 18FEP2 9326 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 5—SUNDT 4: CURRENT EMISSION LIMITS AND CONTROL TECHNOLOGY Pollutant Emission limit Control device NOX ..................................................................... SO2 ...................................................................... PM10 .................................................................... 0.46 lb/MMBtu 36 ................................................ 1 lb/MMBtu 37 ..................................................... 233 lb/hr 38 ......................................................... injection causes the flame to impinge on the back wall of the boiler which damages the boiler tubes.39 A summary of historical emissions data for a recent period of time is in Table 6. maximum gross capacity at which the unit could operate for a sustained period of time while burning coal is about 130 MW. This is due primarily to the fact that the amount of coal that can be introduced to the boiler is limited by the size of the boiler. Excess coal TEP has indicated that the generating capacity of Sundt Unit 4 while firing coal is reduced compared to its capacity using natural gas. As reported to the Energy Information Agency (EIA), Unit 4 has a 173 MW nameplate capacity while firing natural gas. However, the LNB with OFA. None. Fabric filter/baghouse. TABLE 6—SUNDT 4: HISTORICAL EMISSIONS (2008–2012) Heat duty (MMBtu/yr) Year mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2012 2011 2010 2009 2008 ......................................................... ......................................................... ......................................................... ......................................................... ......................................................... 6,313,719 5,993,769 6,869,999 4,801,971 8,709,923 NOX (tpy) 945 1,366 1,303 709 1,880 SO2 (lb/MMBtu) (tpy) 0.297 0.445 0.368 0.285 0.429 371 2,185 1,733 636 2,882 Baseline Emissions Calculations: The baseline period, baseline emissions, and capacity factor are three key variables in determining BART that are linked to fuel usage. TEP has indicated that while Sundt Unit 4 predominantly has operated as a coal-fired unit, it has recently expanded its use of natural gas as a result of historically low natural gas prices.40 As shown in the last column of Table 6, Unit 4 has used much higher amounts of natural gas during 2009– 2010 and again in 2012 that are not representative of anticipatable operations based on coal. Accordingly, we use calendar year 2011 emissions when Unit 4 predominately used coal as the baseline period for annual average emission estimates. Although this represents only a single year of emissions data, we consider this period of coal usage, rather than a period of primarily natural gas usage, to represent a realistic depiction of anticipated annual emissions when burning coal.41 In addition, we rely on an annual capacity factor of 0.49 based on a coalfired capacity of 130 MW and actual generation from the baseline period of 2011. For visibility modeling, we used baseline emissions for NOX and SO2 based on maximum daily emission rates, as reported to EPA’s CAMD Acid Rain Program database, for the period from 2008 to 2010. While this time period is prior to the 2011 baseline period used for the annual emission estimates, the highest daily emission rates from 2008 to 2010 correspond to coal usage. Since these maximum daily emission rates still correspond to coal usage, we consider them reasonable estimates of baseline emissions despite the fact that they are drawn from a baseline period different from the one used to estimate annual emission rates. For PM10, the baseline emission rate used in visibility modeling is based on the value in the original Western Regional Air Partnership (WRAP) visibility modeling that reflects the use of coal and the existing fabric filter. For a more detailed analysis of how we determined the baseline period, baseline emissions and capacity factor, please refer to the TSD. Modeling Overview: EPA’s contactor UNC performed the initial modeling of Sundt’s visibility impacts. EPA performed supplemental modeling to correct some minor errors in the initial work and to estimate impacts from additional control scenarios, such as switching entirely to natural gas fuel. EPA also modeled the impacts for the western unit of Saguaro NP, whereas originally only the eastern unit was included. Although only Unit 4 is BART-eligible, all four Sundt units were included in the CALPUFF modeling to 36 Pima DEQ Permit No. 1052, Attachment F: Phase II Acid Rain Permit. 37 Pima DEQ Permit No. 1052, Specific Condition II.A.2.b. 38 As determined by Pima DEQ Permit No. 1052, Specific Condition II.A.1. 39 TEP’s letter dated May 10, 2013, page 2. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 (lb/MMBtu) 0.118 0.729 0.505 0.265 0.661 Coal (tons) 44,049 265,111 162,212 73,464 378,956 Natural gas (MCF) 4,660,701 157,919 1,904,433 2,642,992 18,422 more accurately represent the chemistry of the facility’s pollutant plume. Baseline emissions for modeling were based on daily CAMD emissions monitoring data for 2008–2010, a period with no changes in pollution controls at the facility. Control case emissions were derived from the baseline by applying the percent reduction expected from the control. Saguaro NP has an eastern unit, the Rincon Mountain District, and a western unit, the Tucson Mountain District. In the original set of modeling receptor locations developed by the National Park Service, only the eastern unit was included. CALPUFF modeling typically covered only the eastern unit. This is true of modeling by the WRAP, and also of modeling by EPA’s contractor UNC, which used the WRAP work as a starting point. A more recent set of NPS modeling receptors from 2008 is available that covers both eastern and western units of Saguaro. For this FIP, EPA remodeled for both Saguaro units where needed for a given facility. The only facilities for which it makes a significant difference are TEP Sundt and CalPortland Cement due to their close proximity to Saguaro. 40 TEP’s letter dated May 10, 2013, page 2. discussed in the BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d. 41 As E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9327 approximately 80 to 90 percent control efficiency, and that this emission rate can be achieved on a retrofit basis, particularly when combined with combustion control technology such as LNB.48 Our contractor used a design emission rate of 0.050 lb/MMBtu (annual average), which in the case of Sundt Unit 4 corresponds to a control efficiency of 89 percent. While this is a value close to the upper range of SCR control efficiency, we consider the use of 0.050 lb/MMBtu appropriate for Sundt Unit 4. A review of Acid Rain Program data indicates that there are up to seven dry-bottom, wall-fired boilers operating with SCR on a retrofit basis that have achieved an annual average emission rate of 0.050 lb/MMBtu or lower in practice.49 However, there are design differences between Sundt Unit 4 and these other units (i.e., boiler size, coal type and characteristics, and loading profile) that have the potential to affect this comparison. If we receive additional comments that sufficiently document source-specific considerations justifying the use of an emission rate higher than 0.050 lb/ MMBtu, we may incorporate such considerations in our selection of BART. For our NOX BART analysis, we identify all available control technologies, eliminate options that are not technically feasible, and evaluate the control effectiveness of the remaining control options. We then evaluate each technically feasible control in terms of a five-factor BART analysis and propose a determination for BART. a. Control Technology Availability, Technical Feasibility, and Effectiveness EPA proposes to find that SNCR and selective catalytic reduction (SCR) are available and technically feasible options to control NOX emissions with a control efficiency of approximately 50 percent for SNCR and approximately 89 percent for SCR. SNCR involves the non-catalytic decomposition of NOX to molecular nitrogen and water. Typical NOX control efficiencies for SNCR range from 40 to 60 percent, depending on inlet NOX concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of interfering chemical substances in the gas stream. Because Sundt Unit 4 already operates with NOX combustion controls, we have used an SNCR control efficiency of 30 percent from a baseline that includes LNB with OFA. Considering typical combustion control technologies such as LNB and OFA can achieve control efficiencies of about 25 to 30 percent, the result is total control efficiency from an uncontrolled baseline of about 50 percent, which is in the mid-range of SNCR control efficiencies. SCR is a post-combustion gas treatment technique that uses either ammonia or urea in the presence of a metal-based catalyst to selectively reduce NOX to molecular nitrogen, water, and oxygen. The catalyst lowers the temperature required for the chemical reaction between NOX and the reducing agent. Technical factors that impact the effectiveness of this technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur content of the fuel, design of the ammonia injection system, and the potential for catalyst poisoning. SCR has been installed on numerous coal-fired boilers of varying sizes, and is considered technically feasible. We note that SCRs are classified as a low dust SCR (LDSCR) or high dust SCR (HDSCR). As explained in the TSD, the SCR system considered in this analysis is the HDSCR. Existing vendor literature and technical studies indicate that SCR systems are capable of achieving 42 78 FR 46175 (codified at 40 CFR 52.145(e)(2)(i)). 43 See 78 FR 75722, 78 FR 46151, and ‘‘TEP Sundt Unit I4 BART Eligibility Memo’’ (November 21, 2012). 44 40 CFR part 51, appendix Y, section III.A. 45 77 FR 46152–53. 46 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Report on Identification of Sources Subject to BART, UNC, July 20, 2012, Table 4. 47 For an expanded discussion of our approach to visibility modeling, please refer to Section III (General Approach to the Five-Factor BART analysis) of the Sundt4 TSD. This approach was used in both determining whether Sundt 4 was subject to BART, as well as in evaluating the visibility factor in the BART analysis. 48 See ‘‘Emissions Control: Cost-Effective Layered Technology for Ultra-Low NOx Control’’ (2007), ‘‘What’s New in SCRs’’ (2006), and ‘‘Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers’’ (2005). 49 See spreadsheet ‘‘CAMD Wall-fired Coal EGUs.xlsx’’ in the docket. 50 See spreadsheet ‘‘Sundt4 2001–12 Emission Calcs 2014–01–24.xlsx’’ in the docket. 51 As noted by TEP in its May 10, 2013 letter, although the calculated capacity factor is different, the annual emissions in tons per year removed do not change significantly, as the change in capacity factor is largely offset by the change in maximum unit gross rating. 1. Proposed Eligible and Subject to BART EPA is proposing to find that Sundt Unit 4 is eligible for and subject to BART. In our final rulemaking on the Arizona RH SIP dated July 30, 2013, we disapproved ADEQ’s finding that Sundt Unit 4 was not eligible for BART.42 In particular, we found that, although this unit was ‘‘reconstructed’’ in 1987, it remains BART-eligible because it did not undergo prevention of significant deterioration (PSD) review at the time of reconstruction.43 For this reason, we propose to find Sundt Unit 4 is eligible for a BART analysis of the three hazecausing pollutants: NOX, SO2 and PM10. Under the RHR and the BART Guidelines, any BART-eligible source that either ‘‘causes’’ or ‘‘contributes’’ to visibility impairment at any Class I area is subject to BART.44 EPA previously approved ADEQ’s decision to set 0.5 dv as the threshold for determining whether a source contributes to visibility impairment at a given Class I area.45 In order to determine whether Sundt Unit 4 is subject to BART, EPA’s contractor UNC evaluated whether Unit 4 has an impact of 0.5 dv or more at any Class I area. UNC’s visibility modeling showed that two Class I areas experienced a 98th percentile impact greater than 0.5 dv due to emissions from Sundt Unit 4.46 In particular, the 98th percentile impact across the three years modeled was 2.798 dv at Saguaro and 0.839 dv at Galiuro.47 These results indicate that Sundt Unit 4 causes visibility impairment at Saguaro and contributes to impairment at Galiuro. Therefore, EPA proposes to find that Sundt Unit 4 is subject to BART. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2. Proposed BART Analysis and Determination for NOX VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 b. BART Analysis for NOX Costs of Compliance: In evaluating the costs of compliance for SNCR and SCR, we calculated the control costs ($) and emission reductions (tons/year of pollutant) for each control technology, and developed average costeffectiveness ($/ton) values. Estimated NOX emission reductions are summarized in Table 7 and costeffectiveness numbers are summarized in Table 8 for each option. A more detailed version of emission calculations are in our docket 50 and in our contractor’s report. The heat duty and capacity factor used in the emission calculations below differ from the values used in the calculations originally prepared by our contractor, due to the unit’s lower capacity when burning coal (130 MW) rather than natural gas (173 MW). The heat duty (MMBtu/hr) and capacity factor (0.49) reflect the coal-burning heat duty, rather than the natural gas-burning heat duty.51 E:\FR\FM\18FEP2.SGM 18FEP2 9328 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 7—SUNDT 4: NOX CONTROL OPTION EMISSION ESTIMATES Control efficiency Emission factor Heat duty Capacity factor % lb/MMBtu MMBtu/hr % NOX emission rate Control option Baseline (LNB+OFA) ............................... SNCR+LNB+OFA .................................... SCR+LNB+OFA ....................................... .................... 30 89 Our consideration of the cost of compliance focuses primarily on the cost-effectiveness of each control option as measured in average cost per ton and incremental cost per ton of each control option as shown in Table 8. SCR is the most stringent option with the highest average cost-effectiveness of $5,176/ton, and incremental cost-effectiveness over SNCR of $6,174/ton. Detailed cost calculations can be found in our docket.52 While we have relied primarily upon the cost calculations prepared by our contractor, we have 0.445 0.312 0.050 1,371 1,371 1,371 lb/hr NOX emission reduction tpy tpy 0.49 0.49 0.49 incorporated certain elements of TEP’s analysis 53 into our cost calculations. The most significant revisions to cost estimates include the following: • We have changed the unit size from 173 MW to 130 MW to reflect the gross capacity of using coal. Although this has the net effect of decreasing certain costs, particularly several operation and maintenance (O&M) costs, the revised capital cost estimates increased for SCR (from $38 million to $45 million) and SNCR (from $2.8 million to $3.1 million). 610 427 69 1,310 917 147 393 1,162 • We have used a retrofit difficulty value of 1.5 (increased from 1.0) in cost estimates due to certain difficulties associated with retrofit installation of SCR. These difficulties are the result of site congestion and the configuration of the existing boiler structure and coal handling system as noted by TEP. • We have included the cost of air preheater modifications that TEP stated are necessary in order to accommodate SCR due to site congestion and coal handling configuration. TABLE 8—SUNDT 4: NOX CONTROL OPTION COST-EFFECTIVENESS Capital cost mstockstill on DSK4VPTVN1PROD with PROPOSALS2 SNCR ....................................................... SCR .......................................................... Annualized capital cost Annual operating cost Total annual cost Emission reduction ($) Control option ($) ($) ($/yr) (tpy) $3,079,089 45,167,561 $290,644 4,263,498 $975,124 1,753,975 $1,265,768 6,017,474 393 1,162 Cost-effectiveness ($/ton) Ave $3,222 5,176 Incremental $6,174 Pollution Control Equipment in Use at the Source: The presence of existing pollution control technology at Sundt Unit 4 is reflected in the consideration of available control technologies and in the development of baseline emission rates for use in cost calculations and visibility modeling. In the case of NOX, current pollution controls are reflected in our selection of 2011 as the baseline period, which includes the use of LNB and OFA. Energy and Non-Air Quality Environmental Impacts: Regarding potential energy impacts of the BART control options, we note that SCR incurs a draft loss that will result in certain load loss, and that other emissions controls may also have modest energy impacts. The costs for direct energy impacts, i.e., power consumption from the control equipment and additional draft system fans from each control technology, are included in the cost analyses. Indirect energy impacts, such as the energy to produce raw materials, are not considered, which is consistent with the BART Guidelines. Ammonia adsorption (resulting from ammonia injection from SCR or SNCR) to fly ash is generally not desirable due to odor but does not impact the integrity of the use of fly ash in concrete. The ability to sell fly ash is unlikely to be affected by the installation of SNCR or SCR technologies. Finally, SNCR and SCR may involve potential safety hazards associated with the transportation and handling of anhydrous ammonia. However, since the handling of anhydrous ammonia will involve the development of a risk management plan (RMP), we consider the associated safety issues to be manageable as long as established safety procedures are followed. As a result, we do not consider these impacts sufficient to warrant the elimination of either of the available control technologies. Remaining Useful Life of the Source: We are considering the ‘‘remaining useful life’’ of Sundt Unit 4 as one element of the overall cost analysis as allowed by the BART Guidelines.54 Since there is not state- or federallyenforceable shut-down date for this unit, we have used a 20-year amortization period per the EPA Cost Control Manual as the remaining useful life for the facility.55 Degree of Visibility Improvement: The visibility improvement due to NOX controls is modest. SNCR was modeled at a 30 percent NOX emission reduction. As shown in Table 9, this yields a maximum visibility improvement of just over 0.2 dv at Saguaro. Galiuro improves about half as much, and other areas much less. The cumulative improvement across all impacted Class I areas is 0.5 dv. SCR was modeled at 89 percent NOX reduction to achieve 0.05 lb/MMBtu. SCR provides a maximum improvement of 0.8 dv, which occurs at Saguaro. Galiuro again improves about half as much, and the cumulative improvement across all Class I areas is 1.6 dv. This visibility improvement is substantially greater for SCR than for SNCR. 52 See spreadsheet ‘‘Sundt4 Control Costs 2014– 01–26.xlsx’’ in the docket. 53 Letter dated May 10, 2013. 54 40 CFR Part 51, Appendix Y, section IV.D.4.k. 55 We note that the 20 year amortization period is primarily used in NOX control cost calculations, such as for SCR. In order to promote consistency in the analysis, we have used the 20 year period in the cost calculations for other control options, such as for SO2 control, for which the Control Cost Manual includes examples that use an amortization period of 15 years. VerDate Mar<15>2010 20:22 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9329 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 9—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Distance (km) Class I area Visibility improvement SNCR (ctrl04) Base case Chiricahua NM ........................................................................................................... Chiricahua WA ........................................................................................................... Galiuro WA ................................................................................................................ Gila WA ...................................................................................................................... Mazatzal WA .............................................................................................................. Mount Baldy WA ........................................................................................................ Pine Mountain WA ..................................................................................................... Saguaro NP ............................................................................................................... Sierra Ancha WA ....................................................................................................... Superstition WA ......................................................................................................... Cumulative (sum) ....................................................................................................... Maximum ................................................................................................................... # CIAs >= 0.5 dv ....................................................................................................... Million $/dv (cumul. dv) .............................................................................................. Million $/dv (max. dv) ................................................................................................ c. Proposed BART Determination for NOX EPA proposes to find that BART for NOX is an emission limit of 0.36 lb/ MMBtu on a 30-day BOD rolling basis that is achievable by SNCR with LNB and OFA. The primary factors supporting this proposed finding are the average cost-effectiveness and anticipated visibility benefits of controls. In particular, while SCR is anticipated to achieve the greatest degree of visibility improvement, it is also significantly more expensive than SNCR, with an average costeffectiveness of $5176/ton. We do not consider this average cost to be warranted by the projected visibility benefit of SCR for this facility. Table 10 provides a summary of our five-factor BART analysis. In proposing an emission limit of 0.36 lb/MMBtu, we have considered the annual average design value for SNCR of 0.31 lb/MMBtu as well as the need to 144 141 64 232 203 232 247 17 178 137 .................... .................... .................... .................... .................... account for emissions associated with startup and shutdown events. To account for this variability, we have examined the difference between the highest 30-day rolling NOX value and the highest annual average NOX value observed over the baseline period, which is approximately 17 percent.56 We have applied this variability to the annual average design value to develop a 30-day BOD rolling emission limit, which we consider to provide sufficient margin for a limit that will apply at all times. We propose to require compliance with this requirement within three years of the effective date of the final rule. A 2006 Institute of Clean Air Companies (ICAC) study indicated that the installation time for a typical SNCR retrofit, from bid to startup, is 10 to 13 months.57 However, because we are also requiring the installation of additional SO2 controls, we consider a three year period for compliance with both BART 0.43 0.51 1.10 0.17 0.19 0.15 0.15 3.40 0.19 0.32 6.6 3.40 3 ...................... ...................... SCR (ctrl08) 0.03 0.05 0.12 0.02 0.02 0.01 0.02 0.23 0.01 0.01 0.5 0.23 0 $2.4 $5.5 0.12 0.15 0.34 0.04 0.04 0.03 0.03 0.78 0.04 0.05 1.6 0.78 1 $3.7 $7.7 determinations to be appropriate. We are seeking comment on whether this compliance date is reasonable and consistent with the requirement of the Clean Air Act that BART be installed ‘‘as expeditiously as practicable but in no event later than five years after [promulgation of the applicable FIP].’’ 58 If we receive information during the comment period that establishes that a different compliance time frame is appropriate, we may finalize a different compliance date. Finally, we are proposing regulatory text that includes monitoring, reporting, and recordkeeping requirements to ensure that the emission limit and compliance deadline are enforceable. As part of the proposed monitoring requirements, we are including a requirement to monitor rates of ammonia injection in order to ensure proper operation of the SNCR in a manner that minimizes ammonia emissions. TABLE 10—SUNDT 4: SUMMARY OF BART ANALYSIS FOR NOX LNB+OFA (baseline) Sundt unit 4 (130 MW) SNCR+LNB 0.445 1310 .................... .................... 0.312 ................ 917 ................... 393 ................... 30% .................. 0.050 147 1,162 89% .................... .................... .................... $3,079,089 ....... $290,644 .......... $975,124 .......... $45,167,561 $4,263,498 $1,753,975 SCR+LNB Emissions mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Emission Factor (lb/MMBtu) ...................................................................................................... Emission Rate (tpy) ................................................................................................................... Emission Reduction (tpy) ........................................................................................................... Control Effectiveness (%) .......................................................................................................... Costs of Compliance Capital Cost ($) .......................................................................................................................... Annualized Capital Cost ($) ....................................................................................................... Annual O&M ($) ......................................................................................................................... 56 See spreadsheet ‘‘Sundt4 2001–12 Emission Calcs 2014–01–24.xlsx’’ in the docket. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 57 See ‘‘Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources’’, Institute of Clean Air Companies, December 4, 2006. PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 58 Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4). E:\FR\FM\18FEP2.SGM 18FEP2 9330 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 10—SUNDT 4: SUMMARY OF BART ANALYSIS FOR NOX—Continued Sundt unit 4 (130 MW) LNB+OFA (baseline) SNCR+LNB Total Annual Cost ($) ................................................................................................................ Ave Cost-Effectiveness ($/ton) .................................................................................................. Incremental Cost-Effectiveness ($/ton) ..................................................................................... .................... .................... .................... $1,265,768 ....... $3,222 .............. ........................... SCR+LNB $6,017,474 $5,176 $6,174 Pollution Control Equipment in Use Low-NOX Burners and Over Fire Air Energy and Non-Air Quality Environmental Impacts Energy impacts have been reflected in annual O&M costs in the costs of compliance. SCR and SNCR may create potential safety and environmental hazards from the transportation and handling of anhydrous ammonia. We consider these impacts manageable with the development of an RMP and additional safety procedures, and do not consider them sufficient enough to warrant eliminating either of these available control technologies. Remaining Useful Life Control technology amortization period ..................................................................................... .................... 20 years ........... 20 years .................... .................... .................... .................... .................... 0.23 .................. $5.5 .................. 0 ....................... 0.5 .................... $2.4 .................. 0.78 $7.7 1 1.6 $3.7 Visibility Improvement Single largest Class I area improvement (dv) ........................................................................... Single Class I area cost-effectiveness (million $/dv) ................................................................ Class I areas with ≥ 0.50 dv improvement ................................................................................ Cumulative visibility improvement (dv) ...................................................................................... Cumulative cost-effectiveness (million $/dv) ............................................................................. 4. Proposed BART Analysis and Determination for SO2 For our SO2 BART analysis, we identified all available control technologies, eliminated options that are not technically feasible, and evaluated the control effectiveness of the remaining control options. We then evaluated each control in terms of a five-factor BART analysis and proposed a determination for BART. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 a. Control Technology Availability, Technical Feasibility, and Effectiveness EPA identified three available and technically feasible technologies to control SO2 emissions from Sundt Unit 4. These technologies are lime or limestone-based wet flue gas desulfurization (wet FGD), lime spray dry absorber (SDA or dry FGD), and dry sorbent injection (DSI). While each of these control options has certain design concerns and constraints associated with their implementation, all three options are considered technically feasible. Lime or limestone-based wet FGD: Wet scrubbing systems mix an alkaline reagent, such as hydrated lime or limestone, with water to generate scrubbing slurry that is used to remove SO2 from the flue gas. The alkaline slurry is sprayed countercurrent to the flue gas, such as in a spray tower, or the flue gas may be bubbled through the alkaline slurry as in a jet bubbling VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 reactor. As the alkaline slurry contacts the exhaust stream, it reacts with the SO2 in the flue gas. Design variations may include changes to increase the alkalinity of the scrubber slurry, increase slurry/SO2 contact, and minimize scaling and equipment problems. Insoluble calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts are formed in the chemical reaction that occurs in the scrubber, and exit as part of the scrubber slurry. The salts are eventually removed and handled as a solid waste byproduct. The waste byproduct is mainly CaSO3, which is difficult to dewater. Solid waste byproducts from wet lime scrubbing are typically managed in dewatering ponds and landfills. Design concerns associated with wet FGD involve the substantial water usage requirements needed to generate the alkaline reagent slurry as well as the substantial amount of wastewater and solid waste discharge associated with the spent byproduct. A wet FGD control system must be located after the fabric filter baghouse because the moist plume resulting from the wet scrubber system would create baghouse plugging issues if the control is placed ahead of the baghouse. In addition, a substantial footprint is required for the management of these waste products as well as for the absorber tower and associated process equipment such as the slurry preparation, mixing, associated tanks, PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 and dewatering activities. While these design concerns do present some challenges, they do not warrant elimination of this option as technically infeasible.59 Our contractor has estimated that newly constructed wet FGD systems could achieve design emission rates (annual average basis) of 0.06 lb/ MMBtu. Relative to baseline SO2 emission rates, this corresponds to a control efficiency of 92 percent. We recognize that FGD systems are designed to achieve more stringent emission rates, and have demonstrated an ability to achieve control efficiencies up to 98 percent. Our contractor’s report notes that the lower control efficiency cited here is regarded as a conservative estimate. While this is not the most stringent level of control that the technology is capable of achieving, we consider 92 percent control efficiency to be consistent with the median values reported for wet FGD systems. Lime SDA or dry FGD: A spray dryer absorber uses a stream of either dry lime or hydrated lime (semi-dry) in a reaction tower where it reacts with SO2 in the flue gas to form calcium sulfite solids. Unlike wet FGD systems that produce a slurry by-product that is collected 59 TEP’s review does not eliminate consideration of wet FGD, but does describe several design challenges that TEP notes should be reflected in the five factor analysis. We have incorporated certain elements of TEP’s review in our analysis, as discussed in Step 4. E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules separately from the fly ash, dry FGD systems are designed to produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. As a result, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material. In instances where hydrated lime is used as a reagent, the reaction towers must be designed to provide adequate contact and residence time between the exhaust gas and the slurry to produce a relatively dry byproduct. Typical process equipment associated with a spray dryer typically includes an alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate control device and a recycle system. The recycle system collects solid reaction products and recycles them back to the spray dryer feed system to reduce alkaline sorbent use. A design concern associated with a dry FGD system is that it must be installed prior to the fabric filter baghouse in order for the reagent to be captured and recycled. As noted in our contractor’s report, the location of the existing fabric filter baghouse does not present enough space to install a new absorber between the boiler and the existing baghouse. As a result, a dry FGD at Sundt Unit 4 is assumed to include a new baghouse, which is reflected in the costs of compliance for the five-factor analysis. We consider this control option to be technically feasible. Our contractor has estimated that newly constructed dry FGD systems could achieve design emission rate (annual average basis) of 0.08 lb/ MMBtu. Relative to baseline SO2 emission rates, this corresponds to a control efficiency of 89 percent. As noted for wet FGD systems, this is a conservative estimate of what dry FGD systems can achieve, and is consistent with the median values reported for dry FGD systems. Dry Sorbent Injection: DSI involves the injection of powdered absorbent directly into the flue gas exhaust stream. These are simple systems that generally require a sorbent storage tank, feeding mechanism, transfer line and blower, and an injection device. The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber is often located downstream of the injection point to increase residence time and efficiency. Particulates generated in the reaction are controlled in the system’s particulate control device. DSI requires less capital equipment, less physical space, and less modification to existing ductwork VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 compared to a dry FGD system. However, reagent costs are much higher and, depending upon the absorbent and amount of sorbent injected, control efficiency is lower when compared to a dry FGD system. Soda ash and Trona (sodium sesquicarbonate) are potential options for reagent use. An important design consideration of DSI is the ability of the downstream particulate control device to accommodate the additional particulate loading resulting from the addition of the DSI reagent into the boiler flue gas. More effective particulate control devices allow for higher rates of sorbent injection, which in turn allow for more effective SO2 control. In a review of SO2 control options for BART eligible units, the Northeast States for Coordinated Air Use Management (NESCAUM) estimated control effectiveness for DSI in a range of 40–60 percent.60 More recently, as part of work done as part of the Integrated Planning Model (IPM), EPA has estimated control effectiveness as high as 80 percent,61 depending upon factors such as the type of sorbent, the quantity of sorbent used, and the type of particulate control device employed. Generally, the use of more effective particulate control devices allow for higher rates of sorbent injection, and therefore greater DSI effectiveness. Since Sundt Unit 4 operates with a fabric filter, we consider a control effectiveness value in the upper range appropriate, and have used 70 percent control effectiveness in our calculations. This value is above the range indicated in the NESCAUM study, but does not require the high sorbent injection rates required to achieve the upper range of control indicated in IPM documentation. A summary of the control technologies and their associated control effectiveness is presented in Table 11. TABLE 11—SUNDT 4: SO2 CONTROL OPTIONS Control effectiveness % Control option Dry Sorbent Injection ............ Dry FGD or Lime SDA ......... 60 ‘‘Assessment 70 89 of Control Technology Options for BART-Eligible Sources’’, Northeast States for Coordinated Air Use Management In Partnership with The Mid-Atlantic/Northeast Visibility Union, March 2005. 61 IPM Model—Revisions to Cost and Performance for APC Technologies, Dry Sorbent Injection Cost Development Methodology, August 2010. PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 9331 TABLE 11—SUNDT 4: SO2 CONTROL OPTIONS—Continued Control option Wet FGD (lime- or limestone-based) ..................... Control effectiveness % 92 b. BART Analysis for SO2 Costs of Compliance: Our consideration of the costs of compliance focuses primarily on the costeffectiveness of each control option, as measured in cost per ton and incremental cost per ton. The emissions estimates and cost-effectiveness for the three control options are shown in Table 12 and Table 13, respectively. Both wet and dry FGD have average costeffectiveness values over $5,000/ton, much greater than DSI, which is a control option that we consider very cost-effective at $1,857/ton. Moreover, both wet and dry FGD have very high incremental cost-effectiveness values, indicating that while they are more effective than less stringent control options, this additional degree of effectiveness comes at a substantial cost. In evaluating the costs of compliance for the control options, we have calculated the control costs ($) and emission reductions (tons/year of pollutant) for each control technology, developed average cost-effectiveness ($/ ton) values, and arrived at the emission reductions for each option as summarized Table 12. A more detailed version of emission calculations is in our docket,62 and in our contractor’s report. As noted previously in our NOX BART analysis, the heat duty and capacity factor used in these calculations differ from the values used in the calculations originally prepared by our contractor because the maximum gross capacity of Sundt Unit 4 while burning coal is about 130 MW, compared to its natural-gas nameplate capacity of 173 MW. The heat duty (MMBtu/hr) and capacity factor used in Table 12 reflect the coal-burning nameplate capacity.63 Detailed cost calculations presented in Table 13 are in the docket.64 62 See spreadsheet ‘‘Sundt4 2001–12 Emission Calcs 2014–01–24.xlsx’’ in the docket. 63 As noted by TEP and Burns and McDonnell, although the calculated capacity factor is different, the annual emissions in tons per year removed do not change significantly, as the change in capacity factor is largely offset by the change in maximum unit gross rating. 64 See spreadsheet ‘‘Sundt4 Control Costs 2014– 01–26.xlsx’’ in the docket. E:\FR\FM\18FEP2.SGM 18FEP2 9332 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 12—SUNDT 4: SO2 CONTROL OPTION EMISSION ESTIMATES SO2 emission rate Control efficiency Emission factor Heat duty (%) (lb/MMBtu) (MMBtu/hr) 0.729 0.219 0.080 0.060 1,371 1,371 1,371 1,371 Capacity factor Control option Baseline (no control) ................................ DSI ........................................................... DFGD ....................................................... WFGD ...................................................... .................... 70 89 92 (lb/hr) SO2 emission reduction (tpy) (tpy) 0.49 0.49 0.49 0.49 1,000 300 110 82 2,145 644 236 177 1,502 1,909 1,969 TABLE 13—SUNDT 4: SO2 CONTROL OPTION COST-EFFECTIVENESS Capital cost mstockstill on DSK4VPTVN1PROD with PROPOSALS2 DSI ........................................................... DFGD ....................................................... WFGD ...................................................... Annualized capital cost Annual operating cost Total annual cost Emission reduction ($) Control option ($) ($) ($/yr) (tpy) $2,482,107 2,880,841 3,227,467 $2,788,884 9,721,549 10,838,337 $3,250,000 72,470,559 80,629,663 Pollution Control Equipment in use at Source: In the case of SO2, Sundt Unit 4 does not operate with any existing control technology. This is reflected in our selection of calendar year 2011 as the baseline period, which represents uncontrolled coal-fired emissions. Energy and Non-Air Quality Environmental Impacts: For wet FGD, energy impacts include certain auxiliary power requirements that are necessary to operate the wet FGD system and to potentially compensate for pressure head loss through the scrubber. These energy impacts are reflected as auxiliary power costs in the cost of compliance estimates. Non-air quality environmental impacts include water usage requirements and the storage and disposal of wet ash. Wet FGD requires very large quantities of water to ensure proper control effectiveness. Securing such quantities of water is a significant challenge in more arid regions of the country such as Arizona, and would preclude the use of that water for potentially more beneficial uses. The on-site storage and disposal of wet ash in large retention ponds triggers significant additional regulatory requirements, as it represents a substantial water pollution threat. For dry FGD, the energy and non-air environmental impacts are similar to those for wet FGD. Operation of a dry FGD system still requires securing significant supplies of water, although to a lesser degree than wet FGD systems. In addition, dry FGD systems will result in generation of larger quantities of boiler ash, and has the potential to affect negatively the properties and quality of boiler ash. In some instances, boiler ash that is suitable to sell for beneficial purposes may no longer be marketable VerDate Mar<15>2010 20:22 Feb 14, 2014 Jkt 232001 $306,777 6,840,708 7,610,870 following installation of a dry FGD system. Energy impacts also include auxiliary power requirements for operation of the dry FGD system, and for overcoming pressure head loss through the scrubber. While we note certain potential impacts resulting from the water resource requirements associated with wet FGD as well as the additional solid waste generation associated with wet and dry FGD, we do not consider these impacts sufficient enough to warrant eliminating these control technologies. DSI could potentially have an adverse effect on the quality of the boiler fly ash, which would make it unmarketable for beneficial uses. Use of DSI also results in an ash byproduct which would require landfill disposal, thereby increasing solid waste generation rates at the plant. Energy impacts are limited to auxiliary power requirements for operation of the DSI system. We do not consider these impacts sufficient enough to warrant eliminating this control technology. Remaining Useful Life of the Source: We are considering the remaining useful life of Sundt Unit 4 as one element of the overall cost analysis as allowed by the BART Guidelines. Since we are not aware of any federally- or Stateenforceable shut down date for Sundt Unit 4, we have used a 20-year amortization period described in the EPA Cost Control Manual as the remaining useful life for the control options considered for Unit 4. We note that the remaining useful life of the source is reflected in the evaluation of cost of compliance through the use of a 20-year amortization period in control cost calculations. PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 1,502 1,909 1,969 Cost-effectiveness ($/ton) Ave $1,857 5,091 5,505 Incremental $17,007 18,795 Degree of Visibility Improvement: The visibility improvement due to SO2 controls is modest. As shown in Table 14, control via DSI, with a 70 percent SO2 emissions reduction, gives a maximum visibility improvement of 0.2 dv, which occurs at Saguaro. Three other areas improve about half as much, and the cumulative improvement is 0.8 dv. Emissions controls via dry and wet FGD were modeled at 89 percent and 92 percent SO2 emissions reduction, respectively. Both dry and wet FGD would cause a visibility disbenefit at Saguaro as indicated by the negative improvements in Table 14. The disbenefit is mainly due to the decreased stack exit temperature and exit velocity associated with these technologies, and more so for wet FGD than for dry FGD. These stack decreases result in less plume rise and increased impacts nearby. At areas farther away, the disbenefit is outweighed by the benefit of SO2 reductions from FGD. This issue is discussed further in the TSD. With FGD, the maximum benefit occurs not at Saguaro, but at Galiuro, with 0.2 dv for dry FGD and 0.1 dv for wet FGD. The corresponding cumulative improvements are 0.6 dv and 0.4 dv for dry and wet FGD, respectively, including the areas of disbenefit. All these improvements are substantially lower than those from DSI, and the visibility cost-effectiveness of each FGD is more than quadruple that of DSI. EPA finds that the improvement from DSI is substantial enough to support its selection as BART, and that it is clearly a better choice than dry FGD and wet FGD. E:\FR\FM\18FEP2.SGM 18FEP2 9333 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 14—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM SO2 CONTROLS Visibility impact Class I Area Distance (km) Chiricahua NM ................................................................................. Chiricahua Wild ................................................................................ Galiuro Wild ..................................................................................... Gila Wild ........................................................................................... Mazatzal Wild ................................................................................... Mount Baldy Wild ............................................................................. Pine Mountain Wild .......................................................................... Saguaro NP ..................................................................................... Sierra Ancha Wild ............................................................................ Superstition Wild .............................................................................. Cumulative (sum) ............................................................................. Maximum .......................................................................................... # CIAs >= 0.5 dv .............................................................................. Million $/dv (cumul. dv) .................................................................... Million $/dv (max. dv) ....................................................................... 144 141 64 232 203 232 247 17 178 137 .................... .................... .................... .................... .................... Base case DSI 70% (ctrl14) 0.43 0.51 1.10 0.17 0.19 0.15 0.15 3.40 0.19 0.32 6.6 3.40 3 ............................ ............................ difference between the highest 30-day rolling SO2 value and the highest annual average SO2 value observed over the baseline period, which is approximately 9 percent.65 We have applied this variability to the annual average design value to develop a 30-day BOD rolling emission limit, which we consider a sufficient margin for a limit that will apply at all times. Please refer to Table 15 that provides a summary of our fivefactor BART analysis. We propose to require compliance with this requirement within three years of the effective date of the final rule. However, we are seeking comment on c. BART Determination for SO2 EPA proposes an emission limit of 0.23 lb/MMBtu on a 30-day (BOD) rolling basis as BART to control SO2 from Sundt Unit 4. This emission limit, equivalent to using DSI, is considered very cost-effective at $1,857/ton. In evaluating the appropriate emission limit for DSI, we have considered the annual average design value for DSI of 0.21 lb/MMBtu as well as the need to account for emissions associated with startup and shutdown events. To determine how to account for this variability, we have examined the Visibility improvement Dry FGD (ctrl02) 0.05 0.10 0.10 0.04 0.07 0.05 0.05 0.20 0.06 0.09 0.8 0.20 0 $3.5 $14 Wet FGD (ctrl03) 0.07 0.10 0.16 0.05 0.08 0.05 0.06 ¥0.16 0.08 0.10 0.6 0.16 0 $16.4 $60 0.06 0.11 0.09 0.05 0.09 0.06 0.06 ¥0.27 0.08 0.10 0.4 0.11 0 $25.1 $97 whether this compliance date is reasonable and consistent with the requirement of the Clean Air Act that BART be installed ‘‘as expeditiously as practicable but in no event later than five years after [promulgation of the applicable FIP].’’ 66 If we receive information during the comment period that establishes that a different compliance time frame is appropriate, we may finalize a different compliance date. We are also proposing regulatory text that includes monitoring, reporting, and recordkeeping requirements associated with this emission limit. TABLE 15—SUNDT 4: SUMMARY OF BART ANALYSIS FOR SO2 Sundt Unit 4 (130 MW) Baseline DSI Dry FGD Wet FGD Emission Factor (lb/MMBtu) ....................................................................... Emission Rate (tpy) .................................................................................... Emission Reduction (tpy) ............................................................................ Control Effectiveness .................................................................................. 0.729 2145 .................... .................... 0.219 ................ 644 ................... 1,502 ................ 70% .................. 0.08 .................. 236 ................... 1,909 ................ 89% .................. 0.06 177 1,969 92% $3,250,000 ....... $306,777 .......... $2,482,107 ....... $2,788,884 ....... $1,857 .............. ........................... $72,470,559 ..... $6,840,708 ....... $2,880,841 ....... $9,721,549 ....... $5,091 .............. $23,081 ............ $80,629,663 $7,610,870 $3,227,467 $10,838,337 $5,505 $18,795 20 years ........... 20 years Cost of Compliance Capital Cost ($) ........................................................................................... Annualized Capital Cost ($) ........................................................................ Annual O&M ($) .......................................................................................... Total Annual Cost ($) .................................................................................. Ave CE ($/ton) ............................................................................................ Incremental CE ($/ton) ................................................................................ .................... .................... .................... .................... .................... .................... Pollution Control Equipment in Use at Source There is no existing control technology for SO2 Energy and Non-Air Quality Environmental Impacts mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Energy impacts are reflected in annual O&M costs in the costs of compliance. Wet ash from wet and dry FGD represents a substantial water pollution threat. Water resources for wet and dry FGD may preclude more beneficial uses of water. Remaining Useful Life Control technology amortization period ...................................................... 65 See spreadsheet ‘‘Sundt4 2001–12 Emission Calcs 2014–01–24.xlsx’’ in the docket. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 .................... 20 years ........... 66 Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4). PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9334 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 15—SUNDT 4: SUMMARY OF BART ANALYSIS FOR SO2—Continued Sundt Unit 4 (130 MW) Baseline DSI Dry FGD 0.20 .................. $14.3 ................ 0 ....................... 0.8 .................... $3.5 .................. 0.16 .................. $60.4 ................ 0 ....................... 0.6 .................... $16.4 ................ Wet FGD Visibility Improvement Single largest Class I area improvement (dv) ............................................ Single Class I area cost-effectiveness (million $/dv) .................................. Class I areas with ≥ 0.50 dv improvement ................................................. Cumulative visibility improvement (dv) ....................................................... Cumulative cost-effectiveness (million $/dv) .............................................. 3. Proposed BART Analysis and Determination for PM10 a. Control Technology Availability, Technical Feasibility, and Effectiveness Sundt Unit 4 currently operates with a fabric filter baghouse for particulate control, which is considered the most stringent control device for particulate matter. These devices operate on the same principle as a vacuum cleaner. Air carrying dust particles is forced through a cloth bag that is designed and manufactured to trap particles greater than a certain specified diameter. As the air passes through the fabric, the dust accumulates on the cloth and is removed from the air stream. The accumulated dust is periodically removed from the cloth by shaking or by reversing the air flow. The layer of dust, known as dust cake, trapped on the surface of the fabric has the potential to result in high efficiency rates for particles ranging in size from submicron to several hundred microns in diameter. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 b. BART Analysis for PM10 The BART Guidelines provide that, where a source has controls already in place that are the most stringent controls available, it is not necessary to complete comprehensively a full fivefactor BART analysis, as long the most stringent controls available are made federally enforceable. Therefore, instead of completing the remaining steps of a five-factor BART analysis, we have evaluated the appropriate level of emissions to ensure that the fabric filter achieves an appropriate degree of control. c. Proposed BART Determination for PM10 EPA is proposing a filterable PM10 BART emission limit of 0.03 lb/MMBtu based on the use of the existing fabric filter baghouse currently in operation, which is the most stringent control for 67 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40 CFR 60.42Da(a), 60.50Da(b)(1)). 68 See Memorandum from Jeffrey Cole (RTI International) to Bill Maxwell (EPA) regarding ‘‘National Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable Control VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 .................... .................... .................... .................... .................... particulate matter. We note that Mercury and Air Toxics (MATS) Rule establishes an emission standard of 0.03 lb/MMBtu filterable PM (as a surrogate for toxic non-mercury metals) as representing Maximum Achievable Control Technology (MACT) for coalfired EGUs.67 This standard derives from the average emission limitation achieved by the best performing 12 percent of existing coal-fired EGUs, as based upon test data used in developing the MATS Rule.68 The BART Guidelines provide that, ‘‘unless there are new technologies subsequent to the MACT standards which would lead to costeffective increases in the level of control, you may rely on the MACT standards for purposes of BART.’’ 69 Therefore, we propose to find that 0.03 lb/MMBtu filterable PM10 is an appropriate limit for BART at Sundt Unit 4. 4. Better Than BART Alternative We are proposing a switch to natural gas on Sundt Unit 4 as a better-thanBART alternative to the emissions controls previously proposed in this section for a coal-fired unit. Unit 4 was originally constructed as a natural gasfired boiler, and has used natural gas as a primary fuel for significant periods of time since 2009. While a change in fuel supply to natural gas instead of coal is an inherently less polluting option, the BART Guidelines do not require the consideration of fuel supply changes as a control option.70 As a result, the option of burning only natural gas is not considered in our BART analysis. However, TEP has submitted to EPA an alternative to BART based on the elimination of coal as a fuel source for Sundt Unit 4 by December 31, 2017. As part of this submittal, TEP compared the potential emission reductions and visibility benefit between a natural gas Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating Units for Final Rule’’ (December 16, 2011). 69 40 CFR Part 51, Appendix Y, Section IV.C. PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 0.11 $96.8 0 0.4 $25.1 fuel change and certain combinations of NOX and SO2 controls.71 EPA has evaluated this alternative proposal pursuant to the ‘‘better-thanBART’’ provisions of the RHR. In particular, the RHR allows for implementation of ‘‘an emissions trading program or other alternative measure’’ in lieu of BART if the alternative measure achieves greater reasonable progress than would be achieved through the installation and operation of BART.72 The rule further states that ‘‘[i]f the distribution of emissions is not substantially different than under BART, and the alternative measure results in greater emissions reductions, than the alternative measures may be deemed to achieve greater reasonable progress’’.73 Because the emissions reductions under EPA’s BART proposal for Sundt Unit 4 and the reductions from TEP’s proposed alternative would occur at the same facility, the distribution of emissions under BART and the alternative are not substantially different. Therefore, if the alternative emission control strategy results in greater emissions reductions than our BART proposal, EPA may deem the alternative emission control strategy to achieve greater reasonable progress. A comparison of annual emission estimates between the BART determination and alternative to BART is summarized in Table 16. BART determination annual emissions are based upon the annual average emission factors and annual capacity factor used in our BART analysis, consistent with coal usage. For the alternative to BART, annual emissions are based on a combination of historical natural gas usage data as indicated in TEP’s submittal, as well as standard emission factors for natural gas combustion. A more detailed discussion of emission estimates from these two scenarios is included in our TSD. 70 40 CFR Part 51, Appendix Y, Section IV.D.1.5, ‘‘STEP 1: How do I identify all available retrofit emission control techniques?’’ 71 Letter dated November 1, 2013. 72 40 CFR 51.308(e)(2). 73 40 CFR 51.308(e)(3). E:\FR\FM\18FEP2.SGM 18FEP2 9335 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 16—SUNDT 4: COMPARISON OF BART DETERMINATION AND ALTERNATIVE TO BART Parameters Units BART determination Natural gas fuel switch Heat Duty ............................... Capacity Factor ...................... NOX ........................................ MMBtu/hr ............................... ................................................ Ctrl Tech ................................ lb/MMBtu 1 .............................. tpy .......................................... Ctrl Tech ................................ lb/MMBtu 1 .............................. tpy .......................................... Ctrl Tech ................................ lb/MMBtu1 .............................. tpy .......................................... 1,371 ...................................... 0.49 ........................................ SNCR+LNB+OFA .................. 0.31 ........................................ 917 ......................................... Fabric Filter ............................ 0.03 ........................................ 88 ........................................... Dry Sorbent Injection ............. 0.22 ........................................ 644 ......................................... 1,828. 0.37. LNB+OFA. 0.22. 652 ......................................... None. 0.01. 30 ........................................... None. 0.00064. 1.9 .......................................... Particulate Matter ................... SO2 ......................................... 1 Annual Difference 265 59 642 average emission factors. As seen in Table 16, a change to natural gas usage achieves greater emission reductions than each of the individual BART determinations for NOX, SO2, and particulate matter, as well as in the aggregate. Although visibility modeling is not required to support a better-than-BART determination in this instance, EPA conducted modeling to verify the visibility benefits of the proposed alternative, as compared with EPA’s BART determination. This modeling is described in the TSD and the results are summarized in Table 17. TABLE 17—SUNDT 4: VISIBILITY IMPACT AND IMPROVEMENT FROM COMBINED SO2 AND NOX BART, AND FROM BETTERTHAN-BART ALTERNATIVE Distance (km) Class I Area Visibility impact Base case mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Chiricahua NM ................................................................................................................. Chiricahua WA ................................................................................................................. Galiuro WA ...................................................................................................................... Gila WA ............................................................................................................................ Mazatzal WA .................................................................................................................... Mount Baldy WA .............................................................................................................. Pine Mountain WA ........................................................................................................... Saguaro NP ..................................................................................................................... Sierra Ancha WA ............................................................................................................. Superstition WA ............................................................................................................... Cumulative (sum) ............................................................................................................. Maximum ......................................................................................................................... # CIAs >= 0.5 dv ............................................................................................................. Million $/dv (cumul. dv) .................................................................................................... Million $/dv (max. dv) ...................................................................................................... Since Sundt is only 17 km from the eastern unit of Saguaro, its emitted NOX may not be fully converted to NO2 by the time it reaches there, as is assumed in the CALPUFF model. It thus may not be fully available to form visibilitydegrading particulate nitrate. EPA explored this issue in CALPUFF sensitivity simulations described in the TSD. For EPA’s proposed BART of SNCR plus DSI, the visibility improvement remains above 0.3 dv even when unrealistically low 10 percent NO-to-NO2 conversion is assumed (i.e., no additional conversion of NO to NO2 once the plume leaves the stack). The improvement from switching to natural gas remains above 0.7 dv at Saguaro. These results show that the FIP’s proposed BART determination remains VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 reasonable despite any concern over the NO conversion rate; the visibility improvement from BART remains substantial. The finding that natural gas provides better visibility improvement than the proposed BART determination also remains sound regardless of the NO conversion assumed. Based on this information, we consider a natural gas fuel switch to result in greater emission reductions and achieve greater reasonable progress than the proposed BART determinations. Under this scenario, we are proposing a NOX emission limit of 0.25 lb/MMBtu based on a 30-day BOD rolling average. As discussed previously in the NOX BART determination, this represents about a 17 percent increase from the annual average emission rate of PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 144 141 64 232 203 232 247 17 178 137 0.43 0.51 1.10 0.17 0.19 0.15 0.15 3.40 0.19 0.32 6.6 3.40 3 Visibility improvement SNCR DSI 70% (ctrl15) 0.09 0.16 0.24 0.06 0.08 0.06 0.06 0.49 0.08 0.11 1.4 0.49 0 $2.8 $8.3 Natural gas (ctrl13) 0.19 0.25 0.47 0.10 0.12 0.09 0.09 1.06 0.12 0.19 2.7 1.06 1 0.22 lb/MMBtu, which we consider to provide sufficient margin for a limit that will apply at all times, including periods of startup and shutdown. In addition, we are proposing particulate matter and SO2 emission limits consistent with natural gas use, as well as monitoring, reporting, and recordkeeping requirements. B. Chemical Lime Nelson Plant Kilns 1 and 2 Summary: EPA is proposing to find that Chemical Lime Nelson is subject to BART. EPA is proposing BART emission limits for NOX, SO2 and PM10 for Kilns 1 and 2 at the Nelson Plant as listed in Table 18 and described in this section. E:\FR\FM\18FEP2.SGM 18FEP2 9336 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 18—NELSON LIME PLANT: SUMMARY OF PROPOSED BART DETERMINATIONS Source Pollutant Kiln 1 ................................. NOX .................................. SO2 ................................... PM10 ................................. NOX .................................. SO2 ................................... PM10 ................................. Kiln 2 ................................. Control technology* (for reference only) Emission Limit (lb/ton feed) 3.80 9.32 0.12 2.61 9.73 0.12 Selective Non-Catalytic Reduction (SNCR). Lower sulfur fuel. Fabric filter baghouse (existing). Selective Non-Catalytic Reduction (SNCR). Lower sulfur fuel. Fabric filter baghouse (existing). * The facility is not required to install the listed technology to meet the BART limit. Affected Class I Areas: Nine Class I areas are within 300 km of the Nelson Lime Plant. Their nearest borders range from 24 km to 289 km away, with the Grand Canyon the closest and other areas more than 100 km away. The highest baseline visibility impact from the Nelson Plant is 1.79 dv at Grand Canyon NP followed by 0.31 at Sycamore Canyon WA and 0.28 at Zion NP. The cumulative sum of visibility impacts over all the Class I areas is 3.34 dv. Facility Overview: The Nelson Plant processes limestone and manufactures lime near Peach Springs in Yavapai County, Arizona. The limestone processing plant consists of a quarry mining operation, a limestone crushing and screening operation, a limestone kiln feed system, a solid fuel handling system, two rotary lime kilns, front and back lime handling systems, a lime hydrator, diesel electric generators, fuel storage tanks, and other support operations and equipment. The lime manufacturing equipment consists of two lime rotary kilns (Kiln 1 and Kiln 2) and auxiliary equipment necessary for receiving crushed limestone, processing it through the lime kilns, and processing the lime kiln product. The lime kilns are used to convert crushed limestone (CaCO3) into quicklime (CaO). We primarily relied on four sources of information for our proposed BART analyses and determinations. An initial BART analysis performed by our contractor 74 is available in the docket in the form of a final contractor’s report and associated modeling spreadsheets. We also incorporated elements of a fivefactor BART analysis 75 provided by Lhoist North America (LNA) of Arizona, owner of the Nelson Plant, that includes control cost estimates and visibility modeling. Another key document in our analysis is the Nelson Lime Plant’s Title V Operating Permit.76 Baseline Emissions Calculations: LNA’s approach to establishing baseline emissions was to first establish baseline emission factors in lb/ton lime based on CEMS testing performed from March to June 2013. Annual average baseline emissions were calculated by multiplying these lb/ton emission factors by the highest annual lime production rate observed over a period from 2001 to 2012. Maximum daily emissions were calculated by multiplying lb/ton emission factors by the maximum daily lime production rate observed during the March to June 2013 testing period. As explained in further detail in our TSD, we consider LNA’s general approach appropriate, but also note that it represents a conservatively high estimate of baseline emissions, and potentially overstates the anticipated emission reductions and visibility benefit from the evaluated control options. Nonetheless, given the lack of measured annual emissions data, we concur with LNA’s use of a conservatively high baseline emissions estimate and we have incorporated this estimate into our analysis. The baseline daily and annual emission rates and associated production levels are shown in Table 19. TABLE 19—NELSON LIME PLANT: SUMMARY OF MAXIMUM DAILY AND ANNUAL BASELINE EMISSIONS FOR NOX AND SO2 Lime production Kiln Max daily 2 Max annual (tpd) Kiln 1 ........ Kiln 2 ........ 1 Maximum 2 Maximum NOX 866 1,246 Year Emission factor 1 (tpy) (lb/ton lime) 3 258,508 2010 2012 4 378,296 7.59 5.21 SO2 Emission factor 1 Maximum emissions (lb/day) (tpy) 6,573 6,492 (lb/ton lime) 981 985 12.15 12.69 Maximum emissions (lb/day) 10,522 15,812 (tpy) 1,570 2,400 emission factors observed during March, May and June 2013 CEMS testing. daily rates occurring during the March 2013 CEMS testing. 3 2010. 4 2012. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 1. Proposed Subject to BART As part of our July 30, 2013 final rulemaking on the Arizona RH SIP, we approved ADEQ’s finding that Chemical 74 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 7: Five-Factor BART Analysis for Chemical Lime Company Nelson, TEP Sundt (Irvington), and Catalyst Paper (Snowflake) Plants, Contract No. EP–D–07–102, Work Assignment 5–12; Prepared for EPA Region 9 by University of North Carolina at Chapel Hill, ICF VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Lime Nelson Plant (Nelson Lime Plant) Kilns 1 and 2 were BART-eligible, but disapproved ADEQ’s determination that the Nelson Lime Plant was not subject to BART.77 In light of this disapproval, we have conducted our own evaluation of whether Nelson Lime Plant is subject to BART, relying primarily on emissions International, and Andover Technology Partners; October 9, 2012. 75 BART Five Factor Analysis, Lhoist North America Nelson Lime Plant; Prepared by Trinity Consultants in Conjunction with Lhoist North America of Arizona, Inc.; Project 131701.0061; August 2013. (Public version dated September 27, 2013). 76 Title V Operating Permit and Technical Support Document for the Nelson Lime Plant, Permit # 42782, Issued August 8, 2011 by the Arizona Department of Environmental Quality. 77 78 FR 46175 (codified at 40 CFR 52.145(g)(1)(i)). PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules data and modeling results provided by the facility’s owner, LNA.78 As explained in the TSD, the baseline emissions estimates and the corresponding modeling results provided by LNA are conservative (i.e., tending to overestimate rather than underestimate the impacts, in this case). Nonetheless, we consider these results to be appropriate for purposes of a subject-to-BART determination, as well as for the five-factor BART analysis. LNA’s modeling results indicate that the 98th percentile impact for each of the 3 years modeled is well over 0.5 dv at Grand Canyon National Park.79 Therefore, we propose to determine that Nelson Lime Plant (Kilns 1 and 2) is subject to BART. 2. Proposed BART for NOX For our NOX BART analysis, we identified all available control technologies, eliminated options that are not technically feasible, and evaluated the control effectiveness of the remaining control options. We then evaluated each control in terms of a five-factor BART analysis and made a determination for BART. a. Control Technology Availability, Technical Feasibility and Effectiveness EPA proposes to find that SNCR is the only technically feasible control option to control NOX emissions with a control efficiency of 50 percent. In order to determine a reasonable performance standard for controlling NOX emissions, we considered four available retrofit control technologies for NOX on Kilns 1 and 2. These control technologies are a LNB, mixing air technology (MAT), SCR, and SNCR. After evaluating each of these technologies to eliminate technically infeasible options, we determined that SNCR is the only remaining technically feasible control option. Low-NOX Burners: LNB are designed to reduce flame turbulence, delay fuel/ air mixing, and establish fuel-rich zones for initial combustion. LNA indicated that it experimented with the installation of bluff body LNB on the Nelson Lime Plant kilns in 2001.80 These LNB wore out in about six months, negatively affected production, caused brick damage, and resulted in unscheduled shutdowns of the kilns. We recognize that the staged combustion principle of LNB can present operational difficulties and potential product quality issues for lime production that are not exhibited in the cement industry. At this time we consider LNB to be technically infeasible for the Nelson Plant kilns, since we do not have any information to suggest otherwise at this time. The technical feasibility of LNB will be reevaluated for lime kilns in subsequent reasonable progress planning periods. Mixing Air Technology: MAT is the practice of injecting a high pressure air stream into the middle of a kiln to help mix the air flowing through the kiln. While the theory behind MAT suggests that the technology is effective at reducing NOX emissions, it is not clear whether this control technology is effective on lime kilns. We propose to eliminate MAT as not technically feasible for retrofit on Kiln 1 and Kiln 2. Selective Catalytic Reduction: This process uses ammonia in the presence of a catalyst to selectively reduce NOX emissions from exhaust gases. In SCR, ammonia, usually diluted with air or 9337 steam, is injected through a grid system into hot flue gases that are then passed through a catalyst bed to carry out NOX reduction reactions. The catalyst is not consumed in the process but allows the reactions to occur at a lower temperature. However, SCR is subject to catalyst poisoning in high dust kiln exhausts. Therefore, SCR would have to be placed after the particulate control systems. According to LNA, given the operating temperature range for Kiln 1 and Kiln 2 at the Nelson Lime Plant, the SCR catalyst would need to be located prior to the kiln baghouses, which would result in poisoning or covering of the catalyst. In addition, there are no SCR systems currently operating on lime kilns. We propose to eliminate SCR as not technically feasible for retrofit on Kiln 1 and Kiln 2. Selective Non-Catalytic Reduction: SNCR is a technically feasible option for reducing NOX emissions from the Nelson Lime Plant kilns as shown in Table 20. This control technique relies on the reduction of NOX in exhaust gases by injection of ammonia or urea, without using any catalyst. This approach avoids the problems related to catalyst fouling and poisoning attributed to SCR, but requires injection of the reagents in the kiln at a temperature between 1600 °F to 2000 °F. Because no catalyst is used to increase the reaction rate, the temperature window is critical for conducting this reaction. LNA has not conducted any detailed design work for an SNCR system for the Nelson Plant kilns, but anticipates that a 50 percent reduction is achievable based on LNA’s experience with operating a ureainjection system at another LNA lime plant. TABLE 20—NELSON LIME PLANT: SNCR CONTROL EFFICIENCY FOR BASELINE EMISSIONS Control efficiency mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Kiln 1: Baseline ........................................................................ SNCR ............................................................................ Kiln 2: Baseline ........................................................................ SNCR ............................................................................ 78 BART Five Factor Analysis, Lhoist North America Nelson Lime Plant; Prepared by Trinity Consultants in Conjunction with Lhoist North America of Arizona, Inc.; Project 131701.0061; August 13, 2013 (Public version dated September 27, 2013). VerDate Mar<15>2010 20:22 Feb 14, 2014 Jkt 232001 Emission factor (%) Control option (lb/ton lime) (lb/day) Emissions removed (tpy) (tpy) ........................ 50 7.59 3.80 6,573 3,286 981 491 491 ........................ 50 5.21 2.61 6,492 3,246 985 493 493 79 Id., Table 4–7. We note that the visibility modeling performed by LNA used only the annual average Class I area background concentrations, rather than the best 20 percent days background concentrations. The use of annual average generally results in lower visibility impacts than the best 20 PO 00000 Maximum emission rate Frm 00021 Fmt 4701 Sfmt 4702 percent days. Therefore, had LNA used the best 20 percent days, the baseline impacts would likely have been even greater. 80 Described on page 5–2, ‘‘BART Five Factor Analysis, Lhoist North America Nelson Lime Plant’’ (Public version dated September 27, 2013). E:\FR\FM\18FEP2.SGM 18FEP2 9338 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules b. BART Analysis for NOX EPA conducted a five-factor BART analysis of SNCR to evaluate its costeffectiveness and visibility benefit. This analysis indicates that SNCR is costeffective and results in visibility improvement. Cost of Compliance: The following table provides LNA’s estimated cost for installation and operation of SNCR. Capital cost estimates developed by LNA relied primarily on vendor cost estimates and LNA’s experience at other lime plants, with the remainder of the capital costs calculated using the cost methodology contained in EPA’s Control Cost Manual. LNA has asserted a confidential business information (CBI) claim regarding certain annual operating costs such as reagent usage and auxiliary power costs. As a result, we have prepared our own independent estimate of annual operating costs based upon a combination of publicly available data and certain general assumptions as described in the Contractor’s Report.81 Table 21 is a summary of the estimated cost for installation and operation of SNCR. TABLE 21—NELSON LIME PLANT: ESTIMATED COST FOR SNCR Capital cost Annualized capital cost Annual operating cost Total annual cost Emission reduction Costeffectiveness ($) ($) ($) ($/yr) (tpy) ($/ton) Kiln 1 ........................................................ Kiln 2 ........................................................ $450,000 450,000 $42,477 42,477 $358,459 354,981 $400,936 397,458 Energy and Non-Air Quality Environmental Impacts: SNCR systems require electricity to operate the blowers and pumps, which will likely involve fuel combustion that will generate emissions. Overall, while the generation of the required electricity will result in emissions, the emissions should be low compared to the reduction in NOX that would be gained by operating an SNCR system. The operation of SNCR systems on Kiln 1 and Kiln 2 would require that either urea or ammonia be stored on site. The storage of the chemicals does not result in a direct non-air quality impact. However, the potential for the urea or ammonia that would be stored to leak or otherwise be released from the storage vessels means there is the potential for both air and non-air quality related impacts. The storage of these chemicals does not significantly impact the BART determination. Pollution Control Equipment in Use at the Source: The presence of existing pollution control technology at each source is reflected in our BART analysis in two ways: first, in the consideration of available control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility modeling. Air pollution control equipment in use at the Nelson Lime Plant includes a number of baghouses, two multi-cyclone dust collectors, and a Ducon wet scrubber to control particulate matter emissions. The facility does not currently have control equipment for NOX and SO2. The kilns are allowed to burn coal, petroleum coke, fuel oil, or any combination of these fuels. Remaining Useful Life of the Source: Since we are not aware of any enforceable shutdown date for the Nelson Lime Plant, we have used a 20year amortization period, as noted in the EPA Cost Control Manual, as the remaining useful life of the kilns. Degree of Visibility Improvement: LNA performed a visibility analysis 82 to assess the visibility improvement associated with SNCR. LNA performed dispersion modeling using the CALPUFF modeling system, which consists of the CALPUFF dispersion model, the CALMET meteorological data processor, and the CALPOST postprocessing program. The specific program versions that were relied upon in the analysis match the program versions relied upon by EPA’s contractor, the University of North Carolina at Chapel Hill and ICF International (UNC/ICF), in the BART analyses that they prepared for select sources, including the Nelson Plant. Most of the same data and parameter settings relied upon in the analysis are the same data and parameter settings that were relied upon in the contractor’s report. Compared to the UNC work, 81 Our estimate of annual operating costs is in the spreadsheet ‘‘Nelson Control Costs 2013–10– 21.xlsx’’ in the docket. 82 BART Five Factor Analysis, Lhoist North America Nelson Lime Plant, Trinity Consultants, August 2013. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Kiln VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 491 493 $817 807 LNA used updated higher base case SO2 and NOx emissions, lower PM emissions, and lower stack exit velocities. LNA’s analysis included tables of visibility impacts and the improvement from controls, including results for the individual model years 2001, 2002, and 2003, and it used visibility method ‘‘8a’’ and focused on the highest value from among the three years’ 98th percentiles. In order to put all the facilities on the same footing, EPA post-processed the modeling files provided by LNA using the approach followed for the other facilities. Table 22 represents the 98th percentile by the 22nd high over the 2001–2003 period using visibility method ‘‘8b.’’ Using the EPA procedure, the maximum impact still occurs at the Grand Canyon, at 1.8 dv. The 98th percentile impacts at other Class I areas are about 0.3 dv or below, and the cumulative impact is 3.3 dv. The maximum visibility improvement due to SNCR is 0.58 dv, and cumulative improvement is 0.85 dv. There is little improvement at areas other than the Grand Canyon. These improvements yield a visibility cost-effectiveness of $1.4 million/dv using the maximum, and $0.9 million/dv using the cumulative improvement. These visibility improvements support the choice of SNCR as BART for NOX. E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9339 TABLE 22—NELSON LIME PLANT: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Base case Class I area mstockstill on DSK4VPTVN1PROD with PROPOSALS2 83 See ‘‘Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources,’’ Institute of Clean Air Companies, December 4, 2006. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 235 24 238 206 199 289 288 132 183 ........................ ........................ ........................ ........................ ........................ sources, such as fossil fuel boilers, there are a limited number of examples of SNCR installation on lime kilns. Given this relative lack of information regarding SNCR installation schedules on lime kilns, we consider three years to be an appropriate length of time to design, install, and test an ammonia injection system for a lime kiln. In addition, we are also proposing regulatory text that includes monitoring, reporting, and recordkeeping requirements associated with this emission limit. As part of the proposed monitoring requirements, we are including a requirement to monitor rates of ammonia injection in order to ensure proper operation of the SNCR in a manner that minimizes ammonia emissions. 3. Proposed BART for SO2 For our BART analysis, we identify all available control technologies, eliminate options that are not technically feasible, and evaluate the control effectiveness of the remaining control options. We then evaluate each control in terms of a fivefactor BART analysis and make a determination for BART. a. Control Technology Analysis for SO2 EPA proposes to find that DSI and switching to lower sulfur fuel are technically feasible controls, while wet or semi-dry scrubbing is not technically feasible. Wet or Semi-Dry Scrubbing: We do not consider wet or dry scrubbing to be a feasible technology to control SO2 emissions for this source. Wet scrubbing involves passing flue gas downstream from the main particulate matter control device through a sprayed aqueous suspension of lime or limestone that is contained in a scrubbing device. The SO2 reacts with the scrubbing reagent to PO 00000 SNCR (ctr1) Distance (km) Bryce Canyon NP .................................................................................................................... Grand Canyon NP ................................................................................................................... Joshua Tree NP ....................................................................................................................... Mazatzal WA ............................................................................................................................ Pine Mountain WA ................................................................................................................... Sierra Ancha WA ..................................................................................................................... Superstition WA ....................................................................................................................... Sycamore Canyon WA ............................................................................................................ Zion NP .................................................................................................................................... Cumulative (sum) ..................................................................................................................... Maximum ................................................................................................................................. # CIAs >= 0.5 dv ..................................................................................................................... Million $/dv (cumul. dv) ............................................................................................................ Million $/dv (max. dv) .............................................................................................................. c. Proposed BART Determination for NOX We propose to find that BART for NOX for Kilns 1 and 2 is SNCR, and are proposing a BART emission limit for Kiln 1 of 3.80 lb/ton lime and for Kiln 2 of 2.61 lb/ton lime on a 30-day rolling basis, as demonstrated through the use of a CEMS. We consider SNCR to be a very cost-effective control option for Kilns 1 and 2, at $817/ton and $807/ton, respectively. In addition, we consider the anticipated visibility benefit from SNCR, 0.58 dv at Grand Canyon National Park and 0.85 cumulatively at all Class I areas within 300 km, to be substantial. In considering the other factors, we do not consider their impact substantial relative to the cost and visibility factors. We note that the remaining useful life of the source is reflected in the evaluation of cost of compliance through the use of a 20-year amortization period in control cost calculations. Since there is no existing NOX control technology in use on the kilns, baseline emissions reflect uncontrolled NOX emissions. In examining energy and non-air quality impacts, while we note certain impacts associated with SNCR, we do not consider these impacts sufficient to warrant its elimination as a control option. We propose to require compliance with this requirement within three years after the effective date of the final rule. A 2006 Institute of Clean Air Companies (ICAC) study indicated that the installation time for a typical SNCR retrofit, from bid to startup-up, is 10–13 months.83 In relation to other industrial Visibility improvement Frm 00023 Fmt 4701 Sfmt 4702 0.20 1.79 0.23 0.15 0.15 0.11 0.13 0.31 0.28 3.34 1.79 1 .......................... .......................... 0.06 0.58 0.02 0.01 0.02 0.01 0.01 0.07 0.08 0.85 0.58 1 $0.9 $1.4 form lime sludge that is collected. The sludge usually is dewatered and disposed of at an offsite landfill. However, LNA has concluded, and we agree, that there is not sufficient water available for this type of system. According to LNA, two ground water wells supply about 106 gallons per minute (gpm) to the Nelson Plant, which currently uses about 80 gpm. Therefore, only 26 gpm of water is available for a scrubbing system that, even for a semi-dry scrubbing system that has lower water requirements than wet scrubbing, would require about 117 gpm. Moreover, a 1998 hydrologic report indicates that the prospects for developing additional wells, even lowyield wells, on the Nelson property are poor.84 After reviewing the hydrologic report and the vendor estimate of water requirements for a semi-dry scrubber, we agree with this assessment. Dry Sorbent Injection: DSI involves the injection of powdered absorbent directly into the flue gas exhaust stream. The sorbent reacts with SO2 in the exhaust to form solid particles that are then removed by a particulate matter control device downstream of the sorbent injection. DSI is a simple system that generally requires a sorbent storage tank, feeding mechanism, transfer line and blower, and an injection device. DSI is generally considered technically feasible for the cement industry, although the level of control effectiveness may vary based upon sitespecific conditions. We consider this option technically feasible for lime kilns. LNA has not included information in its analysis indicating 84 See ‘‘Results of Hydrogeologic Investigations for Development of Additional Water Supply, Chemical Lime Company, Nelson Plant, Yavapai County, AZ,’’ July 8, 1998. E:\FR\FM\18FEP2.SGM 18FEP2 9340 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules that DSI would be infeasible for the Nelson Plant kilns. Lower Sulfur Fuel: The lower sulfur fuel option described by LNA involves changing the proportion of coal and petroleum coke used as a fuel blend. LNA currently uses a blend of 27 percent coal and 73 percent petroleum coke, on a mass basis, as the fuel for the kilns. Since coke has about four to five times more sulfur than coal, it is possible to decrease the sulfur in the fuel blend by increasing the proportion of coal. However, an increase in coal in the fuel blend will also increase the ash content of the fuel blend. Ash in the fuel can disrupt operations due to the buildup of ash rings in the kilns. A fuel blend with an ash content of about 6.5 percent or less must be used in order to avoid these operational challenges. As noted in fuel usage and purchase records, the Nelson Plant currently operates on a coal and petroleum coke mixture. As a result, we consider adjusting the coal/coke ratio in the fuel mixture to be a technically feasible option. We note, however, that since the BART Guidelines do not require fuel supply changes to be considered as a control option, we have typically not considered changes in fuel in BART analyses.85 However, because LNA included lower sulfur fuel in its analysis, we have retained it as a control option. b. BART Analysis for SO2 EPA conducted a five-factor BART analysis of the two technically feasible control options, DSI and lower sulfur fuel, to evaluate the cost-effectiveness and visibility benefit of each option along with any effect on the other factors. Cost of Compliance: Our consideration of the cost of compliance focuses primarily on the costeffectiveness of each control option as measured in cost per ton and incremental cost per ton. We estimate the SO2 emissions rates for DSI and lower sulfur fuel as shown in Table 23, and the cost-effectiveness of these options as shown in Table 24. DSI has a control efficiency of 40 percent that results in about 1,588 tpy of SO2 removed from both kilns. Lower sulfur fuel has a control efficiency of 23.3 percent that results in about 925 tpy of SO2 removed from both kilns. Based on the total annual costs of controlling SO2 emissions at both kilns, DSI would cost an average of about $4,200 per ton removed and lower sulfur fuel about $860 per ton removed. Since there is no existing SO2 control technology in use in the plant, baseline emissions reflect uncontrolled SO2 emissions. While we consider it appropriate to use 40 percent control efficiency 86 for DSI, we are inviting comment on the control effectiveness of 23.3 percent for a lower sulfur fuel blend based on the ratio of coal (1.15 percent sulfur) to petroleum coke (5.64 percent sulfur). LNA estimates that the maximum coalto-coke ratio to maintain overall fuel ash content below 6.5 percent is a 50 percent coal to 50 percent coke fuel mixture. A 50/50 mix corresponds to a fuel sulfur reduction of 1.13 percentage points, which represents a 23.3 percent reduction from the current fuel mixture. Based on a review of coal and coke properties along with historical fuel usage at the Nelson Plant, we agree with the use of a 50/50 coal-to-coke ratio and 23.3 percent control effectiveness. However, LNA cites operational issues with fuel ash content above 6.5 percent. Since ash is a contaminant that can adversely affect lime product quality, we are seeking comment regarding the extent to which it is appropriate to use fuel ash content of 6.5 percent as the upper bound for determining fuel mixture ratio. We may finalize a different fuel mixture ratio based upon the comments we receive. In estimating the costs of compliance, LNA relied on a vendor quote for purchased equipment provided by Noltech dated May 22, 2013, with the remainder of the capital costs calculated using the cost methodology contained in EPA’s Control Cost Manual.87 While these capital costs are higher than those estimated by our contractor, we consider the use of the Noltech vendor quote for the Nelson Plant reasonable, and have incorporated it into our evaluation of the costs of compliance. With regard to annual operating & maintenance costs, LNA has asserted a confidential business information (CBI) claim regarding certain annual operating costs such as reagent usage. As a result, we have prepared our own independent estimate of annual operating costs based upon a combination of publicly available data and certain assumptions as described in the contractor’s report. Detailed cost calculations can be found in the docket.88 TABLE 23—NELSON LIME PLANT: SO2 CONTROL OPTION EMISSION ESTIMATES Control efficiency (%) SO2 control technology mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Kiln 1: Baseline ............................................................................................ Lower Sulfur Fuel Blend ................................................................... Dry Sorbent Injection ........................................................................ Kiln 2: Baseline ............................................................................................ Lower Sulfur Fuel Blend ................................................................... Dry Sorbent Injection ........................................................................ 85 40 CFR Part 51, Appendix Y, Section IV.D.1.5, ‘‘STEP 1: How do I identify all available retrofit emission control techniques?’’ 86 While the control efficiency for DSI is much higher for cement kilns, LNA conducted onsite testing of DSI on the lime kilns at the Nelson Plant VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Emission factor (lb/ton lime) Frm 00024 Fmt 4701 lb/day Tpy Removed (tpy) .................... 23.30 40 12.15 9.32 7.29 10,526 8,073 6,316 1,571 1,205 943 .................... 366 628 .................... 23.30 40 12.69 9.73 7.61 15,808 12,125 9,485 2,400 1,841 1,440 .................... 559 960 that demonstrated it is appropriate to use 40 percent control efficiency. The docket includes a comparison of LNA’s tests of DSI to the analysis in our contractor’s report. 87 Vendor quote included as an attachment to BART Five Factor Analysis, Lhoist North America PO 00000 Maximum emission rate Sfmt 4702 Nelson Lime Plant; (Public version dated September 27, 2013). 88 See spreadsheet ‘‘Nelson Control Costs 2013– 10–24.xlsx’’ in the docket. E:\FR\FM\18FEP2.SGM 18FEP2 9341 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 24—NELSON LIME PLANT: SO2 CONTROL OPTION COST-EFFECTIVENESS Capital cost Annual direct costs Annual indirect costs Total annual cost Emission reduction ($) ($/yr) ($/yr) ($/yr) (tpy) .................... $2,497,559 .................... $371,174 .................... $2,621,832 $313,096 2,621,832 366 628 $856 4,174 .................... $8,803 .................... 2,497,559 .................... 371,174 .................... 3,895,774 458,179 3,895,774 559 960 819 4,058 .................... 8,576 SO2 control technology Kiln 1: Lower Sulfur Fuel Blend ................... Dry Sorbent Injection ........................ Kiln 2: Lower Sulfur Fuel Blend ................... Dry Sorbent Injection ........................ Pollution Control Equipment in use at the Source: The presence of existing pollution control technology at the Nelson Plant is reflected in the BART analysis in two ways: first, in the consideration of available control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility modeling. In the case of SO2, the kilns at the Nelson Plant do not operate with any existing control technology. This is reflected in the baseline emission rates, which represent uncontrolled SO2 emissions. Energy and non-air quality environmental impacts: Regarding the first option, DSI systems require electricity for operation. The generation of the electricity needed to operate a DSI system will likely involve fuel combustion that will generate emissions. Emissions also are associated with the transport, handling, and storage of sorbent. Overall, while the use of DSI will cause emissions from select activities, the emissions should be low compared to the reduction in SO2 that would be gained by operating a DSI system. Regarding the second option, using a lower sulfur fuel blend means LNA will obtain more of the energy for lime production from coal and less of the energy from coke. Since the heating value of coke is slightly higher than the heating value of coal, it is likely that LNA will burn more total mass of fuel as a result of substituting some coal for coke. While burning a lower sulfur fuel blend will likely result in a reduction in SO2 emissions, it will involve the overall use of greater quantities of coal, which may result in a collateral increase of other pollutants such as NOX and CO. Remaining Useful Life of the Source: We are considering the ‘‘remaining useful life’’ of the kilns as one element of the overall cost analysis as allowed by the BART Guidelines. In the absence of any enforceable closure date, we have used a 20-year amortization period described in the EPA Cost Control Manual as the remaining useful life for the control options considered for the Cost-effectiveness ($/ton) Average Incremental Nelson Plant kilns. Since there is no capital costs associated with using a lower sulfur fuel blend, the remaining useful life of the kilns is not a factor in the evaluation of this technology. Degree of Visibility Improvement: As was the case for NOX, EPA postprocessed LNA’s modeling results for SO2 controls. The greatest improvement from DSI is 0.2 dv, occurring at the Grand Canyon, with improvements at other areas a third or less than this. The cumulative improvement is 0.6 dv. The maximum and cumulative improvements from switching to lower sulfur fuel are roughly half of these amounts. While visibility improvement by itself could support either DSI or lower sulfur fuel as BART, lower sulfur fuel is favored by its much lower average cost-effectiveness at $819–856/ ton compared to over $4000 for DSI. Baseline and control option emission rates used in SO2 control scenario modeling are summarized in Table 25 with the modeling results in Table 26.89 TABLE 25—NELSON LIME PLANT: SO2 CONTROL MODEL EMISSION RATES Control efficiency Kiln 1: Baseline ............................................................................................ Lower Sulfur Fuel Blend ................................................................... Dry Sorbent Injection (SBC) ............................................................. Kiln 2: Baseline ............................................................................................ Lower Sulfur Fuel Blend ................................................................... Dry Sorbent Injection (SBC) ............................................................. Emission factor % SO2 control technology Maximum 24-hr model emission rate lb/ton lime lb/day lb/hr g/s .................... 23.30 40 12.15 9.32 7.29 10,526 8,073 6,315 439 336 263 55 42 33 .................... 23.30 40 12.69 9.73 7.61 15,808 12,125 9,489 659 505 395 83 64 50 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 TABLE 26—NELSON LIME PLANT: SO2 CONTROL OPTION VISIBILITY MODELING RESULTS Distance (km) Class I area Visibility impact Base case Bryce Canyon NP ........................................................................................................ 89 These results are from EPA’s post-processing of LNA’s modeling. See the TSD for a discussion of VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 235 0.20 the differences between EPA’s results and the results reported by LNA in their BART analysis. PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 Visibility improvement DSI (ctr2) 0.03 Low-S fuel (ctr3) 0.02 9342 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 26—NELSON LIME PLANT: SO2 CONTROL OPTION VISIBILITY MODELING RESULTS—Continued Distance (km) Class I area Visibility impact Base case Grand Canyon NP ....................................................................................................... Joshua Tree NP ........................................................................................................... Mazatzal WA ................................................................................................................ Pine Mountain WA ....................................................................................................... Sierra Ancha WA ......................................................................................................... Superstition WA ........................................................................................................... Sycamore Canyon WA ................................................................................................ Zion NP ........................................................................................................................ Cumulative (sum) ......................................................................................................... Maximum ..................................................................................................................... # CIAs >= 0.5 dv ......................................................................................................... Million $/dv (cumul. dv) ................................................................................................ Million $/dv (max. dv) .................................................................................................. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 c. Proposed BART Determination for SO2 We propose to find that BART for SO2 is the use of a lower sulfur fuel blend with an emission limit of 9.32 lb/ton for Kiln 1 and 9.73 lb/ton for Kiln 2 90 on a rolling 30-day basis. In evaluating the costs of compliance, we note that we consider DSI and lower sulfur fuel to both be cost-effective control options, with average cost-effectiveness values of approximately $800/ton and $4,000/ton, respectively. In evaluating anticipated visibility benefit, while DSI is anticipated to achieve the greatest visibility improvement (0.21 dv at Grand Canyon), this amount of visibility improvement is not large, nor is the benefit anticipated for the next most stringent control option, lower sulfur fuel (0.10 dv at Grand Canyon). In considering the other factors, there is no significant effect on the outcome of the cost and visibility analyses. The lack of existing control technology is reflected in the baseline in the form of uncontrolled SO2 emissions. In examining energy and non-air quality impacts, we note that there may be certain collateral increases in emissions, but that these increases are outweighed by the emission reductions achieved by implementing the control technology and do not warrant their elimination. The remaining useful life of the source is reflected in the evaluation of the cost of compliance. We consider both DSI and use of lower sulfur fuel to be costeffective, but note that the most stringent option, DSI, is considerably less cost-effective than the use of lower sulfur fuel, with an incremental costeffectiveness, relative to lower sulfur fuel, of approximately $9,000/ton. As a 90 The differing emission limits are due to the different baseline performance of the two kilns. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 24 238 206 199 289 288 132 183 .................... .................... .................... .................... .................... result, although DSI is the most stringent control option, the visibility benefit it achieves is not large, and is achieved at a very high incremental cost relative to the next most stringent control option. Based on this information, we propose to find that BART for SO2 is the use of a lower sulfur fuel blend. 4. Proposed BART for PM10 For our BART analysis, we identified fabric filter baghouses, the existing control technology for PM10 on Kilns 1 and 2, as the most stringent control available for this type of source. a. Control Technology Analysis for PM10 The Nelson Plant, as a major source of hazardous air pollutants (HAPs), is subject to the Maximum Achievable Control Technology (MACT) Standard for Lime Manufacturing Plants, and is required to meet an emission limit of 0.12 lbs PM/TSF (ton of stone feed).91 The BART Guidelines provide that unless there are new technologies subsequent to the MACT standards that would lead to cost-effective increases in the level of control, one may rely on the MACT standards for purposes of BART.92 Based on information developed as part of the Lime MACT, we estimate that existing fabric filter upgrades would result in annual costs of $94,500.93 As noted in LNA’s BART analysis, baseline PM emissions for the two kilns, based on PM filterable stack 91 40 CFR Part 63, Subpart AAAAA, Table 1, Item 1 for existing lime kilns with no wet scrubber prior to 2005. 92 40 CFR Part 51, Appendix Y, Section IV.C. 93 Annual costs as described in the Economic Impact Analysis for the Lime Manufacturing MACT Standard (EPA–452/R–03–013), Table 3–2, Model Kiln F. Adjusted from 1997 to 2013 dollars using the consumer price index, available at ftp:// ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 1.79 0.23 0.15 0.15 0.11 0.13 0.31 0.28 3.34 1.79 1 ...................... ...................... Visibility improvement DSI (ctr2) 0.21 0.07 0.04 0.04 0.04 0.04 0.06 0.04 0.57 0.21 0 $11.5 $30.7 Low-S fuel (ctr3) 0.10 0.04 0.02 0.02 0.02 0.02 0.04 0.02 0.29 0.10 0 $2.6 $8.1 test data and annual lime production, are approximately 8 tpy and 15 tpy.94 This would result in an average costeffectiveness of about $6,300 to $12,000/ ton. b. BART Analysis for PM10 The BART Guidelines provide that, in instances where a source already has the most stringent controls available (including all possible improvements), it is not necessary to complete each step of the BART analysis. Further, as long as the most stringent controls available are made federally enforceable for the purpose of implementing BART for that source, one may skip the remainder of the analysis, including the visibility analysis.95 c. Proposed BART Determination for PM10 We propose a BART emission limit of 0.12 lb/TSF to control PM10 at Kilns 1 and 2 based on the use of the existing fabric filter baghouses and commensurate with the MACT standard that applies to this source. We seek comment on any cost-effective upgrades or improvements that may result in a lower emission limit. We propose to require compliance with this requirement within 6 months after the effective date of the final rule. We also propose regulatory text that includes monitoring, reporting, and recordkeeping requirements associated with this emission limit that is found at the end of this notice. C. Hayden Smelter Summary: EPA proposes to find that the ASARCO Hayden Smelter is subject to BART for NOX in addition to SO2 as 94 As described in the LNA Nelson BART Analysis, Table 4–5. 95 40 CFR Part 51, Appendix Y, Section IV.D.9. E:\FR\FM\18FEP2.SGM 18FEP2 9343 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules determined by the State. ASARCO must capture and control SO2 emissions from the converter units that are subject to BART. In the current method of operation, thousands of tons of SO2 from these units are vented to the atmosphere with no pollution control. One method to control SO2 emissions from the converter units is to install and operate a second double contact acid plant with a control efficiency of about 99.8 percent on a 30-day rolling average. We estimate the annual cost of constructing and operating a second acid plant to control SO2 emissions is about $872 per ton of SO2 removed. While we consider the cost of a new acid plant to be reasonable, we are proposing a performance standard as BART rather than prescribing a particular method of control. For NOX, we propose to set an annual emission limit of 40 tpy from the BART-eligible units, based on our proposed determination that no NOX controls are needed for BART at the Hayden Smelter. Finally, we are proposing an emission limit and associated compliance requirements for PM10. Affected Class I Areas: Twelve Class I areas are within 300 km of the Hayden Smelter. Their nearest borders range from 48 km to 239 km away. Galiuro WA and Superstition WA are the closest, followed by Saguaro NP and Sierra Ancha WA. The highest baseline 98th percentile visibility impact is 1.7 dv at Superstition, with impacts at Galiuro slightly lower. Baseline visibility impacts at each of the twelve areas exceed 0.5 dv. The cumulative sum of visibility impacts over all the Class I areas is 12.1 dv. Facility Overview: ASARCO Hayden Smelter is a batch-process copper smelter in Gila County, Arizona. We previously approved ADEQ’s determination that converters 1, 3, 4 and 5 and Anode Furnaces 1 and 2 at the facility are BART-eligible.96 We also approved ADEQ’s determination that these units are subject to BART for SO2 and that BART for PM10 at ASARCO Hayden is no additional controls. However, we disapproved ADEQ’s determination that existing controls constitute BART for SO2 and that the units are not subject to BART for NOX. In light of these disapprovals and our FIP duty for regional haze in Arizona, we are required to promulgate a FIP to address BART for SO2 and NOX. Baseline Emissions Calculations: Since neither ASARCO nor ADEQ identified baseline emissions for the Hayden Smelter, we calculated baseline emissions for SO2 and NOX. For SO2, we used as the baseline the average of the two highest emitting years from the last five years that ASARCO reported to ADEQ. For NOX, we estimated emission rates based on the rated natural gas capacity of the burners in the four subject-to-BART converters and the two anode furnaces.97 As indicated in Table 27, the majority of the source’s SO2 emissions (20,341 tpy of a total of 22,621 tpy) are process emissions from the converters. These process SO2 emissions are collected through a secondary capture system, but are emitted uncontrolled through an annular stack that bypasses the existing double contact acid plant. While our BART analysis focuses on these uncontrolled SO2 emissions from the converters, we also evaluated improved control of the SO2 emissions from the existing acid plant and from the anode furnaces as well as controlling NOX emissions from all the BART units. TABLE 27—HAYDEN SMELTER: BART BASELINE EMISSIONS [Tons per year] Converters Existing acid plant (primary capture) SO2 ...................................................................................................... 1,034 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 NOX ...................................................................................................... Modeling Overview: EPA is relying on modeled baseline and post-control impacts of the ASARCO Hayden Smelter using stack parameters provided by ASARCO in response to a 2013 EPA information request.98 We also modeled using stack parameters based on a 2012 stack test.99 Stack exit temperatures were comparable for these two models, but the exit velocities from the 2012 stack test were far lower than those provided by ASARCO in 2013. The 2012 stack test parameters resulted in visibility impacts and control benefits about 10 percent higher than the model using the 2013 parameters. We are conservatively using the 2013 ASARCO 96 78 FR 46412 (July 30, 2013). Please refer to the TSD for a description of these units. 97 ASARCO Hayden Title V permit. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Annular stack (secondary capture) 20,341 1. BART Analysis and Determination for SO2 From Converters a. Control Technology Availability, Technical Feasibility and Effectiveness EPA identified two available technology options to control the 20,341 tons of SO2 emissions from the annular stack that are captured by a secondary collection system, but are released 98 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 11, 2013; attached Memorandum from Ralph Morris and Lynsey Parker, ENVIRON, to Eric Hiser, Jorden, Bischoff and Hiser, PLC, March 4, 2013. Frm 00027 Fmt 4701 1,209 Sfmt 4702 Anode furnaces Total 37 22,621 19 31 parameters to evaluate controls, since using the 2012 parameters would yield even greater visibility improvements. For both sets of modeling runs, EPA used emission rates that were developed using information provided by ASARCO. PO 00000 Uncaptured 50 uncontrolled through the annular stack. These options are to construct and operate a second double contact acid plant or install a wet scrubber on the annular portion of the existing stack. In addition, we found that ASARCO could add a tail stack scrubber to the existing acid plant to address the remaining emissions that are not converted and removed as sulfuric acid by the acid plant. Regarding technical feasibility, we note that ASARCO Hayden currently uses a double contact acid plant to control SO2 emissions captured by the primary capture system. Wet scrubbing also is commonly used in many industries to control SO2. Thus, we find 99 ASARCO Hayden CEMS Test Report, Energy and Environmental Measurement Corporation, Test date: September, 2012. E:\FR\FM\18FEP2.SGM 18FEP2 9344 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules that the double contact acid plant and wet scrubbing are technically feasible. In terms of control effectiveness, ASARCO indicated in a letter 100 to EPA that its double contact acid plant is capable of recovering 99.8 percent of the SO2 vented to it.101 In the same letter, ASARCO noted that the expected control effectiveness of wet scrubbing is 85 percent. We used these removal efficiencies in our five-factor analyses. These analyses are explained in the TSD and summarized below. b. Option 1: Double Contact Acid Plant for Secondary Capture a control efficiency of 99.8 percent, which the existing acid plant is currently achieving with limited cesium catalyst. The emission reduction was applied to the secondary capture system baseline emissions. This cost analysis does not include the offsetting value of any sulfuric acid produced and sold. It does assume full catalyst replacement every other year and air preheating with natural gas for 8,760 hours per year. Cost of Compliance: EPA determined the cost-effectiveness of a new double contact acid plant is $872 per ton of SO2 removed as shown in Table 28. As explained in the TSD, we conservatively estimated the cost of construction of a double contact acid plant to be $81,621,297. The annualized capital costs are based on a 20-year lifespan and a seven percent interest rate. We applied TABLE 28—HAYDEN SMELTER OPTION 1: SECOND DOUBLE CONTACT ACID PLANT Capital cost Annualized capital cost Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $81,621,297 ............................................. $7,704,573 $10,006,010 $17,710,483 20,341 99.8% $872 Energy and Non-Air Quality Environmental Impacts: Controlling secondary capture with a sulfuric acid plant at the Hayden Smelter would require energy to heat inlet air from approximately 177 °F to 735 °F. This would require a heat input of approximately 114 MMBtu/hour and could require 1,200 MMscf of natural gas per year, resulting in up to 30 tpy of NOX emissions.102 This assumes 100 percent of the needed heat results from natural gas combustion. Non-air quality impacts from a second acid plant are not expected to be significant given that ASARCO already has the capacity to handle and store the much larger quantities of sulfuric acid produced by the primary acid plant. Pollution Control Equipment in Use at the Source: As noted above and further described in the TSD, a portion of the emissions from the converters are controlled by a gas cleaning plant to remove particulate matter and a double contact sulfuric acid plant that converts SO2 to sulfuric acid. We considered these controls as part of our analysis of available control technologies and in developing baseline emission rates for use in cost calculations and visibility modeling. Remaining Useful Life of the Source: The BART-eligible converters have each been in place for about 40 years or longer. ASARCO has not indicated that any of the converters would need to be replaced during the 20-year capital cost recovery period. Degree of Visibility Improvement: Controlling SO2 emissions through a second double contact acid plant at a 98.8 percent efficiency results in visibility improvement in 12 Class I areas in Arizona and New Mexico as indicated in Table 29. Based on air quality modeling, visibility improvement from controlling SO2 by constructing a new acid plant to control converter emissions from the secondary capture system is 1.5 dv at Superstition, and nearly the same at Galiuro. Eleven of the Class I areas improve by at least 0.5 dv. The cumulative improvement is 10.3 dv. The large visibility improvement at many Class I Areas supports the choice of a new acid plant as BART for SO2. TABLE 29—HAYDEN SMELTER OPTION 1: VISIBILITY IMPACT AND IMPROVEMENT FROM SO2 CONTROLS mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Class I area Distance (km) Visibility impact base case (base) Chiricahua NM ..................................................................................................................................... Chiricahua WA ..................................................................................................................................... Galiuro WA .......................................................................................................................................... Gila WA ................................................................................................................................................ Mazatzal WA ........................................................................................................................................ Mount Baldy WA .................................................................................................................................. Petrified Forest NP .............................................................................................................................. Pine Mountain WA ............................................................................................................................... Saguaro NP ......................................................................................................................................... Sierra Ancha WA ................................................................................................................................. Superstition WA ................................................................................................................................... Sycamore Canyon WA ........................................................................................................................ Cumulative (sum) ................................................................................................................................. Maximum ............................................................................................................................................. # CIAs >= 0.5 dv ................................................................................................................................. Million $/dv (cumul. dv) ........................................................................................................................ Million $/dv (max. dv) .......................................................................................................................... 170 174 48 186 121 151 215 168 82 84 50 239 .................... .................... .................... .................... .................... 1.05 1.01 1.73 0.69 0.88 0.66 0.70 0.67 1.38 1.09 1.74 0.51 12.10 1.74 12 ...................... ...................... 100 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 11, 2013. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 101 Ibid. PO 00000 Frm 00028 Visibility improvement new acid plant (ctrl2) 0.89 0.87 1.45 0.60 0.75 0.56 0.61 0.57 1.18 0.93 1.47 0.44 10.32 1.47 11 $1.7 $12.1 102 This is based on the AP 42 factor for low-NO X burners. Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules constructing and operating a wet scrubber based on information provided in ASARCO’s letter 103 from which we used the highest operating cost estimates to demonstrate costeffectiveness. We also included a sludge hauling fee of $60 per ton and assumed one ton of SO2 controlled would result in five tons of sludge. According to c. Option 2: Wet Scrubber on Existing Stack for Secondary Capture Cost of Compliance: EPA determined that the annual cost of using a wet scrubber to control SO2 emissions from the secondary capture system is $972 per ton of SO2 removed as displayed in Table 30. We calculated the costs of 9345 ASARCO, these costs do not include the cost of a booster fan or a modified stack that may be needed, thereby somewhat increasing the cost over what is shown here. Although the calculation includes the cost of hauling sludge off site, it does not include the cost of treating or landfilling the sludge. TABLE 30—HAYDEN SMELTER OPTION 2: WET SCRUBBER ON EXISTING STACK Capital cost Annualized capital cost Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $28,000,000 ............................................. $2,643,002 $14,186,965 $16,829,967 17,290 85% $972 Energy and Non-Air Quality Environmental Impacts: Operation of a wet scrubber would likely require operation of a booster fan and a gas reheater to force emissions through the 305 meter stack. The addition of a wet scrubber could result in a detached visible plume as water vapor emitted from the scrubber condenses. Addition of a scrubber would result in sludge which would have to be shipped off site to be treated or landfilled. Because of metals in the sludge, it may need to be treated as hazardous waste. Pollution Control Equipment in Use at the Source: This is the same as for Option 1. Remaining Useful Life of the Source: This is the same as for Option 1. Degree of Visibility Improvement: We did not conduct visibility modeling for this option. Because a scrubber is less efficient at removing SO2 than a second acid plant, the emission rates would be higher and there would be less visibility improvement from a scrubber compared to an acid plant. Given that scrubbers are less cost-effective than a second acid plant, we deemed it unnecessary to model impacts. d. Option 3: Wet Scrubber on Acid Tail Stack for Primary Capture Cost of Compliance: EPA determined the annual cost of using a wet scrubber to control SO2 emissions from the existing acid plant tail stack is $13,564 per ton of SO2 removed as displayed in Table 31. We calculated the costs of constructing and operating a wet scrubber based on information provided by ASARCO.104 In this case, we used the low-end estimate of operating costs because we are demonstrating that this option is not cost-effective. We also included a sludge hauling fee of $60 per ton and assumed one ton of SO2 controlled would result in five tons of sludge. Again, these costs did not include the cost of a booster fan or a modified stack that may be needed. Although the calculation included the cost of hauling sludge off site, it did not include the cost of treating or disposing the sludge, which may be classified as hazardous waste depending on the metals content. In addition, we note that some of the SO2 that passes through the acid plant is emitted by the flash furnace that is not BART-eligible. TABLE 31—HAYDEN SMELTER OPTION 3: WET SCRUBBER ON ACID TAIL STACK Annualized capital cost Annual variable cost Total annual cost Control efficiency Tons SO2 reduced $/ton SO2 removed $28,000,000 ............................................. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Capital cost $2,643,002 $9,274,521 $11,917,523 85% 879 $13,564 Energy and Non-Air Quality Environmental Impacts: This is the same as for Option 2. Pollution Control Equipment in Use at the Source: This is the same as for Options 1 and 2. Remaining Useful Life of the Source: This is the same as for Options 1 and 2. Degree of Visibility Improvement: We did not conduct visibility modeling for a tail stack scrubber because of the high control cost per ton of SO2. However, because the scrubber would remove much less SO2 than options 1 or 2 (second acid plant and wet scrubber on the secondary capture, respectively), the expected visibility improvement is far less than for options 1 and 2. 103 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA (July 11, 2013). VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 e. Proposed BART Determination for SO2 From Converters Based on the results of our BART analysis, we propose that BART for SO2 from the converters is a level of control consistent with what ASARCO could achieve through the installation of a new double contact acid plant. This would control about 20,341 tpy of SO2 emissions from the converter units at a cost of about $872 per ton of SO2 removed, which we consider highly cost-effective. The expected visibility benefits of this option are substantial with a greater than 0.5 dv improvement in eleven Class I areas with a maximum benefit of 1.47 dv at Superstition WA. We propose to find that the energy and non-air quality environmental effects of this option are not sufficient to warrant elimination of this option. Regarding the other options, a wet scrubber for the secondary capture (Option 2) is less effective at a similar annual cost but with greater non-air environmental impacts. Therefore, we do not propose to require this as BART. Adding a scrubber to the existing acid tail stack for the primary capture (Option 3) would result in a relatively small amount of additional emissions reductions at a relatively high cost ($13,564 per ton of SO2 removed) and with potentially significant non-air environmental impacts. Therefore, we propose that the addition of a scrubber 104 Ibid. PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9346 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules to the existing acid plant is not required as BART. The specifics of our BART proposal for SO2 from the converters are as follows: • An SO2 control efficiency of 99.8 percent, 30-day rolling average, on all SO2 captured by the primary and secondary control systems. The control efficiency may be averaged between the two capture systems on a mass basis, if needed. (For every 30-day period the total mass of SO2 exiting the two control systems must be no greater than 0.0019 percent of the SO2 entering the control systems.) • Compliance with the SO2 BART limit may be verified either through the use of SO2 CEMS before and after controls in each system or by using post-control CEMS and acid production rates. A limit of 2.49 lbs SO2 emissions per tons of sulfuric acid production is equivalent to 99.8 percent control. • Operation and maintenance of primary and secondary capture systems meeting the requirements of 40 CFR part 63, subpart QQQ. We propose to require that these requirements be met within 3 years of promulgation of the final rule, consistent with the requirement of the CAA and the RHR that BART be installed ‘‘as expeditiously as practicable.’’ 2. BART Analysis and Determination for SO2 From Anode Furnaces a. BART Analysis for SO2 From Anode Furnaces We identified the same two control technologies for the anode furnaces: a new double contact acid plant and a wet scrubber. In addition, we considered whether emissions from the anode furnaces might be vented to the existing acid plant. Cost of Compliance: Based on our calculations, we estimated that the cost to control 37 tpy of SO2 from the anode furnaces by construction of a new acid plant is over $28,000 per ton, not including the cost of inlet preheating,105 as shown in Table 32. The estimated cost of installing and operating a wet scrubber is even more expensive at over $80,000 per ton106 as shown in Table 33. TABLE 32—HAYDEN SMELTER: NEW ACID PLANT FOR THE ANODE FURNACES Capital cost Annualized capital cost Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $8,583,190 ............................................... $810,192 $261,827 $1,071,920 37 99.8% $28,616 TABLE 33—HAYDEN SMELTER: NEW WET SCRUBBER FOR THE ANODE FURNACES Capital cost Annualized capital cost Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $7,000,000 ............................................... $660,750 $2,009,570 $2,670,320 32 85% $83,708 Given the high cost of control, and the small potential for visibility improvement, we propose that controlling the 37 tpy of SO2 emissions from the anode furnaces is not a. Proposed Subject-to-BART Finding for NOX As explained in our final rule on the Arizona RH SIP, once a source is determined to be subject to BART, the RHR allows for the exemption of a specific pollutant from a BART analysis only if the potential to emit for that pollutant is below a specified de minimis level.108 Neither the Hayden Smelter’s current Title V permit nor the Arizona RH SIP contains any physical or operational limitations that would limit the PTE of the BART-eligible 105 See the TSD for further discussion of this issue. 106 See the TSD, Section III.D.4. 107 40 CFR 51.308(e)(1)(iii). See also 40 CFR 51.100(z) (defining ‘‘emission limitation’’ and ‘‘emission standard’’ to include ‘‘any requirements which . . . prescribe equipment . . . for a source to assure continuous emission reduction.’’ 108 40 CFR 51.308(e)(1)(ii)(C). b. Proposed BART Determination for SO2 From Anode Furnaces mstockstill on DSK4VPTVN1PROD with PROPOSALS2 of emissions from these units, compared with the converters. Therefore, we are proposing to establish a work practice standard in the form of a requirement that the anode furnaces be charged with blister copper or higher purity copper. Because blister copper is generally 98 to 99 percent pure copper, this requirement will ensure that sulfur emission from the anode furnaces are minimized. warranted as BART. Furthermore, while redirecting the anode furnace emissions to the existing acid plant might be technically feasible and cost-effective, the emission reductions and visibility benefit, although not calculated, would be much smaller than the calculated benefits from controlling additional emissions from the converters. In order to ensure that emissions from anode furnaces do not increase substantially in the future, we are proposing to establish a work practice standard for these units. While BART determinations are generally promulgated in the form of numeric emission limitations, the RHR allows for use of equipment requirements or work practice standards in lieu of a numeric limit where ‘‘technological or economic limitations on the applicability of measurement methodology to a particular source would make the imposition of an emission standard infeasible.’’107 In this case, we find that a numerical emission limitation for the anode furnaces would be infeasible because of the relatively small amount Energy and Non-Air Quality Environmental Impacts: This is the same as for the converters. Pollution Control Equipment in Use at the Source: The anode furnaces currently have no SO2 controls in place. Remaining Useful Life of the Source: ASARCO has not indicated that any of the anode furnaces would need to be replaced during the 20-year capital cost recovery period. Degree of Visibility Improvement: We did not conduct visibility modeling for the anode furnace emissions. However, since the emissions from these units are a small fraction of those from the converters, the expected visibility improvement would be far less than for any of the controls considered for the converters. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 3. Subject-to-BART, BART Analysis and BART Determination for NOX E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules source below the NOX de minimis threshold of 40 tpy. Therefore, because the Hayden Smelter is subject to BART and has a PTE of more than 40 tons per year of NOX, we have analyzed potential NOX BART controls for the source. b. BART Analysis for NOX The Hayden Smelter’s NOX emissions result from the combustion of natural gas to heat process equipment. LNB are an available, feasible and effective technical option for such process heaters, with an estimated control efficiency of 50 percent.109 Cost of Compliance: According to the Documentation Report accompanying AirControlNet, the cost to retrofit process heaters with LNB is $2,200 per ton.110 Energy and Non-Air Quality Environmental Impacts: No significant energy and non-air environmental impacts are expected to result from use of LNB. Pollution Control Equipment in Use at the Source: No NOX controls are currently employed at either the converters or the anode furnaces. Remaining Useful Life of the Source: ASARCO has not indicated that any of the units would need to be replaced during the 20-year capital cost recovery period. Degree of Visibility Improvement: The maximum modeled 98th percentile visibility impact resulting from baseline NOX emissions from the Hayden Smelter is no higher than 0.01 dv111 at any of the Class I areas. Thus, the maximum visibility benefit of controls is less than 0.01 dv. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 c. Proposed BART Determination for NOX Given the small potential for visibility improvement, we propose that controlling these NOX emissions is not warranted for purposes of BART. However, in order to ensure that NOX emissions do not increase in the future, we propose to set a 12-month rolling limit of 40 tons of NOX from the subjectto-BART units, which is equivalent to the de minimis level of emissions set out in the RHR.112 This emission limit is slightly lower than the annual 50 tpy baseline emissions noted above. Nonetheless, we consider it to be a 109 AirControlNet, Version 4.1, documentation report by E.H. Pechan and Associates, Inc. for U.S. EPA, Office of Air Quality, Planning, and Standards, May 2006, section III, page 445. 110 Id. 111 Summary of WRAP RMC BART Modeling for Arizona, Draft Number 5, May 25, 2007. Also, ASARCO response letter, July 11, 2013, ENVIRON memo attachment, March 4, 2012, (‘‘H–09 2013–03– 04 ENVIRON report-Asarco-Hayden-BART.pdf’’. 112 40 CFR 51.308(e)(1)(ii)(C). VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 reasonable limit because the 50 tpy estimate assumes that all of the converters are all operating simultaneously, which is not how they typically operate. Therefore, we expect actual emissions to be well below 40 tpy, which is consistent with ASARCO’s own estimate.113 4. Summary of EPA’s Proposed BART Determinations We propose that BART for SO2 from the converters is a control efficiency of 99.8 percent, 30-day rolling average, on all SO2 captured by the primary and secondary control systems. We propose to require compliance with this requirement within three years of promulgation of a final rule. We also are proposing monitoring, recordkeeping and reporting as well as operation and maintenance requirements, to ensure the enforceability of our proposed BART determination. We propose a work practice standard consistent with current practices for the anode furnaces. We also propose to set a 12-month rolling limit of 40 tons of NOX from the subject-to-BART units. We are seeking comment on all aspects of this proposal. In particular, we are seeking comment on the following elements of our BART analysis and determination for SO2 from the converters: • The cost of controls; • the collection efficiency for the primary collection system; • the collection efficiency for the secondary collection system; • the control efficiency to be applied to the primary and secondary collections systems; • the compliance methodology; and • the compliance schedule. If we receive additional information concerning these or other elements of our analysis, we may finalize a BART determination that differs in some respects from this proposal. D. Miami Smelter Summary: EPA proposes to find that the Miami Smelter is subject to BART for NOX in addition to SO2 and PM10, as determined by the State. For SO2 from the converters, we propose to require construction of a secondary capture system consistent with the requirements of MACT QQQ and an SO2 control efficiency of 99.7 percent, 30day rolling average, on all SO2 captured by the primary and secondary capture systems. For SO2 emissions from the electric furnace, we propose to prohibit 113 Letter from Krishna Parameswaran, ASARCO, to Gregory Nudd, EPA dated March 6, 2013, page 15. PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 9347 active aeration of the electric furnace. For NOX, we propose to find that controlling emissions from the converters and anode furnaces is costeffective, but would not result in sufficient visibility improvement to warrant the cost. Therefore, we are proposing an annual emission limit of 40 tpy NOX emissions from the BARTeligible units at the Miami Smelter, which is consistent with current emissions from these units. We previously approved Arizona’s determination that BART for PM10 at the Miami Smelter is the NESHAP for Primary Copper Smelting. Please refer to the Long Term Strategy in Section VII below, regarding our proposal to ensure the enforceability of this determination. Affected Class I Areas: Twelve Class I areas are within 300 km of the Miami Smelter with the nearest borders ranging from 55 km to 260 km away. The set of areas differs from the ones near the Hayden Smelter only in that Bosque Del Apache WA is included, and Sycamore Canyon WA is not. The baseline visibility impacts are 0.70 dv or less at all Class I areas except at Superstition where the visibility impact is 3.6 dv. The cumulative sum of visibility impacts at all areas within 300 km is 8.2 dv. Facility Overview: The Miami Smelter is a batch-process copper smelter in Gila County, Arizona. We previously approved ADEQ’s determination that Hoboken Converters 2, 3, 4 and 5 and the Electric Furnace at the facility are BART-eligible.114 We also approved ADEQ’s determination that these units are subject to BART for SO2 and that BART for PM10 at the Miami Smelter is the Maximum Achievable Control Technology (MACT) Subpart QQQ under the National Emission Standards for Hazardous Air Pollutants (NESHAP) for primary copper smelting. However, we disapproved ADEQ’s determination that existing controls constitute BART for SO2 and that the units are not subject to BART for NOX. In light of these disapprovals and our FIP duty for Regional Haze in Arizona, we are required to promulgate a FIP to address BART for both SO2 and NOX. Baseline Emissions: Because neither FMMI nor ADEQ identified baseline emissions for the Miami Smelter, we selected emissions from 2010 as the baseline. We chose 2010 because ADEQ provided the most detailed emissions information from this year in its RH SIP and because FMMI used 2010 as a basis for calculating uncaptured emissions of SO2 for 2011 and 2012. FMMI reports 114 78 FR 46412 (July 30, 2013). See also the TSD for a description of these units. E:\FR\FM\18FEP2.SGM 18FEP2 9348 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules emissions of SO2 to ADEQ by stack, and performs a mass-balance equation to determine uncaptured emissions. SO2 emissions in tons per year are presented in Table 34 as reported by FMMI to ADEQ for the acid plant duct, acid plant bypass duct, and the vent fume duct.115 Because each of these stacks vents emissions from both BART and nonBART emission units, EPA apportioned the emissions to BART and non-BART units for purposes of our analysis. The BART-eligible emissions from the acid plant were based on FMMI and ADEQ’s estimate that 35 percent of SO2 sent to the acid plant is emitted by the converters and 65 percent of SO2 is emitted by the primary smelter (often called by a proprietary name, the IsaSmelt furnace) and electric furnace. Because it is not possible to differentiate which converter emissions are from the one converter that is not BART-eligible, we are treating all converter emissions as subject to BART. Subject-to-BART emissions from the vent fume duct were set at seven tons per year based on our estimate of the share of emissions originating from the electric furnace. Please refer to the TSD for an explanation for how the subject-toBART uncaptured emissions are determined. TABLE 34—MIAMI SMELTER: BART BASELINE EMISSIONS FOR SO2 IN 2010 [Tons per year] Acid plant duct Total SO2 Emissions ........................................................................................ Subject-to-BART SO2 Emissions ..................................................................... FMMI also reports potentially BARTeligible NOX emissions from the acid plant duct and from ‘‘natural gas combustion’’ to ADEQ as depicted in Table 35. FMMI estimates that 15 Acid plant bypass 1,415 495 percent of NOX emitted from the acid plant duct originates from the BARTeligible converters. While ‘‘natural gas emissions’’ includes emissions from the converter burners, it is not possible to Vent fume duct 93 33 331 7 Uncaptured 8,472 3,231–8,078 separate the BART-eligible emissions from ineligible emissions. Thus, we are assuming that all these emissions are BART-eligible. TABLE 35—MIAMI SMELTER: BART BASELINE EMISSIONS FOR NOX IN 2010 [Tons per year] Acid plant duct mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Total NOx Emissions ............................................................................................................................................... Subject-to-BART NOX Emissions ............................................................................................................................ Modeling Overview: Using the CALPUFF model, EPA estimated the visibility impacts of the Miami Smelter in its current (i.e., baseline) configuration, and with two different control options for SO2 emissions. Model inputs were developed using work by the WRAP and updated stack and other information from FMMI. EPA made two different emissions calculations, incorporating high and low estimates of the amount of emissions that are not captured by the existing systems. Most of the discussion below focuses on modeling performed using the high estimate as shown in Table 37. An additional complication for this facility is that most of the emissions occur via a ‘‘roofline,’’ a long rectangular hole in the roof of the building containing the converters. Modeling the roofline as if it were a stack may be problematic, especially for nearby Class I areas. Modeling the roofline as a buoyant line source is a better characterization of the source. 115 The vent fume duct is the stack for a wet scrubber used to control emissions collected by the IsaSmelt secondary collection system, other collection systems associated with conveyors that VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 EPA performed sensitivity simulations, described in the TSD, and found that impacts do vary depending on whether it is modeled as a stack or a line source. Which modeling scenario resulted in higher impacts depended on the particular Class I area. EPA therefore modeled the main emissions from FMMI as a buoyant line source, despite the considerably longer model run times. 1. BART Analysis for SO2 From Converters a. Control Technology Availability, Technical Feasibility and Effectiveness We identified two available and feasible technologies to control SO2 emissions from the converters: a double contact acid plant and wet scrubbing. FMMI already uses these two technologies in series to control SO2 emissions currently captured from the converters. Based on SO2 acid plant emissions and sulfuric acid production data provided to EPA by FMMI, we are not BART-eligible, and emissions collected by the BART-eligible electric furnace secondary collection system. PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 154 23 Natural gas combustion 15 15 calculated that the existing acid plant and tail gas scrubber system is controlling at least 99.7 percent of the SO2 ducted to the acid plant,116 which we consider effective. Because FMMI already uses both of the two available control technologies to control SO2 emissions currently captured from the converters and achieves a high degree of control of these emissions, we did not further evaluate additional controls or upgrades to the existing controls as BART. Rather, we evaluated ways to improve the capture efficiency of the existing system so that additional emissions may be collected and controlled. In order to analyze options for improved capture, we requested information from FMMI regarding potential design improvements, upgrades to existing equipment or new equipment that could increase the degree of capture of SO2 emissions from the converters.117 In response, FMMI reported that it planned to improve the 116 Letter from Derek Cooke, FMMI, to Thomas Webb, EPA, Appendices A and C, January 25, 2013. 117 Letter from Thomas Webb, EPA, to Derek Cooke, FMMI (June 27, 2013). E:\FR\FM\18FEP2.SGM 18FEP2 9349 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules converter mouth covers, reconfigure the roofline capture system and route the captured emissions to the existing acid plant.118 Accordingly, we performed a five-factor BART analysis for these improvements, which we refer to collectively as a ‘‘secondary capture system.’’ b. Secondary Capture System The purpose of the secondary capture system is to improve capture and control of SO2 emissions from the converters that can then be directed to the existing double contact acid plant. efficiency of 99.7 percent, which the existing acid plant and tail stack scrubber system currently achieves using very limited cesium catalyst. The emission reduction was applied to 85 percent of the currently uncaptured SO2 emissions from the converters.120 Based on these calculations, we estimate the cost-effectiveness of installing and operating a secondary capture system would be $990 to $2,474 per ton of SO2 removed, as shown in Table 36. This range reflects the uncertainty in the quantity of SO2 emissions that are currently not captured. Cost of Compliance: FMMI claimed as confidential business information (CBI) the cost information for improvements in SO2 capture, so we relied on other information to estimate the cost of controls. In particular, we considered cost estimates supplied by ASARCO for the Hayden Smelter, a similar facility, for a series of upgrades to its capture systems.119 We estimated costeffectiveness using a capital cost of $47,850,000, and annualized those costs assuming a 20-year lifespan and a 7 percent interest rate with an operation and maintenance cost of 50 percent of the capital cost. We applied a control TABLE 36—MIAMI SMELTER: COST OF SECONDARY CAPTURE OF SO2 FROM CONVERTERS Capital cost Annualized capital cost Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $47,850,000 ............................................. $4,516,701 $2,258,351 $6,775,052 2,379–6,845 99.7% $990–2,474 Energy and Non-Air Quality Environmental Impacts: We do not anticipate significant energy or other non-air quality environmental impacts resulting from capturing and ducting additional emissions to the existing SO2 control system given that FMMI already has the capacity to handle and store the much larger quantities of sulfuric acid produced by emissions captured from the IsaSmelt and converter primary capture systems. Pollution Control Equipment in Use at the Source: SO2 emissions collected from the converters are ducted to the four-pass, double contact acid plant. There is a wet scrubber (the tailstack scrubber) located after the acid plant outlet, to which emissions may be vented during periods of elevated SO2 concentrations.121 Remaining Useful Life: The BARTeligible converters have each been in place for about 40 years. FMMI has not indicated that any of them would be replaced during the 20-year capital cost recovery period. Degree of Visibility Improvement: As shown in Table 37, installing a secondary capture system to collect and direct SO2 emissions from the converters to the acid plant, the maximum 98th percentile baseline improvement ranges from a low of 0.41 dv to a high of 1.06 dv at Superstition WA. The cumulative improvement ranges from 1.7 to 4.3 dv. These are large visibility improvements that support using the existing acid plant with a new secondary capture system as BART for SO2. The high and low visibility impacts and improvements in Table 37 correspond to the range of emissions that are not captured. The range is 3,231 (low) to 8,078 (high) tpy. For the low emission estimate, the maximum improvement from the secondary capture system is 0.41 dv, and the cumulative improvement is 1.7 dv. These are considerably less than for the high emission estimate, which has a maximum improvement of 1.06 dv and cumulative improvement of 4.3 dv, but is still substantial. TABLE 37—MIAMI SMELTER: VISIBILITY IMPACT AND IMPROVEMENT FROM SECONDARY CAPTURE SYSTEM Impact Distance (km) mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Class I area Bosque del Apache WA ................................................................... Chiricahua NM ................................................................................. Chiricahua WA ................................................................................. Galiuro WA ....................................................................................... Gila WA ............................................................................................ Mazatzal WA .................................................................................... Mount Baldy WA .............................................................................. Petrified Forest NP .......................................................................... Pine Mountain WA ........................................................................... Saguaro NP ..................................................................................... Sierra Ancha WA ............................................................................. Superstition WA ............................................................................... 118 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Item 2 (July 12, 2013). FMMI indicated that ‘‘[t]hese proposed changes are in anticipation of measures that may be adopted by ADEQ as necessary to demonstrate compliance’’ with the 2012 SO2 NAAQS.’’ Regardless of their regulatory VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 235 113 125 99 55 220 95 197 260 143 158 163 Improvement from control Impact Improvement from control High base case (basehi) Converter 85% capture (opt1hi) Low base case (baselo) Converter 85% capture (opt1lo) 0.15 0.36 0.35 0.56 0.34 0.64 0.27 0.33 0.43 0.45 0.70 3.61 purpose of the changes, FMMI’s proposal indicates that these changes are technically feasible. 119 See the TSD, Section III.D.4. 120 Review of New Source Performance Standards for Primary Copper Smelters, OAQPS, EPA 450/3– PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 0.12 0.27 0.27 0.40 0.26 0.44 0.20 0.25 0.32 0.34 0.40 1.06 0.07 0.16 0.16 0.28 0.16 0.32 0.13 0.16 0.20 0.21 0.42 2.86 0.05 0.10 0.10 0.17 0.10 0.17 0.08 0.10 0.12 0.13 0.17 0.41 83–018a, March 1984. According to Section 4.7.6.3, the overall collection efficiency of secondary fixed hoods is approximately 90 percent. 121 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Item 2 (July 12, 2013). E:\FR\FM\18FEP2.SGM 18FEP2 9350 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 37—MIAMI SMELTER: VISIBILITY IMPACT AND IMPROVEMENT FROM SECONDARY CAPTURE SYSTEM—Continued Impact Improvement from control Impact Improvement from control Converter 85% capture (opt1hi) Low base case (baselo) Converter 85% capture (opt1lo) Class I area Distance (km) High base case (basehi) Cumulative (sum) ............................................................................. Maximum .......................................................................................... # CIAs >= 0.5 dv .............................................................................. Million $/dv (cumul. dv) .................................................................... Million $/dv (max. dv) ....................................................................... .................... .................... .................... .................... .................... 8.2 3.61 4 ...................... ...................... c. Proposed BART Determination for SO2 From Converters mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Based on the results of our BART analysis, we propose that BART for SO2 from the converters is construction of a secondary capture system (i.e., construction of hooding and ventilation systems to capture escaped SO2 emissions) and ducting the emissions to existing controls. We have determined that these improvements are feasible and cost-effective, will result in significant visibility improvements, and should not result in significant adverse impacts. As noted above, the RHR allows for use of equipment requirements or work practice standards in lieu of a numeric limit where ‘‘technological or economic limitations on the applicability of measurement methodology to a particular source would make the imposition of an emission standard infeasible.’’ 122 In this instance, we propose to find that technological limitations on the source’s ability to measure accurately uncaptured SO2 emissions make numeric capture efficiency infeasible. Therefore, we are proposing to prescribe specific equipment for capture of SO2 emissions, in addition to numeric control efficiency and related compliance requirements. Specifically, we are proposing the following as BART for SO2 from the converters: • Construction of a secondary capture system consistent with the requirements of MACT QQQ as a work practice standard. • An SO2 control efficiency of 99.7 percent, 30-day rolling average, on all 122 40 CFR 51.308(e)(1)(iii). See also 40 CFR 51.100(z)(defining ‘‘emission limitation’’ and ‘‘emission standard’’ to include ‘‘any requirements which . . . prescribe equipment . . . for a source to assure continuous emission reduction.’’ VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 SO2 captured by the primary and secondary capture systems. • Compliance with the SO2 BART limit may be verified either through the use of SO2 CEMS before and after controls or by using post-control CEMS and acid production rates. A limit of 4.06 lbs SO2 emissions per tons of sulfuric acid production is equivalent to 99.7 percent control. d. Alternative Control Efficiency We are also seeking comment on whether FMMI should be expected to meet a 99.8 percent control efficiency, 30-day rolling average, on all SO2 captured by the primary and secondary capture systems. ASARCO Hayden has demonstrated that a control efficiency of 99.8 percent is achievable in practice at a batch copper smelter. FMMI could increase control efficiency by increasing its use of cesium promoted catalyst in the acid plant, increasing the volume of gas exiting the acid plant that is further controlled by the tail stack scrubber, and/or using sodium rather than magnesium in the scrubbing liquor. If we received comments establishing that a control efficiency greater than 99.7 percent is achievable at FMMI, we may finalize a control efficiency of up to 99.8 percent. 4.3 1.06 1 $1.6 $6.4 5.1 2.86 1 ...................... ...................... 1.7 0.41 0 $4.0 $16.7 emissions from the electric furnace are already controlled by the existing double contact acid plant and tail stack scrubber.123 In addition, a secondary capture system ducts gases not captured by the primary capture system to the vent fume scrubber, which has a control efficiency of 80 percent. Because FMMI already uses both of the two available control technologies to control SO2 emissions currently captured from the furnace, we did not evaluate the addition of new controls, nor did we evaluate upgrades to the acid plant system, which already achieves a high degree of control. The one improvement to controls that we identified was upgrading the scrubber, which currently uses magnesium oxide, to use sodium hydroxide, which could increase the control efficiency from 80 percent to 98 percent. b. Existing Double Contact Acid Plant and Wet Scrubbing a. Control Technology Availability, Technical Feasibility and Effectiveness EPA identified two possible technologies to control SO2 emissions from the electric furnace: Double contact acid plant and wet scrubbing. FMMI has indicated to EPA that Cost of Compliance: We estimated the emissions from the electric furnace by multiplying the relevant AP 42 emission factors for copper smelters 124 by the 2010 concentrate throughput provided by FMMI. This results in uncontrolled emissions of SO2 from the electric furnace of 379 tons per year. Because the scrubber is a secondary control device, however, this would likely result in an emissions decrease of no more than 5 to 10 tons per year. Replacing magnesium oxide with sodium hydroxide would cost at least $2,000,000 per year, resulting in control costs of $200,000–$400,000 per ton of SO2 removed, as shown in Table 38. 123 ADEQ Class 1 Permit Number 53592, Application for a Significant Permit Revision, July, 2013. 124 AP 42, Chapter 12.3, Primary Copper Smelters, Table 12.3–3 (cleaning furnace) and Table 12.3–11 (converter slag return). 2. BART Analysis for SO2 From Electric Furnace PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 9351 TABLE 38—MIAMI SMELTER: COST OF UPGRADING VENT FUME SCRUBBER Annualized capital cost mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Energy and Non-Air Quality Environmental Impacts: We do not anticipate significant energy or non-air quality environmental impacts resulting from capturing and ducting additional emissions to the existing SO2 control system. Non-air quality impacts from venting additional captured emissions to the existing scrubber are not expected to be significant given that FMMI is already controlling much larger quantities of SO2 in the existing scrubber and managing the wastewater and sludge that result. Pollution Control Equipment in Use at the Source: SO2 emissions collected from the electric furnace are ducted to the four-pass, double contact acid plant. There is a wet scrubber (the tailstack scrubber) located after the acid plant outlet, to which emissions may be vented ‘‘if needed.’’ In addition, gases collected from the secondary collection system are ducted to the vent fume scrubber, which is another wet scrubber. The vent fume scrubber also controls secondary emissions from the IsaSmelt and emissions collected from other equipment. Remaining Useful Life: FMMI has not indicated any plans to remove the electric furnace from service. Degree of Visibility Improvement: Our modeling results did not demonstrate even modest visibility improvements at any Class I areas from this option. Improvements were 0.004 dv or less at each Class I area, and only 0.008 dv for the cumulative sum over all areas. These are negligible visibility improvements over the baseline levels, as expected from the small emission reductions associated with this option. c. BART Determination for Electric Furnace Based on the high cost of compliance to upgrade the vent fume scrubber and low potential for visibility improvement, we are proposing that existing controls represent BART for SO2 emissions from the electric furnace. While we would prefer to set a numeric emission limit in order to ensure that SO2 emissions from the electric furnace do not increase in the future, such a limit is impracticable because emissions from the electric furnace are commingled with emissions from nonBART eligible units in the vent fume stack. Therefore, consistent with 40 CFR VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Annual variable cost Total annual cost Tons SO2 reduced Control efficiency $/ton SO2 removed $2,000,000 Capital cost $2,000,000 5–10 98% $200,000–$400,000 51.308(e)(1), we propose a work practice standard prohibiting active aeration of the electric furnace. 3. BART Analysis for NOX From Process Heaters NOX emissions from the FMMI smelter result from the combustion of natural gas to heat process equipment. According to the Documentation Report accompanying AirControlNet, the cost to retrofit process heaters with low NOX burners, which can reduce NOX emissions by 50 percent, is $2,200 per ton.125 Although this is not necessarily cost-prohibitive, there is relatively little potential for visibility improvement from installation of any NOX controls at FMMI. In particular, the maximum modeled 98th percentile visibility impact resulting from baseline NOX emissions from FMMI is 0.11 dv.126 In addition, the WRAP estimated the annual BART-eligible NOX emissions from the facility as 159 tons per year,127 whereas we estimate annual BARTeligible NOX baseline emissions as 38 tons per year. Therefore, the baseline visibility impact attributable to NOX, and thus, the potential for visibility improvement due to NOX reductions, is, in fact, significantly less than 0.11 dv. Given the small potential for visibility improvement, we propose that NOX controls are not warranted for purposes of BART. However, in order to ensure that NOX emissions do not increase in the future, we propose to set a 12-month rolling cap of 40 tons of NOX from the subject-to-BART units, which is equivalent to the de minimis level of emissions set out in the RHR and is roughly equivalent to current annual emissions from these units.128 VI. EPA’s Proposed Reasonable Progress Analyses and Determinations Summary: In this section, EPA addresses point sources for NOX, area sources for NOX and SO2, the reasonable progress goals for the Class I areas, and a demonstration that the rate of progress is reasonable compared to the URP. In 125 AirControlNet, Version 4.1, Documentation Report. Prepared by E.H. Pechan and Associates, Inc. for U.S. EPA, Office of Air Quality, Planning, and Standards. May, 2006, section III, page 445. 126 Summary of WRAP RMC BART Modeling for Arizona, Draft Number 5, May 25, 2007, page 23. 127 Id. 128 40 CFR 51.308(e)(1)(ii)(C). PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 our previous actions on the Arizona RH SIP, EPA narrowed the focus of the RP analysis to point sources of NOX and area sources of NOX and SO2. Based on our analysis, we propose to require emissions reductions consistent with SNCR on Kiln 4 at the Phoenix Cement Clarkdale Plant and on Kiln 4 at the CalPortland Cement Rillito Plant. EPA proposes to find that it is not reasonable to require additional controls on area sources of NOX and SO2 at this time. We are also proposing RPGs consistent with a combination of control measures that include the approved Arizona RH SIP measures as well as the finalized and proposed Arizona RH FIP measures. Finally, we propose to find that it is not reasonable for any of Arizona’s Class I areas to meet the URP during this planning period, and demonstrate that rate of progress is reasonable based on our RP analysis. Background: The RHR requires the State, or EPA in the case of a FIP, to set RPGs by considering four factors: ‘‘the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and the remaining useful life of any potentially affected sources’’ (collectively ‘‘the RP factors’’).129 The RPGs must provide for an improvement in visibility on the worst days and ensure no degradation in visibility on the best days during the planning period. Furthermore, if the projected progress for the worst days is less than the Uniform Rate of Progress (URP), then the state or EPA must demonstrate, based on the factors above, that it is not reasonable to provide for a rate of progress consistent with the URP.130 In our final rule on the Arizona RH SIP published on July 30, 2013, we partially approved and partially disapproved the State’s RP analysis.131 In particular, we approved the State’s decision to focus on NOX and SO2 sources and its decision not to require additional controls on non-BART point sources of SO2 for this planning period. However, we disapproved the State’s RPGs for the worst days and best days, as well as its RP analyses and determinations for point sources of NOX 129 40 CFR 51.308(d)(1)(i)(A). CFR 51.308(d)(1)(ii). 131 See 78 FR 46173 (codified at 40 CFR 52.145(g)). 130 40 E:\FR\FM\18FEP2.SGM 18FEP2 9352 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules as well as area sources of SO2 and NOX. Accordingly, we have analyzed these remaining source categories to determine whether additional controls are reasonable based on an evaluation of the RP factors. A. Reasonable Progress Analysis of Point Sources for NOX EPA conducted an extensive statewide analysis of NOX point sources to determine whether cost-effective controls on sources near Class I areas would contribute to visibility improvements. In this section, we describe the process to identify and analyze these potentially affected NOX point sources for reasonable progress. Of the nine point sources evaluated for reasonable progress, EPA is proposing to require Phoenix Cement Clarkdale Plant and CalPortland Cement Rillito Plant to comply with new emissions limits for NOX based on the analysis presented below and in the TSD available in the docket. We are seeking comment on our analyses and proposed determinations for all the identified sources. 1. Identification of NOX Point Sources To identify point sources in Arizona that potentially affect visibility in Class I areas, EPA examined the annual emissions data from the WRAP 2002 planning inventory and identified those sources with facility-wide actual emissions that exceed 250 tpy of NOX or SO2. For these sources, we calculated the total actual emission rate (Q) in tpy of NOX and SO2 and determined the distance (D) in kilometers of each source to its closest Class I area.132 We employed a contractor to prepare an initial spreadsheet calculating these Q and D values.133 We used a Q divided by D value of ten as a threshold for further evaluation of RP controls. We selected this value based on guidance contained in the BART Guidelines, which state: Based on our analyses, we believe that a State that has established 0.5 deciviews as a contribution threshold could reasonably exempt from the BART review process sources that emit less than 500 tpy of NOX or SO2 (or combined NOX and SO2), as long as these sources are located more than 50 kilometers from any Class I area; and sources that emit less than 1000 tpy of NOX or SO2 (or combined NOX and SO2) that are located more than 100 kilometers from any Class I area.134 The approach described above corresponds to a Q/D threshold of ten. In addition, the use of a Q/D threshold of ten or greater is recommended by the Federal Land Managers’ Air Quality Related Values Work Group (FLAG) as a screening threshold, as described in the FLAG 2010 Phase I Report.135 A summary of sources with a Q/D value greater than 10 is included in Table 39. TABLE 39—SOURCES OF NOX WITH Q/D VALUE GREATER THAN 10 Q (tpy) Facility name Arizona Public Service .......................................... CalPortland Cement Co ........................................ Arizona Electric Power Coop ................................ Arizona Public Service .......................................... Lhoist North America ............................................ El Paso Natural Gas Co ....................................... El Paso Natural Gas Co ....................................... Tucson Electric Power .......................................... Lhoist North America ............................................ Freeport-McMoRan ............................................... Phoenix Cement ................................................... Pima County ......................................................... ASARCO ............................................................... Salt River Project .................................................. Salt River Project .................................................. Catalyst Paper Abitibi ........................................... Salt River Project .................................................. Tucson Electric Power .......................................... El Paso Natural Gas Co ....................................... mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Owner/operator West Phoenix Plant .............................................. Rillito Plant ........................................................... Apache Generating Station .................................. Cholla Power Plant ............................................... Douglas Lime Plant .............................................. Tucson Compressor Station ................................. Flagstaff Compressor Station ............................... Sundt Generating Station ..................................... Nelson Lime Plant ................................................ Miami Smelter ...................................................... Clarkdale Plant ..................................................... Ina Road Sewage Plant ....................................... Smelter and Mill ................................................... Coronado Generating Station .............................. San Tan Generating Station ................................ Snowflake Pulp Mill .............................................. Aqua Fria Generating Station .............................. Springerville Generating Station .......................... Williams Compressor Station ............................... 992 5,075 11,840 33,588 755 336 1,010 5,659 2,556 5,996 2,744 258 18,486 29,674 335 5,143 994 32,434 1,373 D (km) 73.10 6.99 44.86 31.75 55.16 14.72 34.94 15.84 24.56 15.58 12.65 12.56 47.22 48.53 28.13 39.36 68.87 60.46 19.12 Q/D 14 726 264 1058 14 23 29 357 104 385 217 21 392 611 12 131 14 536 72 Of the sources listed in Table 39, we eliminated several sources from further consideration by calculating updated Q/ D values based on 2008–2010 emission data.136 As a result, APS West Phoenix Plant, Lhoist Douglas Plant, SRP San Tan Generating Station, and SRP Agua Fria Generating Station have Q/D values less than or equal to ten. Thus, we eliminated these sources from further consideration for this planning period. However, if any of these sources resume operations at levels sufficient to increase their Q/D value to ten or greater, Arizona should consider them for potential RP controls in the next planning period. Finally, we eliminated from further consideration those sources (or units at sources) that were evaluated under BART. These include the Apache Generating Station, Coronado Generating Station, Cholla Power Plant (except Unit 1), Sundt Generating Station (except for Units 1–3), Snowflake Pulp and Paper Mill, and Nelson Lime Plant. Because the BART analysis examines many of the same factors as those evaluated for reasonable progress, we propose that the BART determinations for these facilities satisfy the requirement for reasonable progress from these facilities during this planning period. The final list of sources considered for reasonable progress NOX controls is summarized in Table 40. 132 The analysis included NO , SO , and X 2 particulate matter pollutants because we had not yet approved ADEQ’s determination to focus on NOX and SO2, nor had we approved its conclusion regarding non-BART SO2 point sources, at the time this screening analysis was performed. 133 ‘‘EP–D–07–102 WA5–12 Task4 Deliverable (AZ–BART-QbyD-Screening-report)-final.xlsx’’. 134 See 40 CFR part 51, app. Y, § III (How to Identify Sources ‘‘Subject to BART’’). 135 Section 3.2, Initial Screening Criteria (New), Federal Land Managers’ Air Quality Related Values Work Group (FLAG) Phase I Report—Revised (2010). 136 See spreadsheet ‘‘10D Screening Update— 2008–10 Emission Data.xlsx’’ in the docket. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9353 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 40—SOURCES OF NOX FOR REASONABLE PROGRESS ANALYSES Owner/operator Facility name CalPortland Cement Co .................................................... Arizona Public Service ...................................................... El Paso Natural Gas Co ................................................... El Paso Natural Gas Co ................................................... Tucson Electric Power ...................................................... Phoenix Cement ............................................................... Pima County ..................................................................... Tucson Electric Power ...................................................... El Paso Natural Gas Co ................................................... Rillito Plant. Cholla Power Plant (Unit 1) ............................................ Tucson Compressor Station. Flagstaff Compressor Station. Sundt Generating Station (Units 1–3) ............................. Clarkdale Plant. Ina Road Sewage Plant. Springerville Generating Station (Units 1–2) .................. Williams Compressor Station. 2. Analysis of Potentially Affected NOX Point Sources EPA contracted with the University of North Carolina (UNC) and their subcontractor, Andover Technology Partners (ATP), to perform RP analyses for the nine sources listed in Table 40. EPA considered the four RP factors for each of these sources based on the work from UNC. In addition, for the larger point sources (EGUs and cement kilns), we conducted CALPUFF modeling to assess the potential visibility benefits of controls.137 These analyses are set out in the TSD and are summarized in the following sections. a. Phoenix Cement Clarkdale Plant Kiln 4 Costs of Compliance: This facility consists of one precalciner kiln, which currently uses LNB for NOX control. Our estimate of costs of compliance is based primarily on estimates provided by PCC in their March 6, 2013 comment letter, with revisions to certain cost items we considered to be unreasonable or not allowed by EPA’s Control Cost Manual.138 As explained in further detail in the TSD, we estimated a total annual cost for SNCR of approximately $940,000 per year. SNCR is estimated to reduce emissions at the kiln by 810 tpy at a cost of $1,142/ton, based on baseline emissions of 1620 tpy and a 50 percent SNCR control efficiency. As explained in the TSD, we are seeking comment on whether a different SNCR control efficiency is appropriate for this kiln. If we receive technical information demonstrating that a different SNCR control efficiency is appropriate for Kiln 4, we will incorporate this change into our analysis. Time Necessary for Compliance: We expect that SNCR could be installed in approximately 3 years from the final date of this action. The Institute of Clean Air Companies estimates that the installation time for SNCR on industrial sources is 10–13 months.139 CPCC estimates that it would require approximately three years to install SNCR on their similar technology kiln. Given these two pieces of information, a 3-year timeframe appears to be reasonable. Energy and Non-Air Quality Environmental Impacts of Compliance: The installation and operation of SNCR at the plant would require a small increase in energy usage. The cost of this additional energy usage is included in the cost analysis. Non-air quality environmental impacts associated with SNCR include the hazards of Notes Units 2–4 subject to BART. Unit 4 subject to BART. Units 3–4 have SCR. transporting and storing urea or ammonia, especially if anhydrous ammonia is used. However, since the handling of anhydrous ammonia will involve the development of a risk management plan (RMP), we consider the associated safety issues to be manageable as long as established safety procedures are followed. Therefore, we find that these impacts are not sufficient to warrant eliminating SNCR as a control option. Remaining Useful Life: EPA presumes that the kiln would continue operating for 20 years and fully amortize the cost of controls. Degree of Improvement in Visibility: There are twelve Class I areas within 300 km of the Clarkdale Plant. As shown in Table 41, the highest 98th percentile baseline visibility impact of Phoenix Cement is 5.2 dv at Sycamore. Pine Mountain, Mazatzal, and the Grand Canyon all have visibility impacts over 0.5 dv, and other areas are at 0.1 dv or less. The cumulative sum of visibility impacts over all the Class I areas is 7.5 dv. The maximum visibility improvement due to SNCR is 1.9 dv at Sycamore, 0.3 dv at Pine Mountain, and slightly less at Mazatzal and the Grand Canyon. The cumulative improvement from SNCR is 3.0 dv. TABLE 41—PHOENIX CEMENT KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Distance (km) mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Class I Area Bryce Canyon NP ................................................................................................................................ Galiuro WA .......................................................................................................................................... Grand Canyon NP ............................................................................................................................... Mazatzal WA ........................................................................................................................................ Mount Baldy WA .................................................................................................................................. Petrified Forest NP .............................................................................................................................. Pine Mountain WA ............................................................................................................................... 137 While visibility is not an explicitly listed factor to consider when determining whether additional controls are reasonable, the purpose of the four-factor analysis is to determine what degree of progress toward natural visibility conditions is reasonable. Therefore, it is appropriate to consider VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 the projected visibility benefit of the controls when determining if the controls are needed to make reasonable progress. 138 Comments submitted on EPA’s December 21, 2012 proposed rulemaking partially approving and PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 296 278 133 59 249 200 56 Visibility improvement Base case (base) SNCR ¥50% NOX (ctrl2) 0.09 0.03 0.51 0.51 0.05 0.21 0.66 0.04 0.01 0.25 0.24 0.02 0.10 0.32 disapproving Arizona’s Regional Haze Plan. 77 FR 75704. 139 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. E:\FR\FM\18FEP2.SGM 18FEP2 9354 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules TABLE 41—PHOENIX CEMENT KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS—Continued Visibility impact Saguaro NP ......................................................................................................................................... Sierra Ancha WA ................................................................................................................................. Superstition WA ................................................................................................................................... Sycamore Canyon WA ........................................................................................................................ Zion NP ................................................................................................................................................ Cumulative (sum) ................................................................................................................................. Maximum ............................................................................................................................................. # CIAs >= 0.5 dv ................................................................................................................................. Million $/dv (cumul. dv) ........................................................................................................................ Million $/dv (max. dv) .......................................................................................................................... Phoenix Cement is only 10.5 km away from the Sycamore Canyon Wilderness. Therefore NOX emitted by the Plant may not be fully converted to NO2 by the time it reaches Sycamore Canyon and may not be fully available to form visibility-degrading particulate nitrate. However, the CALPUFF model assumes 100 percent conversion. EPA explored this issue by scaling back the visibility Base case (base) Distance (km) Class I Area extinction due to NO2 and nitrate to reflect lower NO-to-NO2 conversion rates, described further in the TSD. As shown in Table 42, EPA found that visibility impacts and the improvement due to SNCR decrease along with the percent conversion assumed. However, the benefit of SNCR is 0.52 dv when NO conversion is reduced to 25 percent. Even for an unrealistically low 284 142 151 10 272 .................... .................... .................... .................... .................... Visibility improvement SNCR ¥50% NOX (ctrl2) 0.03 0.09 0.10 5.15 0.09 7.5 5.15 4 ...................... ...................... 0.01 0.04 0.05 1.85 0.05 3.0 1.85 1 $0.3 $0.5 assumption of 10 percent (i.e., no conversion of NO to NO2 after the plume leaves the stack), the benefit of SNCR is 0.25 dv at Sycamore Canyon alone. Because the other Class I Areas are far enough away for NOX emitted by the Plant to be fully converted to NO2, the benefits at the other Class I areas would remain the same. TABLE 42—BENEFIT OF SNCR ON PHOENIX CEMENT AT SYCAMORE CANYON FOR VARIOUS NO-TO-NO2 CONVERSION RATES NO % Conversion 100% Base case ................................................................................................ SNCR ....................................................................................................... Benefit ...................................................................................................... Proposed RP Determination: Based on our analysis of the four RP factors, as well as the expected degree visibility improvement, EPA proposes to require compliance with an emission limit of 2.12 lb/ton on Kiln 4 based on a 30-day rolling average basis.140 We propose to find that this emissions limit, equivalent to SNCR control, is cost-effective at $1,142/ton and would result in significant visibility benefits at Sycamore Canyon Wilderness Area. We are proposing to require compliance with the 2.12 lb/ton limit by December 31, 2018. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 140 The basis for this specific emission rate is described in the TSD. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 75% 5.14 3.30 1.85 We are also soliciting comment on the possibility of establishing an annual cap on NOX emissions from Kiln 4 in lieu of a lb/ton emission limit. Such a cap would provide additional flexibility to PCC by allowing them to comply either by installing controls or by limiting production. In particular, we are seeking comment on an annual NOX emission cap for Kiln 4 of 810 tpy established on a rolling 12-month basis, effective December 31, 2018. If production remains at current levels, PCC could meet this cap without installing any additional controls. However, if production increases to pre-2008 levels, we expect that PCC would need to install SNCR on Kiln 4 to comply with the cap. PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 50% 4.19 2.68 1.51 3.13 2.07 1.06 25% 10% 1.94 1.42 0.52 1.17 0.92 0.25 b. CalPortland Cement Rillito Plant Kilns 1–4 The facility consists of three long dry kilns (Kilns 1–3) and one precalciner kiln (Kiln 4). Due to the significant differences between long dry kilns and precalciner kilns, we have separately analyzed Kilns 1–3 and Kiln 4. 1. Rillito Plant Kilns 1–3 Kilns 1–3 have not operated since 2008 due to economic conditions. However, CPCC retains the ability to start using these kilns again at any time. Therefore, we conducted an analysis of the kilns using pre-2008 emission levels. E:\FR\FM\18FEP2.SGM 18FEP2 9355 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Costs of Compliance: Our estimate of the costs of compliance is based primarily on estimates provided by CalPortland in its RP analysis, with revisions to certain cost items we considered to be unreasonable or not allowed by EPA’s Control Cost Manual.141 Our analysis identified SNCR with Mixing Air Technology (MAT) as the most cost-effective control technology. Installation of SNCR with MAT on Kilns 1–3 is estimated to reduce emissions at each kiln by 182 tpy at a cost of $5,603/ton reduced, based on an annualized cost of approximately $1 million per year and 30-percent control efficiency for SNCR.142 Time Necessary for Compliance: CPCC estimates that the time needed to install the control equipment is about 3 years. Energy and Non-Air Quality Environmental Impacts of Compliance: The installation and operation of SNCR at the plant would require a small increase in energy usage. The cost of this additional energy usage is included in the cost analysis. Non-air quality environmental impacts associated with SNCR include the hazards of transporting and storing urea or ammonia, especially if anhydrous ammonia is used. However, since the handling of anhydrous ammonia will involve the development of an RMP, we consider the associated safety issues to be manageable as long as established safety procedures are followed. Therefore, we find that these impacts are not sufficient to warrant eliminating SNCR as a control option. Remaining Useful Life: The plant’s owner intends to shut down all four kilns and replace them with a new kiln that would be subject to Best Available Control Technology and a visibility impact analysis.143 This project has been on hold while the economy in Arizona recovers. As a result, it is unclear whether these kilns will be in service long enough to fully amortize the cost of controls. However, because there is no enforceable shutdown date at this time, we assume that the kilns will remain in service for a 20-year amortization period. Degree of Improvement in Visibility: The maximum visibility improvement due to SNCR on Kilns 1–3 is 0.22 dv at the eastern unit of Saguaro NP, 0.18 dv at Galiuro WA, and smaller for other areas. The cumulative visibility improvement is 0.7 dv. TABLE 43—CALPORTLAND CEMENT KILNS 1–3 AND KILN 4: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Distance (km) Class I area Chiricahua NM ........................................................................................................... Chiricahua WA ........................................................................................................... Galiuro WA ................................................................................................................ Gila WA ...................................................................................................................... Mazatzal WA .............................................................................................................. Mount Baldy WA ........................................................................................................ Petrified Forest NP .................................................................................................... Pine Mountain WA ..................................................................................................... Saguaro NP ............................................................................................................... Sierra Ancha WA ....................................................................................................... Superstition WA ......................................................................................................... Sycamore Canyon WA .............................................................................................. Cumulative (sum) ....................................................................................................... Maximum ................................................................................................................... # CIAs >= 0.5 dv ....................................................................................................... Million $/dv (cumul. dv) .............................................................................................. Million $/dv (max. dv) ................................................................................................ 171 170 73 240 171 223 290 213 8 153 108 287 .................... .................... .................... .................... .................... Base case (c0) 0.25 0.23 1.02 0.12 0.13 0.11 0.11 0.11 1.26 0.13 0.30 0.09 3.9 1.26 2 ...................... ...................... Visibility improvement SNCR on Kilns 1, 2, 3 (c22) 0.05 0.05 0.18 0.02 0.02 0.03 0.02 0.02 0.22 0.02 0.06 0.02 0.7 0.22 0 $1.5 $4.8 SNCR on Kiln 4 (c24) 0.06 0.05 0.19 0.03 0.03 0.03 0.03 0.02 0.24 0.03 0.06 0.02 0.8 0.24 0 $1.4 $4.6 The Saguaro NP results in this table are for the eastern unit of the park only. Costs of Compliance: Our estimate of the costs of compliance is based primarily on estimates provided by CalPortland in its RP analysis, with revisions to certain cost items we considered to be unreasonable or not allowed by EPA’s Control Cost Manual.144 Our analysis identified the addition of SNCR to the existing LNB as the most cost-effective available control technology. As explained in further detail in the TSD, we estimated a total annual cost for SNCR of approximately $1.1 million per year. SNCR is estimated to reduce emissions by 1,041 tpy at a cost of $1,047/ton reduced, based on baseline emissions of 2,082 tons per year and a 50 percent SNCR controlefficiency. As explained in the TSD, we are seeking comment on whether a different SNCR control efficiency is appropriate for Kiln 4. If we receive technical information demonstrating that a different SNCR control efficiency is appropriate for Kiln 4, we will incorporate this change into our analysis. Energy and Non-Air Quality Environmental Impacts of Compliance: The installation and operation of SNCR at the plant would require a small increase in energy usage. The cost of this additional energy usage is included in the cost analysis. Non-air quality environmental impacts associated with SNCR include the hazards of 141 ‘‘Reasonable Progress Analysis for CalPortland Company Rillito Cement Plant Kiln, prepared by CalPortland Company.’’ Submitted to EPA May 9, 2013. 142 See TSD for an analysis of all control options and associated control efficiencies and control costs. 143 See Arizona RH SIP supplement, page 32. 144 ‘‘Reasonable Progress Analysis for CalPortland Company Rillito Cement Plant Kiln, prepared by CalPortland Company.’’ Submitted to EPA May 9, 2013. Proposed RP Determination: Given the lack of emissions from Kilns 1–3 over the last five years and the relatively high cost of controls ($5,603/ton), EPA proposes to find that requiring controls for these units is not reasonable at this time. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2. Rillito Plant Kiln 4 VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9356 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules transporting and storing urea or ammonia, especially if anhydrous ammonia is used. However, since the handling of anhydrous ammonia will involve the development of an RMP, we consider the associated safety issues to be manageable as long as established safety procedures are followed. Therefore, we find that these impacts are not sufficient to warrant eliminating SNCR as a control option. Existing Pollution Control Equipment: Kiln 4 is a precalciner kiln that currently uses LNB for NOX control. Remaining Useful Life: The plant’s owner intends to shut down all four kilns and replace them with a new kiln that would be subject to Best Available Control Technology and a visibility impact analysis.145 This project has been on hold while the economy in Arizona recovers. As a result, it is unclear whether these kilns will be in service long enough to fully amortize the cost of controls. However, because there is no enforceable shutdown date at this time, we assume that the kilns will remain in service for a 20-year amortization period. Degree of Improvement in Visibility: As shown in Table 43, the maximum visibility improvement due to SNCR on Kiln 4 is 0.24 dv at the eastern unit of Saguaro NP, 0.19 dv at Galiuro WA, and smaller for other areas. The cumulative visibility improvement is 0.8 dv. The cumulative visibility improvement from SNCR on all four kilns would be about 1.5 dv. As discussed above in the section covering visibility improvements for TEP Sundt, EPA remodeled impacts at Saguaro NP to address both the eastern and western units of the park. The modeled visibility impact at the western unit of Saguaro, not shown in the table, is 6.04 dv, far greater than at the eastern unit. The modeled improvement there due to SNCR is 0.30 dv, still rather modest but 25 percent greater than for the eastern unit. However, CalPortland is only 7.8 km away from the western unit, so its emitted NOX may not be fully converted to NO2 by the time it reaches there, as is assumed in the CALPUFF model. It thus may not be fully available to form visibilitydegrading particulate nitrate. EPA explored this issue by scaling back the visibility extinction due to NO2 and nitrate to reflect lower NO-to-NO2 conversion rates, described further in the TSD. EPA found that visibility impacts and the improvement due to SNCR decrease along with the percent conversion assumed, so much so that at a 25 percent conversion rate, the SNCR benefit was only 0.05 dv. Therefore, EPA is relying on impacts and improvements for the more distant eastern unit of Saguaro NP. Proposed RP Determination: EPA finds that SNCR is cost-effective for Kiln 4 at $1,047/ton, would not result in undue non-air quality environmental impacts, and would result in modest visibility benefits at Saguaro NP and Galiuro WA. Therefore, we propose to determine that it is reasonable to require SNCR at Kiln 4. In particular, EPA proposes to require compliance with an emissions limit of 2.67 lb/ton at Kiln 4 based on a 30-day rolling average by December 31, 2018.146 We are also soliciting comment on the possibility of requiring an annual cap on NOX emissions in lieu of a lb/ton emission limit. In order to avoid a shift in production from Kiln 4 to Kilns 1–3, we are proposing that the cap would apply to all four kilns. In particular, we are seeking comment on an annual NOX emission cap for Kilns 1–4 of 2,082 tpy, established on a rolling 12-month basis. CPCC could meet this cap either by retaining production at current levels, or by increasing production and installing SNCR on Kiln 4. We are proposing to require compliance with this rolling 12month limit by December 31, 2018. c. APS Cholla Unit 1 Costs of Compliance: Unit 1 is a 1,246 MMBtu/hr tangential coal-fired boiler, which currently employs LNB with separated overfire air (SOFA) for NOX control. EPA identified two feasible additional controls: SNCR and SCR. The estimated emission reductions and costs for these two options are summarized in Tables 44 and 45. TABLE 44—CHOLLA UNIT 1: NOX EMISSION ESTIMATES NOX emissions Control option (lb/MMBtu) Baseline (LNB+OFA) ....................................................................................... SNCR ............................................................................................................... SCR ................................................................................................................. (lb/hr) 0.22 0.15 0.05 Emission reduction (tpy) 274 192 62 (tpy) 1,032 723 235 310 798 TABLE 45—CHOLLA UNIT 1: NOX CONTROL COST ESTIMATES Total capital cost mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Baseline (LNB+OFA) SNCR ....................................................... SCR .......................................................... 145 See Arizona RH SIP supplement, page 32. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Annualized capital cost Annual O&M costs Total annual cost ($) Control option ($) ($) ($) $2,272,000 26,437,190 $241,725 2,812,730 $918,875 1,425,137 Ave $1,160,599 4,237,867 146 See TSD for a discussion of how this emission limit was calculated. PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM Cost-effectiveness ($/ton) 18FEP2 $3,748 5,313 Incr $6,307 9357 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Time Necessary for Compliance: Given the estimate from the Institute of Clean Air Companies147 that about a year is required to install SNCR, and the estimate of three years for installing SNCR on a cement kiln discussed previously in this notice, EPA estimates that SNCR could be installed in less than three years. In our previous Arizona FIP action, EPA estimated that 5 years would be required to install SCR on coal-fired boilers.148 That estimate also holds for this source. Energy and Non-Air Quality Environmental Impacts of Compliance: SCR and SNCR can result in additional ammonia emissions. There is also increased truck traffic bringing the reagent on site. SCR will also slightly reduce the efficiency of the plant, resulting in increased fuel usage. Remaining Useful Life: EPA assumes that this plant would continue operating for 20 years and fully amortize the cost of controls. Degree of Improvement in Visibility: CALPUFF modeling indicates that installation of SNCR at Unit 1 would provide a 0.10 dv visibility benefit at the most affected Class I area, Petrified Forest NP, while installation of SCR would provide a 0.20 dv benefit at the same area as shown in Table 46. Note that all of these results, including the base case, assume that SCR has been applied to Units 2, 3 and 4, consistent with EPA’s previous BART determination for those units. TABLE 46—CHOLLA UNIT 1: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Distance (km) Class I area Capitol Reef NP ......................................................................................................... Galiuro WA ................................................................................................................ Gila WA ...................................................................................................................... Grand Canyon NP ..................................................................................................... Mazatzal WA .............................................................................................................. Mesa Verde NP ......................................................................................................... Mount Baldy WA ........................................................................................................ Petrified Forest NP .................................................................................................... Pine Mountain WA ..................................................................................................... Saguaro NP ............................................................................................................... Sierra Ancha WA ....................................................................................................... Superstition WA ......................................................................................................... Sycamore Canyon WA .............................................................................................. Cumulative (sum) ....................................................................................................... Maximum ................................................................................................................... # CIAs >= 0.5 dv ....................................................................................................... Million $/dv (cumul. dv) .............................................................................................. Million $/dv (max. dv) ................................................................................................ Proposed Determination: EPA proposes to determine that it is not reasonable to require additional controls on this facility at this time. The costs for both SNCR and SCR are relatively high in light of the relatively small anticipated visibility benefits of the controls. However, this decision should be revisited in future planning periods. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 d. El Paso Natural Gas Company’s Tucson Compressor Station Costs of Compliance: This site includes seventeen 1,071 hp compressor engines. EPA’s analysis indicates that the most cost-effective control would be an air/fuel ratio controller that would reduce emissions by 578 tpy at a cost of $792/ton.149 The site also includes four 370 hp engines. EPA’s analysis indicates that the most cost-effective control would be a three-way catalyst that would reduce 147 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 300 249 222 179 128 292 128 39 149 300 126 166 147 .................... .................... .................... .................... .................... emissions by 96 tons per year at a cost of $290/ton. Time Necessary for Compliance: The Institute of Clean Air Companies estimates that 8 to 14 weeks would be required to install these kinds of controls.150 Energy and Non-Air Quality Environmental Impacts of Compliance: Both controls may increase fuel usage by reducing the thermal efficiency of the engines. Remaining Useful Life: EPA assumes that the engines would continue operating for 20 years and fully amortize the cost of controls. Proposed Determination: EPA proposes to find that it is not reasonable to require additional controls on this facility at this time. Natural gas engines similar to those at the Tucson Compressor Station are found in various locations throughout Arizona. EPA’s assessment indicates that a state-wide or 148 See 77 FR 42834 at 42865 for more details. spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in the docket. 149 See PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 Base case (ctrl0/ctrl2_r2) 0.71 0.30 0.48 1.14 0.79 0.65 0.71 3.38 0.55 0.23 0.87 0.81 0.76 11.4 3.38 10 ...................... ...................... Visibility improvement from control SNCR on Unit 1 (ctrl2–1) SCR on Unit 1 (ctrl2–2) 0.04 0.01 0.01 0.05 0.02 0.03 0.01 0.10 0.01 0.00 0.02 0.03 0.03 0.3 0.10 0 $3.0 $10.3 0.09 0.01 0.01 0.12 0.04 0.06 0.02 0.20 0.03 0.00 0.06 0.06 0.07 0.7 0.20 0 $5.7 $21.7 regional approach to controlling this source category could result in significant emissions reductions. Given the dispersed nature of these engines, it is not practical for EPA to control these sources. Therefore, EPA proposes to find that it is not reasonable to require additional controls on this particular source at this time. This source category should be given serious consideration for future planning periods, as it would be more appropriately controlled by the State. e. El Paso Natural Gas Company’s Flagstaff Compressor Station Costs of Compliance: This site includes two 5,500 hp compressor engines. EPA’s analysis indicates that the most cost-effective control would be an air/fuel ratio controller that would 150 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. E:\FR\FM\18FEP2.SGM 18FEP2 9358 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules reduce emissions by 398 tpy at a cost of $432/ton.151 Time Necessary for Compliance: The Institute of Clean Air Companies estimates that 8 to 14 weeks would be required to install these kinds of controls.152 Energy and Non-Air Quality Environmental Impacts of Compliance: The controls may increase fuel usage by reducing the thermal efficiency of the engines. Remaining Useful Life: EPA assumes that the engines would continue operating for 20 years and fully amortize the cost of controls. Proposed RP Determination: EPA proposes to find that it is not reasonable to require additional controls on this facility at this time. Natural gas engines similar to those comprising the Flagstaff Compressor Station are found in various locations throughout Arizona. EPA’s assessment indicates that a state-wide or regional approach to controlling this source category could result in significant emissions reductions. Given the dispersed nature of these engines, many of which may fall into the area source category discussed above, it is not practical for EPA to control these sources. Therefore, EPA proposes to find that it is not reasonable to require additional controls on this particular source at this time. This source category should be given serious consideration for future planning periods. f. Tucson Electric Power Sundt Station (Units 1–3) Costs of Compliance: TEP Sundt has three natural gas-fired boilers rated at approximately 1,220 MMBTU/hr each. EPA’s analysis indicates that the most cost-effective control would be ultra-low NOX burners (ULNB). This retrofit would reduce emissions from Unit 1 by 46 tpy at a cost of $8,300/ton. It would reduce emissions from Unit 2 by 55 tpy at a cost of $7,000/ton. The retrofit would reduce emissions from Unit 3 by 90 tpy at a cost of $4,400/ton. As shown in Table 47, modeling indicates that these controls would provide a 0.40 dv visibility benefit at the most improved Class I area. Time Necessary for Compliance: The Institute of Clean Air Companies estimates that 6 to 8 months would be required to install these kinds of controls.153 Energy and Non-Air Quality Environmental Impacts of Compliance: The ultra-low-NOX burners may reduce the thermodynamic efficiency of the boilers and require an increase in fuel consumption. Remaining Useful Life: EPA assumes that the boilers would continue operating for 20 years and fully amortize the cost of controls. Proposed RP Determination: EPA proposes to find that it is not reasonable to require additional controls on this facility at this time. As noted above, ULNB has cost-effectiveness values for Sundt Units 1–3 in the range of $4,000 to 7,000 per ton. These costs are relatively high in light of the anticipated visibility benefits of the controls. However, this decision should be revisited in future planning periods, particularly if these units operate at a higher capacity factor in the future. Degree of Improvement in Visibility: Modeling indicates that installation of ULNB on all three units would provide a 0.40 dv visibility benefit at the most improved Class I area, Saguaro National Park, as shown in Table 47. Note that all of these results assume that SNCR has been applied to Sundt Unit 4, consistent with EPA’s previous BART determination for that unit. The visibility cost-effectiveness values are based on an annualized cost of $1.2 million per year, based on the analysis by UNC, contractor to EPA.154 TABLE 47—SUNDT UNIT 1, 2 AND 3: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Visibility impact Distance (km) Class I area mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Chiricahua NM ..................................................................................................................................... Chiricahua WA ..................................................................................................................................... Galiuro WA .......................................................................................................................................... Gila WA ................................................................................................................................................ Mazatzal WA ........................................................................................................................................ Mount Baldy WA .................................................................................................................................. Pine Mountain WA ............................................................................................................................... Saguaro NP ......................................................................................................................................... Sierra Ancha WA ................................................................................................................................. Superstition WA ................................................................................................................................... Cumulative (sum) ................................................................................................................................. Maximum ............................................................................................................................................. # CIAs >= 0.5 dv ................................................................................................................................. Million $/dv (cumul. dv) ........................................................................................................................ Million $/dv (max. dv) .......................................................................................................................... 151 See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in the docket. 152 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 153 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. 154 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor RP Analyses for TEP Springerville, APS Cholla, TEP PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 144 141 64 232 203 232 247 17 178 137 .................... .................... .................... .................... .................... Visibility improvement from control Base case (SNCR on Unit 4) ULNB 0.43 0.51 1.10 0.17 0.19 0.15 0.15 3.40 0.19 0.32 6.6 3.40 3 ...................... ...................... 0.08 0.07 0.22 0.02 0.02 0.02 0.01 0.40 0.02 0.04 0.9 0.40 0 $1.3 $2.9 Sundt, CalPortland Cement and Phoenix Cement Plants, Contract No. EP–D–07–102, Work Assignment 5–12; Prepared for EPA Region 9 by University of North Carolina at Chapel Hill, ICF International, and Andover Technology Partners; October 3, 2012, Table 20. E:\FR\FM\18FEP2.SGM 18FEP2 9359 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules g. Ina Road Sewage Plant Costs of Compliance: This site has seven 1,000 hp natural gas-fired internal combustion engines. EPA’s analysis indicates that the most cost-effective control is non-selective catalytic reduction (NSCR). Installation of this control would reduce emissions by 1,029 tpy at a cost of $210/ton.155 Time Necessary for Compliance: The Institute of Clean Air Companies estimates that 8 to 14 weeks would be required to install these kinds of controls.156 Energy and Non-Air Quality Environmental Impacts of Compliance: The control measure may decrease the thermodynamic efficiency of the engines and increase fuel usage. Remaining Useful Life: EPA assumes that the engines would continue operating for 20 years and fully amortize the cost of controls. Proposed RP Determination: EPA proposes to find that it is not reasonable to require additional controls on this facility at this time. Natural gas engines similar to those at the Ina Road Sewage Plant are found in many locations throughout Arizona. EPA’s assessment indicates that a state-wide or regional approach to controlling this source category could result in significant emissions reductions. Given the dispersed nature of these engines, many of which may fall into the area source category discussed above, it is not practical for EPA to control these sources. Therefore, EPA proposes to find that it is not reasonable to require additional controls on this particular source at this time. This source category should be given serious consideration for future planning periods, as it would be more appropriately controlled by the State. h. Tucson Electric Power Springerville Plant Costs of Compliance: TEP Springerville Plant Units 1 and 2 are 4,700 MMBtu/hr tangential coal-fired boilers, which currently employ LNB with OFA for NOX control. EPA identified two feasible additional controls: SNCR and SCR. The estimated emission reductions and costs for these two options are summarized in Tables 48 and 49. TABLE 48—TEP SPRINGERVILLE 1 AND 2: NOX EMISSION ESTIMATES NOX emissions Emission reduction Control option lb/MMBtu Springerville 1: Baseline (LNB+OFA) ................................................................................ SNCR ........................................................................................................ SCR .......................................................................................................... Springerville 2: Baseline (LNB+OFA) ................................................................................ SNCR ........................................................................................................ SCR .......................................................................................................... lb/hr tpy tpy 0.18 0.13 0.05 769 538 212 2,189 1532 605 657 1,584 0.19 0.13 0.05 798 559 210 2,448 1714 644 734 1,804 TABLE 49—TEP SPRINGERVILLE 1 AND 2: NOX CONTROL COST ESTIMATES Total capital cost Annualized capital cost Annual O&M costs Total annual cost $ Control option $/yr $/yr $/yr mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Springerville 1: Baseline (LNB+OFA) SNCR ................................................ SCR .................................................. Springerville 2: Baseline (LNB+OFA) SNCR ................................................ SCR .................................................. Cost-effectiveness ($/ton) Ave Incr $8,496,000 71,796,257 $903,914 7,638,614 $1,933,059 3,181,809 $2,836,973 10,820,423 $4,320 6,829 $8,606 8,496,000 71,402,351 903,914 7,596,705 2,141,291 3,379,514 3,045,205 10,976,219 4,146 6,085 7,416 Time Necessary for Compliance: Given the estimate from the Institute of Clean Air Companies 157 that approximately a year is required to install SNCR and the estimate of three years for installing SNCR on a cement kiln discussed previously in this notice. EPA estimates that SNCR could be installed in less than three years. In our previous Arizona FIP action, EPA estimated that 5 years would be required to install SCR on coal-fired boilers.158 That estimate also holds for this source. Energy and Non-Air Quality Environmental Impacts of Compliance: SCR and SNCR can result in additional ammonia emissions. There is also increased truck traffic bringing the reagent on site. SCR will also slightly reduce the efficiency of the plant, resulting in increased fuel usage. Remaining Useful Life: EPA assumes that this plant would continue operating for 20 years and fully amortize the cost of controls. Degree of Improvement in Visibility: As shown in Table 50, CALPUFF modeling indicates that SNCR at Units 1 and 2 would provide a 0.18 dv visibility benefit at the most affected Class I area and a cumulative 0.8 dv benefit across all affected areas. SCR would provide a 0.41 dv benefit at the most affected Class I area and 155 See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in the docket. 156 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. 157 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. 158 See 77 FR 42834 at 42865 for more details. VerDate Mar<15>2010 20:22 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 9360 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules cumulative 1.7 dv across all affected areas. TABLE 50—SPRINGERVILLE UNITS 1 & 2: VISIBILITY IMPACT AND IMPROVEMENT FROM NOX CONTROLS Impact Distance (km) Class I area Improvement from control SNC (ctrl-1) Base case Bandelier NM ............................................................................................. Chiricahua NM ........................................................................................... Chiricahua WA ........................................................................................... Galiuro WA ................................................................................................ Gila WA ...................................................................................................... Grand Canyon NP ..................................................................................... Mazatzal WA .............................................................................................. Mount Baldy WA ........................................................................................ Petrified Forest NP .................................................................................... Pine Mountain WA ..................................................................................... Saguaro NP ............................................................................................... San Pedro Parks WA ................................................................................ Sierra Ancha WA ....................................................................................... Superstition WA ......................................................................................... Sycamore Canyon WA .............................................................................. Cumulative (sum) ....................................................................................... Maximum ................................................................................................... # CIAs >= 0.5 dv ....................................................................................... 298 253 264 211 111 302 209 51 79 236 263 281 165 194 263 ........................ ........................ ........................ 1.08 0.85 0.88 0.95 4.39 0.79 0.86 3.63 2.46 0.67 0.57 1.53 1.01 0.52 0.65 20.8 4.39 15 Million $/dv (cumul. dv) .............................................................................. Million $/dv (max. dv) ................................................................................ ........................ ........................ .......................... .......................... Proposed RP Determination: EPA proposes to determine that it is not reasonable to require additional controls at Springerville Units 1 and 2 at this time. While the cost per ton for SNCR may be reasonable, the projected visibility benefits are relatively small (0.18 dv at the most affected area). The projected visibility benefits of SCR are larger (0.41 dv at the most affected area), but we do not consider them sufficient to warrant the relatively high cost of controls for purposes of RP in this planning period. However, these units should be considered for additional NOX controls in future planning periods. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 i. El Paso Natural Gas Williams Compressor Station Costs of Compliance: This site consists of five 2,500 hp engines, one 3,400 hp engine, and one 32,200 hp gas turbine. EPA’s analysis indicates that air/fuel ratio controllers are the most cost-effective controls for the five 2,500 hp engines and would reduce emissions by 288 tpy at a cost of $547/ton. Our analysis indicates that an air/fuel ratio controller is also the most cost-effective control for the 3,400 hp engine and would reduce emissions from that engine by 131 tpy at a cost of $444/ton. Our analysis further indicates that water injection would be the most costeffective control for the gas turbine and would reduce emissions from that VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 engine by 505 tpy at a cost of $854/ ton.159 Time Necessary for Compliance: The Institute of Clean Air Companies estimates that 8 to 14 weeks would be required to install these kinds of controls.160 Energy and Non-Air Quality Environmental Impacts of Compliance: These controls may increase fuel usage by reducing the thermal efficiency of the engines. Remaining Useful Life: EPA assumes that the engines would continue operating for 20 years and fully amortize the cost of controls. Proposed RP Determination: EPA proposes to find that it is not reasonable to require additional controls on this facility at this time. Natural gas engines similar to those comprising the Williams Compressor Station are found in various locations throughout Arizona. EPA’s assessment indicates that a statewide or regional approach to controlling this source could result in significant emissions reductions. Given the dispersed nature of these engines, many of which may fall into the area source category discussed above, it is not practical for EPA to control these sources. Therefore, EPA proposes to 159 See spreadsheet ‘‘Non EGU_RP_Ch5.xlsx’’ in the docket. 160 Typical Installation Timelines for NO X Emissions Control Technologies on Industrial Sources, Institute of Clean Air Companies, December 4, 2006. PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 SCR (ctrl-2) 0.07 0.07 0.00 0.03 0.18 0.07 0.01 0.13 0.06 0.02 0.01 0.05 0.02 0.03 0.02 0.8 0.18 0 $7.3 $32.2 0.13 0.14 0.01 0.08 0.41 0.07 0.01 0.32 0.09 0.06 0.04 0.23 0.05 0.06 0.04 1.7 0.41 0 $12.6 $53.4 find that it is not reasonable to require additional controls on this particular source at this time. This source category should be given serious consideration for future planning periods, as it would be more appropriately controlled by the State. B. Reasonable Progress Analysis of Area Sources for NOX and SO2 1. Identification of Area Sources for NOX and SO2. The initial step in our area source RP analysis was the identification of specific SO2 and NOX area source categories to evaluate for potential controls. To that end, we examined data from the 2008 National Emissions Inventory (NEI) to determine the most significant area sources of SO2 and NOX. This analysis is described in the TSD, and the results are summarized in Tables 51 and 52. As discussed in the TSD, there are significant uncertainties in the area source emissions inventory for Arizona. In spite of the uncertainty, it is evident that the primary area source categories of most concern are Industrial and Commercial Boilers and Internal Combustion Engines burning distillate fuel oil. A third category, Residential Natural Gas Combustion, also comprises a significant portion of NOX emissions. EPA has therefore identified these categories as ‘‘potentially affected sources.’’ EPA proposes to find that the remaining source categories comprise too small of a percentage contribution to E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules overall emissions to justify 9361 consideration for additional controls in this initial planning period. TABLE 51—SIGNIFICANT AREA SOURCES OF NOX IN ARIZONA Source type Source classification code Industrial Boilers and Internal Combustion Engines (burning distillate fuel oil) .................................................................................................... Residential Natural Gas Combustion ........................................................ Industrial Natural Gas Combustion ........................................................... Open Burning, Land Clearing Debris ........................................................ Tons per year (2008) 2102004000 2104006000 2102006000 ............................ 2,300 1,645.7 765.4 727.0 Portion of total area source emissions (%) 29.3 20.2 9.4 8.9 Cumulative portion (%) 29.3 49.5 58.8 67.7 TABLE 52—SIGNIFICANT AREA SOURCES OF SO2 IN ARIZONA Industrial Boilers and Internal Combustion Engines (burning distillate fuel oil) ............................................................................................................. Commercial and Institutional Boilers and Internal Combustion Engines (burning distillate fuel oil) ......................................................................... Industrial processes not elsewhere classified ............................................. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2. Analysis of Significant Area Source Categories a. Approach to Area Source Analysis In conducting an RP analysis for area source, EPA encountered significant limitations on the availability and accuracy of data concerning the relevant source categories. For purposes of emission inventory development, an area source is not a single facility, but a category of polluting sources known to exist within a certain geographic area (such as a county), whose actual number, age, and design is not known. The emissions from area sources are usually estimated based on a ‘‘topdown’’ method, where a surrogate piece of information, such as the number of people living in a county or the gallons of diesel fuel sold there in a given year, is used to estimate emissions. Each of the source categories analyzed has an emissions estimate derived from Federal, state, or local databases of fuel consumption. In the aggregate, these numbers are sufficiently accurate for most analyses. However, they do not provide adequate detail for EPA to precisely estimate the actual costs and benefits of controlling the existing population of sources. Given these limitations in available data, EPA’s analyses of area sources are limited in scope. For each category we have developed ranges for the estimated cost of compliance and general information about each of the other factors, based largely on data from three sources: the WRAP Four-Factor VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 Tons per year (2008) Portion of total area source emissions (%) 2102004000 1652.1 65.3 65.3 2103004000 2399000000 483.5 110.4 19.1 4.4 84.5 88.8 Source classification code Source type Analysis report, 161 EPA’s Control Strategy Tool, and the documentation for EPA’s AirControlNet tool.162 The WRAP report lists several possible NOX and SO2 controls for industrial boilers and internal combustion engines, depending on their size and pre-existing controls. The WRAP report also addresses the other mandatory factors for an RP analysis. The Control Strategy Tool is EPA’s most current tool for assessing the cost-effectiveness of control strategies for various source categories. EPA used this tool to confirm that the cost estimates in the WRAP report are still reasonable.163 We also consulted the AirControlNet documentation report that contains the most current data on the costeffectiveness of NOX controls for residential natural gas combustion. Finally, while we lacked sufficient data to conduct visibility modeling for particular categories of area sources, we have analyzed the overall contribution of area sources to nitrate and sulfatecaused visibility impairment in Arizona’s Class I areas in order to estimate the potential benefits of controls. The results of this analysis are provided below, following the results of the four-factor analyses for all of the source categories. 161 ‘‘Supplementary Information for Four Factor Analyses by WRAP States,’’ EC/R Incorporated, corrected version, April 20, 2010. 162 ‘‘AirControlNet, Version 4.1,’’ May 2006, E.H. Pechan and Associates. 163 See spreadsheet titled ‘‘AZ FIP Cost Analysis_ for Greg Nudd Rg 9_2013–08–13.xls’’. PO 00000 Frm 00045 Fmt 4701 Sfmt 4702 Cumulative portion (%) b. RP Analysis of Industrial, Commercial, and Institutional Boilers Burning Distillate Fuel Oil Cost of Compliance: The estimated cost-effectiveness values for NOX control options are: • LNB: $400–7,000/ton; • LNB/OFA: $400–7,000/ton; • SNCR: $400–6,900/ton; • SCR: $1,000–8,000/ton. The estimated cost-effectiveness values for SO2 control options for this category are: • DSI: $5,000–11,000/ton; • Wet FGD: $6,000–13,000/ton. Time Necessary for Compliance: Installation of the control devices, in most cases, should take no more than 2– 3 years. The only possible exception may be for installation of SCR, which may take as long as 5 years. Energy and Non-Air Quality Environmental Impacts of Compliance: LNB may reduce combustion efficiency and slightly increase fuel consumption; SNCR and SCR would require some electricity use and environmental impacts from ammonia slip and transport and storage of the reagent. Wet FGD requires large quantities of water and requires disposal of wet ash. Remaining Useful Life: It is reasonable to assume that the units would remain in use long enough to fully recover the costs of controls. E:\FR\FM\18FEP2.SGM 18FEP2 9362 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules c. RP Analysis of Industrial, Commercial, and Institutional Internal Combustion Engines Burning Distillate Fuel Oil Costs of Compliance: We estimate the following cost-effectiveness values for NOX control options: • Ignition timing retard: $1,000– 2,200/ton; • Exhaust Gas Recirculation: $780– 2,000/ton; • SCR: $3,000–7,700/ton; • Replacement with Tier 4 engines: $900–2,400/ton. We did not identify any technically feasible options for SO2 control other than lower sulfur fuel. Time Necessary for Compliance: Installation of the control devices, in most cases, should take no more than 2– 3 years. The only possible exception may be for installation of SCR, which may take as long as 5 years. Energy and Non-Air Quality Environmental Impacts of Compliance: SCR would require some electricity use and there may also be environmental impacts from ammonia slip and transport and storage of the reagent. The other options would not have negative energy or non-air quality environmental impacts. Remaining Useful Life: It is reasonable to assume that the units would remain in use long enough to fully recover the costs of controls. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 d. RP Analysis of Residential Natural Gas Combustion Costs of Compliance: We estimate the following cost-effectiveness values for NOX control options: • Replace space heaters with Low NOX equivalent: $1,600/ton; • Replace water heaters with Low NOX equivalent: $1,230/ton.164 SO2 controls are not needed for this category due to low sulfur content of pipeline natural gas. Time Necessary for Compliance: Installation of the new devices, in most cases, should take no more than 2–3 years. Energy and Non-Air Quality Environmental Impacts of Compliance: We did not identify any energy or nonair quality environmental impacts. Remaining Useful Life: This factor is not applicable for a unit replacement. Visibility Significance of Area Sources: As explained above, we do not have sufficient information to assess the likely visibility benefits of requiring controls on particular categories of area sources. However, in order to estimate 164 Both estimates from AirControlNet Manual p. III–90 and are in 1990 dollars. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 the total potential visibility benefits that might result from controlling NOX and SO2 emissions from area sources, we have analyzed the overall contribution of area sources to nitrate- or sulfatecaused visibility impairment in Arizona’s Class I areas. The relative contribution can be estimated by reviewing the results of the Particulate Source Apportionment Technology (PSAT) modeling conducted by the WRAP. This method and our evaluation of it are described in the WRAP TSD prepared by EPA.165 Tables 53 and 54 below compare the contribution of Arizona area sources to visibility impairment in Arizona’s Class I areas with the contributions from point and mobile sources.166 Table 53 shows the relative contribution of these Arizona source categories to the 2018 predicted total nitrate impairment at the Class I areas. Table 54 shows the same data for 2018 predicted total sulfate impairment. Nitrate and sulfate comprise a subset of the total visibility impairment at these Class I areas. To calculate the source category’s total contribution to visibility impairment, one would have to account for the other pollutants (such as coarse mass, black carbon, etc.). EPA has not made that calculation here, as we are looking specifically at nitrate and sulfate impairment for this RP analysis. TABLE 53—2018 PROJECTED NITRATE IMPAIRMENT: COMPARISON OF ARIZONA SOURCE CATEGORIES Class I area Arizona area sources (%) Arizona point sources (%) Arizona mobile sources CHIR1 ......... GRCA2 ....... IKBA1 .......... BALD1 ........ PEFO1 ........ SAGU1 ........ SAWE1 ....... SIAN1 ......... TONT1 ........ SYCA1 ........ 0.7 2.9 4.1 0.8 1.7 5.2 4.3 4.1 5.4 2.7 5.1 7.4 12.3 18.1 26.7 19.3 18.4 5.0 12.7 14.0 5.1 18.3 23.6 8.7 14.2 27.5 23.5 20.7 30.2 19.3 165 ‘‘Technical Support Document for Technical Products Prepared by the Western Regional Air Partnership (WRAP) in Support of Western Regional Haze Plans,’’ February 28, 2011. 166 See http://vista.cira.colostate.edu/tss/Results/ HazePlanning.aspx, select ‘‘Emissions and Source Apportionment’’ and the 2018 Base Case (base 18b) emissions scenario. PO 00000 Frm 00046 Fmt 4701 Sfmt 4702 TABLE 54—2018 PROJECTED SULFATE IMPAIRMENT: COMPARISON OF ARIZONA SOURCE CATEGORIES Class I area Arizona area sources Arizona point sources Arizona mobile sources CHIR1 ......... GRCA2 ....... IKBA1 .......... BALD1 ........ PEFO1 ........ SAGU1 ........ SAWE1 ....... SIAN1 ......... TONT1 ........ SYCA1 ........ 0.4 0.4 1.0 0.7 0.7 2.1 1.7 0.8 1.3 1.0 4.7 4.3 6.7 11.3 19.6 10.2 9.6 7.8 7.8 3.5 0.5 1.0 1.2 0.7 0.9 1.7 1.4 1.1 2.8 0.8 As indicated in Tables 53 and 54, area sources in Arizona currently comprise a relatively small portion of the visibility impairment due to nitrate and sulfate, so the potential visibility benefits of NOX or SO2 controls on these sources would be relatively small at this point in time. However, the relative contribution of area sources to visibility impairment at Arizona’s Class I areas may increase over time, as additional point source and mobile source controls are implemented. Therefore, additional analysis of these sources will be necessary in future planning periods. f. Proposed RP Determination for Area Sources EPA proposes to find that it is not reasonable to require additional controls on area sources of NOX and SO2 at this time. There are significant uncertainties about the costs and potential benefits of such rules at this time. Furthermore, the visibility benefits due to area source controls are likely to be much smaller than the significant reductions in SO2 and NOX emissions from point sources achieved during this planning period. We also note that no other Regional Haze SIP or FIP has imposed controls on such sources primarily to ensure reasonable progress.167 EPA will work with the State and the relevant regional planning organizations to improve our understanding of the nature of these area source emissions, the costs and methods of controlling them, and their impact on visibility at Class I areas. Based on the results of these efforts, 167 The Colorado Regional Haze SIP includes rules limiting emissions from certain Reciprocating Internal Combustion Engines. 77 FR 18052, 18089. However these rules are part of a State regulation intended to control ozone rather than regional haze. Colorado Air Quality Control Commission, Regulation Number 7, 5 CCR 1001–9, Control of Ozone via Ozone Precursors, Section XVII, Statewide Control for Oil and Gas Operations and Natural Gas-Fired Reciprocating Internal Combustion Engines, subsection E.3.a, (Regional Haze SIP) Rich Burn Reciprocating Internal Combustion Engines. E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules these source categories should be carefully considered in future Regional Haze SIPs. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 C. Reasonable Progress Goals We are proposing reasonable progress goals (RPGs) that are consistent with the combination of control measures included in the Arizona RH SIP measures that we previously approved; 168 the partial RH FIP that we promulgated on December 5, 2012; 169 and the partial RH FIP we are proposing today. In total, these final and proposed controls to meet the BART and RP requirements will result in higher emissions reductions and commensurate visibility improvements beyond what was in the State’s plan. As a result, we expect that the visibility levels at Arizona Class I areas will be substantially better than predicted in the WRAP modeling that served as the basis for the State’s RPGs. In addition, our final BART FIP for the Four Corners Power Plant on the Navajo Nation is expected to result in tens of thousands of tons per year of additional NOX reductions that will benefit some of Arizona’s Class I areas. Likewise, our proposed BART FIP for the Navajo Generating Station, if finalized, will result in substantial visibility benefit for Class I areas. While we would prefer to quantify these proposed RPGs for each of Arizona’s 12 Class I areas based on the new state and federal plans, we lack sufficient time and resources to conduct the type of regional-scale modeling required to develop such numerical RPGs.170 Nonetheless, we anticipate that the additional controls required in EPA’s Regional Haze FIPs will result in an increase in visibility improvement during the 20 percent worst days and the 20 percent best days in all of Arizona’s Class 1 Areas. D. Meeting the Uniform Rate of Progress As explained in our proposed and final rules on the Arizona RH SIP, the State set RPGs that provide for slower rates of improvement in visibility than the URP for each of the State’s twelve Class I areas.171 Given the variety and location of the sources contributing to visibility impairment in Arizona, EPA considers it unlikely that all of Arizona’s Class I areas will meet the URP during this planning period, even 168 77 FR 72512, 78 FR 46142. FR 72512. 170 The regional-scale modeling that formed the basis for Arizona’s RPGs was developed by the WRAP’s Regional Modeling Center over the course of several years with input from numerous sources. 171 See 77 FR 75728, 78 FR 29298 and 78 FR 46160. 169 77 VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 with the additional controls required in EPA’s Regional Haze FIPs. Therefore, EPA must demonstrate that it is not reasonable to provide for rates of progress consistent with the URP for this planning period, based upon the four RP factors.172 Given that this demonstration must be based on the same four factors as the initial RP analysis, EPA proposes to find that the extensive reasonable progress analysis underlying our actions on the Arizona SIP, and the reasonable progress analysis found in this proposal are sufficient to make this demonstration. In particular, for the reasons explained in our proposed and final rules on the Arizona RH SIP, we have approved Arizona’s determinations that it is not reasonable to require additional controls to address organic carbon, elemental carbon, coarse mass and fine soil during this planning period.173 We also approved the State’s decision not to require additional controls on nonBART point sources of SO2.174 Moreover, based on the analyses set out in the preceding sections of this document, we are now proposing to find that it is not reasonable to require additional controls on most point sources of NOX or area sources of NOX and SO2 during this planning period. However, we are proposing to require additional NOX controls on two cement kilns. Based on all of these analyses, we propose to find that it is not reasonable for any of Arizona’s Class I areas to meet the URP during this planning period. VII. EPA’s Proposed Long-Term Strategy Supplement In our final rule on the Arizona RH SIP published on July 30, 2013, we disapproved portions of the State’s LTS related to three RHR requirements. These requirements were for measures needed to achieve emission reductions for out-of-state Class I areas, emissions limitations and schedules for compliance to achieve the reasonable progress goals, and enforceability of emissions limitations and control measures.175 These RHR requirements are found in 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F). We now are obligated to address these requirements through a FIP under CAA section 110(c). In this section, we describe each of these requirements, our rationale for disapproving these elements in the 172 40 CFR 51.308(d)(1)(ii). 77 FR 75728 for a discussion on sources of organic carbon and elemental carbon (fires), and 78 FR 29297–29299 for a discussion of coarse mass and fine soil. 174 See 78 FR 46172. 175 See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)). 173 See PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 9363 Arizona RH SIP, and propose how to address these requirements in our FIP. A. Emission Reductions for Out-of-State Class I Areas Under the RHR, where a state has participated in a regional planning process, the state’s LTS must include all measures needed to achieve that state’s apportionment of emission reduction obligations agreed upon through that process.176 Arizona participated in a regional planning process through the WRAP and incorporated the WRAPdeveloped visibility modeling into the Arizona RH SIP. However, the Arizona RH SIP did not include all measures needed to achieve the State’s apportionment of emission reductions that were included in the WRAP modeling. In particular, Arizona’s BART determinations lacked the necessary compliance schedules and requirements for operation and maintenance of control equipment and monitoring, recordkeeping and reporting to ensure that the assumed reductions at Arizona’s BART sources are achieved. Therefore, we disapproved this element of the Arizona RH SIP. B. Emissions Limitations and Schedules for Compliance To Achieve RPGs One of the factors a state must consider in developing its LTS is emissions limitations and schedules for compliance to achieve the State’s RPGs for its own Class I areas.177 As explained in the preceding section, the Arizona RH SIP did not contain any enforceable emission limitations or schedules for compliance to achieve the State’s RPGs. Therefore, we found that the Arizona RH SIP did not meet this requirement. C. Enforceability of Emissions Limitations and Control Measures Another factor a state must consider in developing its LTS is the enforceability of emissions limitations and control measures.178 As explained in the preceding sections, Arizona’s BART determinations lack provisions to ensure their enforceability. Therefore, we disapproved the Arizona RH SIP with respect to this requirement. D. Proposed Partial LTS FIP The primary flaw in Arizona’s LTS is the lack of enforceable emission limitations for BART controls. We propose to remedy this deficiency by promulgating BART emission limitations and compliance schedules as 176 40 CFR 51.308(d)(3)(ii). CFR 51.308(d)(3)(v)(C). 178 40 CFR 51.308(d)(3)(v)(F). 177 40 E:\FR\FM\18FEP2.SGM 18FEP2 9364 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules well as monitoring, recordkeeping and reporting requirements, to ensure the enforceability of these limits. 1. Enforceability Requirements for Arizona and EPA’s Phase 1 BART Determinations As part of our final rule published on December 5, 2012, regarding BART for Apache Generating Station, Cholla Power Plant and Coronado Generating Station, we promulgated compliance deadlines and requirements for equipment maintenance and operation including monitoring, recordkeeping and reporting, to ensure the enforceability of both Arizona’s and EPA’s BART determinations. 2. Enforceability Requirements for EPA’s Proposed Phase 3 BART and RP Determinations As described above, today, we are proposing to promulgate similar requirements for the remaining subjectto-BART sources and pollutants in Arizona. We are also proposing emission limitations and compliance requirements for two RP sources: the Phoenix Cement Clarkdale Plant and the CalPortland Rillito Plant. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 3. Enforceability Requirements for Arizona’s Phase 2 BART Determinations The final element of our proposed LTS consists of enforceable emission limitations and associated requirements for PM10 at the Hayden and Miami Copper Smelters. While we previously approved the State’s determination that existing controls constitute BART for PM10 at each of these facilities, the Arizona RH SIP lacked any emission limitation or associated requirements to ensure the enforceability of these determinations, as required under the CAA and EPA’s regulations.179 Therefore, we are proposing to promulgate such limits and associated compliance requirements for these BART determinations, as necessary to ensure their enforceability. incorporated in its Regional Haze SIP.181 We are now proposing to incorporate these requirements into the FIP. In particular, we propose to set a limit of 6.2 mg/dscm non-sulfuric acid particulate matter from the primary capture system, and a limit of 23 mg/ dscm particulate matter from the secondary capture system, as measured using the test methods specified in 40 CFR 63.1450(b). We propose to require demonstration of compliance with these limits through the applicable procedures in 40 CFR 63.1451 and 1453. b. Miami Smelter PM10 In the Arizona Regional Haze SIP, ADEQ determined that the NESHAP for Primary Copper Smelting constitutes BART for PM emissions from the Miami Smelter. Because the FMMI smelter is a major source of Hazardous Air Pollutants (HAPs), and therefore subject to the requirements of the NESHAP, these requirements are already incorporated into the facility’s Title V permit.182 We propose to find that these existing, federally enforceable requirements are sufficient to ensure the enforceability of ADEQ’s PM10 BART determination for the Miami Smelter. a. Hayden Smelter PM10 In its BART analysis for PM10, ASARCO relied on the particulate limits established in National Emission Standard for Hazardous Air Pollutants (NESHAP) Subpart QQQ, Primary Copper Smelting at 40 CFR 63.1444(d)(5) and (6).180 These limits and associated monitoring requirements formed the basis for ASARCO’s BART determination, which ADEQ VIII. EPA’s Proposal for Interstate Transport We propose that a combination of SIP and FIP measures will satisfy the FIP obligation for the visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. As discussed in section II.B (‘‘Overview of Proposed Actions; Interstate Transport of Pollutants that affect Visibility’’) of this proposed rule, EPA disapproved Arizona’s 2007 and 2009 Transport SIPs as well as its Regional Haze SIP for the interstate transport visibility protection requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. As noted in our proposed SIP action,183 we interpret the visibility requirement of section 110(a)(D)(i)(II) as requiring states to include in their SIPs either measures to prohibit emissions that would interfere with attaining RPGs of Class I areas in other states, or a demonstration that emissions from the state’s sources and activities will not have the prohibited impacts under the existing SIP. Arizona’s 2007 and 2009 Transport SIP revisions indicated that the interstate transport visibility requirement should be assessed in 179 See CAA section 110(a)(2)(F) and 40 CFR 51.212(c), 51.308(d)(3)(v)(C) and (F). 180 Letter from Eric Hiser, Counsel for ASARCO, to Balaji Vaidyanathan, ADEQ dated March 20, 2013, page 5. 181 Arizona RH SIP Supplement (May 3, 2013), Appendix D, page 23, and Section XII. 182 ADEQ Air Quality Class I Permit Number 53592 issued November 26, 2012, attachment B. 183 77 FR 75704 at 75709. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00048 Fmt 4701 Sfmt 4702 conjunction with the Arizona RH SIP, but did not specify which parts of the RH SIP should be considered as meeting the visibility requirement of section 110(a)(2)(D)(i)(II). Therefore we have considered the Arizona RH SIP as a whole in assessing whether Arizona has met this visibility requirement. As a result of the partial disapprovals of the Arizona RH SIP, we found that the Arizona SIP did not contain adequate provisions to prohibit emissions that may interfere with SIP measures required of other states to protect visibility. Therefore, we disapproved Arizona’s submittals with respect to the interstate transport visibility requirement for the 1997 8hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS, which triggered the obligation for EPA to promulgate a FIP under CAA section 110(c)(1). We anticipated that this FIP obligation could be satisfied by a combination of the State’s measures that we previously approved and EPA’s promulgation of FIPs for the disapproved elements of the Arizona RH SIP.184 We propose to find that the combination of elements in the applicable RH SIPs and FIPs will contain adequate provisions to prohibit emissions from Arizona that would interfere with SIP measures required of other states to protect visibility. These elements are the Arizona RH SIP measures that we previously approved;185 the partial RH FIP that we promulgated on December 5, 2012;186 and the partial RH FIP we are proposing today. As explained in the LTS section, the combination of all of these measures will ensure that the applicable implementation plan (i.e., the combination of SIP and FIP measures) will include all of the measures needed to achieve Arizona’s allotment of emission reductions agreed upon through the WRAP process. We propose that this combination of SIP and FIP measures will satisfy the FIP obligation for the visibility requirement of CAA section 110(a)(2)(D)(i)(II) for the 1997 8hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS. IX. Summary of EPA’s Proposed Actions A. Regional Haze EPA is proposing a FIP to address the remaining portions of the Arizona’s RH SIP that we disapproved on July 30, 2013, which includes requirements for Best Available Retrofit Technology, Reasonable Progress, and the Long-term 184 77 FR 75704 at 75736. FR 72512, 78 FR 46142. 186 77 FR 72512. 185 77 E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Strategy. We are proposing more stringent emission limits on six sources that impact visibility in 17 Class I areas inside and outside the State. We welcome comments on all of our proposals and indicate specific issues or areas where feedback would be particularly useful. Our proposal includes compliance dates and specific requirements for monitoring, recordkeeping, reporting and equipment operation and maintenance for all of the units covered by this action as described in Part 52 attached to this notice. Today’s proposed FIP, once finalized, along with previously approved SIPs and a finalized FIP, will constitute Arizona’s regional haze program for the first planning period that ends in 2018. B. Interstate Visibility Transport We propose that the interstate transport visibility requirement of section 110(a)(2)(D)(i)(II) for the 1997 8hour ozone, 1997 PM2.5, and 2006 PM2.5 NAAQS is satisfied by a combination of SIP and FIP elements. These elements are the Arizona RH SIP measures that we previously approved; the partial RH FIP that we promulgated on December 5, 2012; and the partial RH FIP we are proposing today. X. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review This proposed action is not a ‘‘significant regulatory action’’ under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011). The proposed FIP applies to only six facilities. It is therefore not a rule of general applicability. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 B. Paperwork Reduction Act This proposed action does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Under the Paperwork Reduction Act, a ‘‘collection of information’’ is defined as a requirement for ‘‘answers to * * * identical reporting or recordkeeping requirements imposed on ten or more persons * * *.’’ 44 U.S.C. 3502(3)(A). Because the proposed FIP applies to just six facilities, the Paperwork Reduction Act does not apply. See 5 CFR 1320(c). Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid Office of Management and Budget (OMB) control number. The OMB control numbers for our regulations in 40 CFR are listed in 40 CFR part 9. C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for profit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of this proposed action on small entities, I certify that this proposed action will not have a significant economic impact on a substantial number of small entities. None of the facilities subject to this proposed rule is owned by a small entity.187 We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts. 187 See Regulatory Flexibility Act Screening Analysis for Proposed Arizona Regional Haze Federal Implementation Plan (EPA–R09–OAR– 2013–0588). PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 9365 D. Unfunded Mandates Reform Act Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104–4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and Tribal governments and the private sector. Under section 202 of UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with ‘‘Federal mandates’’ that may result in expenditures to State, local, and Tribal governments, in the aggregate, or to the private sector, of $100 million or more (adjusted for inflation) in any 1 year. Before promulgating an EPA rule for which a written statement is needed, section 205 of UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most costeffective, or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 of UMRA do not apply when they are inconsistent with applicable law. Moreover, section 205 of UMRA allows EPA to adopt an alternative other than the least costly, most cost-effective, or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including Tribal governments, it must have developed under section 203 of UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. Under Title II of UMRA, EPA has determined that this proposed rule does not contain a Federal mandate that may result in expenditures that exceed the inflation-adjusted UMRA threshold of $100 million by State, local, or Tribal governments or the private sector in any 1 year. In addition, this proposed rule does not contain a significant Federal intergovernmental mandate as described by section 203 of UMRA nor does it contain any regulatory requirements that might significantly or uniquely affect small governments.188 188 See ‘‘Summary of EPA BART Cost Estimates’’ in the docket. E:\FR\FM\18FEP2.SGM 18FEP2 9366 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules E. Executive Order 13132: Federalism mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Executive Order 13132 Federalism (64 FR 43255, August 10, 1999) revokes and replaces Executive Orders 12612 (Federalism) and 12875 (Enhancing the Intergovernmental Partnership). Executive Order 13132 requires EPA to develop an accountable process to ensure ‘‘meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.’’ ‘‘Policies that have federalism implications’’ is defined in the Executive Order to include regulations that have ‘‘substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.’’ Under Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed regulation. EPA also may not issue a regulation that has federalism implications and that preempts State law unless the Agency consults with State and local officials early in the process of developing the proposed regulation. This rule will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. In this action, EPA is fulfilling our statutory duty under CAA Section 110(c) to promulgate a partial Regional Haze FIP. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on this proposed rule from State and local officials. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. EPA has concluded that this action, if finalized, will have tribal implications, because it will impose substantial direct compliance costs on tribal governments, and the Federal government will not provide the funds necessary to pay those costs. PCC is a division of Salt River Pima Maricopa Indian Community (SRPMIC or the Community) and profits from the Phoenix Cement Clarkdale Plant are used to provide government services to SRPMIC’s members. Therefore, EPA is providing the following tribal summary impact statement as required by section 5(b). EPA consulted with tribal officials early in the process of developing this regulation to permit them to have meaningful and timely input into its development. In November 2012, we shared our initial analyses with SRPMIC and PCC to ensure that the tribe had an early opportunity to provide feedback on potential controls at the Clarkdale Plant. PCC submitted comments on this initial analysis as part of the rulemaking on the Arizona Regional Haze SIP and we revised our initial analysis based on these comments. On November 6, 2013, the EPA Region 9 Regional Administrator met with the President and other representatives of SRPMIC to discuss the potential impacts of the FIP on SRPMIC. Following this meeting, staff from EPA, SPRMIC and PCC shared further information regarding the Plant and potential impacts of the FIP on SRPMIC.189 During these consultations, SRPMIC expressed its concern regarding the potential financial impacts of any new controls that might be required at the Clarkdale Plant. In particular, SRPMIC requested that EPA provide PCC with an extended compliance schedule for any controls in order to enable PCC and SRPMIC to plan for such controls in their long-term budgets and thus mitigate the potential impacts to the Community.190 However, SRPMIC provided only limited information documenting the potential for such impacts and claimed all such information as CBI. As explained above, EPA is proposing to determine that it is reasonable to require installation of SNCR at Kiln 4 at the Clarkdale Plant by December 31, 189 See Memorandum to Docket: Summary of Communications and Consultation between EPA, PCC and SRPMIC (January 27, 2014). PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 2018. EPA is also seeking comment on the possibility of establishing an annual cap on NOX emissions from Kiln 4 in lieu of a lb/ton emission limit. An annual cap would allow SRPMIC to delay installation of controls until the Plant’s production returns to prerecession levels and would thus help to address the Community’s concerns about the budgetary impacts of control requirements. EPA specifically solicits additional comment on this proposed rule from tribal officials. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to any rule that: (1) Is determined to be economically significant as defined under Executive Order 12866; and (2) concerns an environmental health or safety risk that we have reason to believe may have a disproportionate effect on children. EPA interprets EO 13045 as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it implements specific standards established by Congress in statutes. However, to the extent this proposed rule will limit emissions of NOX, SO2 and PM, the rule will have a beneficial effect on children’s health by reducing air pollution. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer and Advancement Act Section 12 of the National Technology Transfer and Advancement Act (NTTAA) of 1995 requires Federal agencies to evaluate existing technical standards when developing a new regulation. To comply with NTTAA, EPA must consider and use ‘‘voluntary consensus standards’’ (VCS) if available and applicable when developing programs and policies unless doing so would be inconsistent with applicable law or otherwise impractical. EPA believes that VCS are inapplicable to this action. Today’s action does not E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules require the public to perform activities conducive to the use of VCS. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, February 16, 1994), establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. We have determined that this proposed rule, if finalized, will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low-income population. This proposed federal rule limits emissions of NOX and SO2 from six facilities in Arizona. List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen oxides, Sulfur dioxide, Particulate matter, Reporting and recordkeeping requirements, Visibility, Volatile organic compounds. Authority: 42 U.S.C. 7401 et seq. Dated: January 27, 2014. Jared Blumenfeld, Regional Administrator, Region 9. Part 52, chapter I, title 40 of the Code of Federal Regulations is proposed to be amended as follows: PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS 1. The authority citation for part 52 continues to read as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 ■ (i) Source-specific federal implementation plan for regional haze at Nelson Lime Plant—(1) Applicability. This paragraph (i) applies to the owner/ operator of the lime kilns designated as Kiln 1 and Kiln 2 at the Nelson Lime Plant located in Yavapai County, Arizona. (2) Definitions. Terms not defined in this paragraph (i)(2) shall have the meaning given them in the Clean Air Act or EPA’s regulations implementing the Clean Air Act. For purposes of this paragraph (i): Ammonia injection shall include any of the following: anhydrous ammonia, aqueous ammonia or urea injection. Continuous emission monitoring system or CEMS means the equipment required by this section to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of NOX emissions, SO2 emissions, diluent, or stack gas volumetric flow rate. Kiln 1 means rotary kiln 1, as identified in paragraph (i)(1) of this section. Kiln 2 means rotary kiln 2, as identified in paragraph (i)(1) of this section. Kiln operating day means a 24-hour period between 12 midnight and the following midnight during which the kiln operates. Lime product means the product of the lime kiln calcination process including calcitic lime, dolomitic lime, and dead-burned dolomite. NOX means nitrogen oxides. Owner/operator means any person who owns or who operates, controls, or supervises a kiln identified in paragraph (i)(1) of this section. SO2 means sulfur dioxide. Unit means any of the kilns identified in paragraph (i)(1) of this section. (3) Emission limitations. The owner/ operator of each kiln identified in paragraph (i)(1) of this section shall not emit or cause to be emitted pollutants in excess of the following limitations, in pounds of pollutant per ton of lime product (lb/ton), from any kiln. Each emission limit shall be based on a rolling 30 kiln-operating day basis. Pollutant emission limit Kiln ID Authority: 42 U.S.C. 7401 et seq. NOX Subpart D—Arizona 2. Amend § 52.145 by adding paragraphs (i), (j), (k), (l) and (m) to read as follow: ■ § 52.145 * * Visibility protection. * VerDate Mar<15>2010 * * 19:33 Feb 14, 2014 Jkt 232001 Kiln 1 ......... Kiln 2 ......... SO2 3.80 2.61 9.32 9.73 (4) Compliance dates. (i) The owner/ operator of each unit shall comply with the NOX emissions limitations and other NOX-related requirements of this PO 00000 Frm 00051 Fmt 4701 Sfmt 4702 9367 paragraph (i) no later than (three years after date of publication of the final rule in the Federal Register). (ii) The owner/operator of each unit shall comply with the SO2 emissions limitations and other SO2-related requirements of this paragraph (i) no later than (six months after date of publication of the final rule in the Federal Register). (5) Compliance determination—(i) Continuous emission monitoring system. At all times after the compliance dates specified in paragraph (i)(4) of this section, the owner/operator of Kiln 1 and 2 shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.13 and 40 CFR Part 60, Appendices B and F, to accurately measure the mass emission rate of NOX and SO2, in pounds per hour, from Kiln 1 and 2. The CEMS shall be used by the owner/ operator to determine compliance with the emission limitations in paragraph (i)(3) of this section, in combination with data on actual lime production. The owner/operator must operate the monitoring system and collect data at all required intervals at all times that an affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (ii) Ammonia consumption monitoring. Upon and after the completion of installation of ammonia injection on a unit, the owner or operator shall install, and thereafter maintain and operate, instrumentation to continuously monitor and record levels of ammonia consumption for that unit. (iii) Compliance determination for NOX. Compliance with the NOX emission limit described in paragraph (i)(3) of this section shall be determined based on a rolling 30 kiln-operating day basis. The 30-day rolling NOX emission rate for each kiln shall be calculated for each kiln operating day in accordance with the following procedure: Step one, sum the hourly pounds of NOX emitted for the current kiln operating day and the preceding twenty-nine (29) kiln operating days, to calculate the total pounds of NOX emitted over the most recent thirty (30) kiln operating day period for that kiln; Step two, sum the total lime product, in tons, produced during the current kiln operating day and the preceding twenty-nine (29) kiln operating days, to calculate the total lime product produced over the most E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9368 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules recent thirty (30) kiln operating day period for that kiln; Step three, divide the total amount of NOX calculated from Step one by the total lime product calculated from Step two to calculate the 30-day rolling NOX emission rate for that kiln. Each 30-day rolling NOX emission rate shall include all emissions and all lime product that occur during all periods within any kiln operating day, including emissions from startup, shutdown and malfunction. (iv) Compliance determination for SO2. Compliance with the SO2 emission limit described in paragraph (i)(3) of this section shall be determined based on a rolling 30 kiln-operating day basis. The 30-day rolling SO2 emission rate for each kiln shall be calculated for each kiln operating day in accordance with the following procedure: Step one, sum the hourly pounds of SO2 emitted for the current kiln operating day and the preceding twenty-nine (29) kiln operating days, to calculate the total pounds of SO2 emitted over the most recent thirty (30) kiln operating day period for that kiln; Step two, sum the total lime product, in tons, produced during the current kiln operating day and the preceding twenty-nine (29) kiln operating days, to calculate the total lime product produced over the most recent thirty (30) kiln operating day period for that kiln; Step three, divide the total amount of SO2 calculated from Step one by the total lime product calculated from Step two to calculate the 30-day rolling SO2 emission rate for that kiln. Each 30-day rolling SO2 emission rate shall include all emissions and all lime product that occur during all periods within any kiln operating day, including emissions from startup, shutdown and malfunction. (6) Recordkeeping. The owner/ operator shall maintain the following records for at least five years: (i) All CEMS data, including the date, place, and time of sampling or measurement; parameters sampled or measured; and results. (ii) All records of lime production. (iii) Daily 30-day rolling emission rates of NOX and SO2, when applicable, calculated in accordance with paragraphs (i)(5)(iii) and (iv) of this section. (iv) Records of quality assurance and quality control activities for emissions measuring systems including, but not limited to, any records required by 40 CFR part 60, appendix F, Procedure 1. (v) Records of ammonia consumption, as recorded by the instrumentation required in paragraph (i)(5)(ii) of this section. (vi) Records of all major maintenance activities conducted on emission units, VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 air pollution control equipment, CEMS and clinker production measurement devices. (vii) Any other records required by 40 CFR part 60, Subpart F, or 40 CFR part 60, Appendix F, Procedure 1. (7) Reporting. All reports required under this section shall be submitted by the owner/operator to the Director, Enforcement Division (Mail Code ENF– 2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this section shall be submitted within 30 days after the applicable compliance date(s) in paragraph (i)(4) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall submit a report that lists the daily 30-day rolling emission rates for NOX and SO2. (ii) The owner/operator shall submit excess emissions reports for NOX and SO2 limits. Excess emissions means emissions that exceed the emissions limits specified in paragraph (i)(3) of this section. The reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. (iii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. (iv) The owner/operator shall also submit results of any CEMS performance tests required by 40 CFR part 60, appendix F, Procedure 1 (Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder Gas Audits). (v) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the semiannual report. PO 00000 Frm 00052 Fmt 4701 Sfmt 4702 (8) Notifications. (i) The owner/ operator shall notify EPA of commencement of construction of any equipment which is being constructed to comply with the NOX emission limits in paragraph (i)(3) of this section. (ii) The owner/operator shall submit semiannual progress reports on construction of any such equipment. (iii) The owner/operator shall submit notification of initial startup of any such equipment. (9) Equipment operations. (i) At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Pollution control equipment shall be designed and capable of operating properly to minimize emissions during all expected operating conditions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the kiln. (ii) After completion of installation of ammonia injection on a unit, the owner or operator shall inject sufficient ammonia to achieve compliance with NOX emission limits from paragraph (i)(3) for that unit while preventing excessive ammonia emissions. (10) Enforcement. Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (11) Affirmative defense for malfunctions. The following provisions of the Arizona Administrative Code are incorporated by reference and made part of this Federal implementation plan: (i) R–18–2–101, paragraph 65; (ii) R18–2–310, sections (A), (B), (D) and (E) only; and (iii) R18–2–310.01. (j) Source-specific federal implementation plan for regional haze at H. Wilson Sundt Generating Station— (1) Applicability. This paragraph (j) applies to the owner and operator of the electricity generating unit (EGU) designated as Unit I4 at the H. Wilson E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules maintain and operate, instrumentation to continuously monitor and record levels of ammonia consumption for that PM10 .............................. 0.010 unit. SO2 ............................... 0.00064 (iii) Compliance determination for NOX. Compliance with the NOX (5) Compliance dates. (i) The owner/ emission limit described in paragraph operator of the unit subject to this (j)(3) of this section shall be determined paragraph shall comply with the NOX based on a rolling 30 boiler-operatingand SO2 emissions limitations of day basis. The 30-day rolling NOX paragraph (j)(3) of this section no later emission rate for the unit shall be than (three years after date of calculated for each boiler operating day publication of the final rule in the in accordance with the following Federal Register). procedure: Step one, sum the hourly (ii) The owner/operator of the unit pounds of NOX emitted for the current subject to this paragraph shall comply boiler operating day and the preceding with the PM emissions limitations of twenty-nine (29) boiler operating days, paragraph (j)(3) of this section no later to calculate the total pounds of NOX than April 16, 2015. emitted over the most recent thirty (30) (6) Alternative compliance dates. If boiler operating day period for that unit; the owner/operator chooses to comply Step two, sum the total heat input, in with the emission limits of paragraph millions of BTU, during the current (j)(4) of this section in lieu of paragraph boiler operating day and the preceding (j)(3) of this section, the owner/operator twenty-nine (29) boiler operating days, of the unit shall comply with the NOX, to calculate the total heat input over the SO2 and PM10 emissions limitations of most recent thirty (30) boiler operating paragraph (j)(4) no later than December day period for that unit; Step three, 31, 2017. divide the total amount of NOX (7) Compliance determination—(i) calculated from Step one by the total Continuous emission monitoring heat input calculated from Step two to system. (A) At all times after the calculate the 30-day rolling NOX compliance date specified in paragraph emission rate, in pounds per million (j)(5)(i) of this section, the owner/ BTU for that unit. Each 30-day rolling operator of the unit shall maintain, NOX emission rate shall include all calibrate, and operate a CEMS, in full emissions and all heat input that occur compliance with the requirements during all periods within any boiler found at 40 CFR Part 75, to accurately operating day, including emissions from measure SO2, NOX, diluent, and stack startup, shutdown and malfunction. If a gas volumetric flow rate from the unit. valid NOX pounds per hour or heat All valid CEMS hourly data shall be input is not available for any hour for used to determine compliance with the the unit, that heat input and NOX emission limitations for NOX and SO2 in pounds per hour shall not be used in the paragraph (j)(3) of this section. When calculation of the 30-day rolling the CEMS is out-of-control as defined by emission rate. Part 75, that CEMs data shall be treated (iv) Compliance determination for Pollutant emission Pollutant limit as missing data and not used to SO2. Compliance with the SO2 emission calculate the emission average. Each limit described in paragraph (j)(3) of this NOX .............................. 0.36 required CEMS must obtain valid data section shall be determined based on a PM ................................ 0.030 for at least 90 percent of the unit rolling 30 boiler-operating-day basis. SO2 ............................... 0.23 operating hours, on an annual basis. The 30-day rolling SO2 emission rate for (B) The owner/operator of the unit the unit shall be calculated for each (4) Alternative emission limitations. shall comply with the quality assurance boiler operating day in accordance with The owner/operator of the unit may procedures for CEMS found in 40 CFR the following procedure: Step one, sum choose to comply with the following Part 75. In addition to these Part 75 the hourly pounds of SO2 emitted for limitations in lieu of the emission requirements, relative accuracy test the current boiler operating day and the limitations listed in paragraph (j)(3). audits shall be calculated for both the preceding twenty-nine (29) boiler (i) The owner/operator of the unit NOX and SO2 pounds per hour operating days, to calculate the total shall combust only pipeline natural gas measurement and the heat input pounds of SO2 emitted over the most in the subject unit. measurement. The CEMs monitoring recent thirty (30) boiler operating day (ii) The owner/operator of the unit data shall not be bias adjusted. period for that unit; Step two, sum the shall not emit or cause to be emitted Calculations of relative accuracy for lb/ total heat input, in millions of BTU, pollutants in excess of the following hr of NOX, SO2 and heat input shall be during the current boiler operating day limitations, in pounds of pollutant per performed each time the Part 75 CEMS and the preceding twenty-nine (29) million british thermal units (lb/ undergo relative accuracy testing. boiler operating days, to calculate the MMBtu), from the subject unit. (ii) Ammonia consumption total heat input over the most recent monitoring. Upon and after the thirty (30) boiler operating day period Pollutant emission Pollutant completion of installation of ammonia for that unit; Step three, divide the total limit injection on the unit, the owner or amount of SO2 calculated from Step one NOX .............................. 0.25 operator shall install, and thereafter by the total heat input calculated from Sundt Generating Station located in Tucson, Pima County, Arizona. (2) Definitions. Terms not defined in this paragraph (j)(2) shall have the meaning given them in the Clean Air Act or EPA’s regulations implementing the Clean Air Act. For purposes of this paragraph (j): Ammonia injection shall include any of the following: anhydrous ammonia, aqueous ammonia or urea injection. Boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. Continuous emission monitoring system or CEMS means the equipment required by 40 CFR Part 75 and this paragraph (j). MMBtu means one million British thermal units. NOX means nitrogen oxides. Owner/operator means any person who owns or who operates, controls, or supervises the EGU identified in paragraph (j)(1) of this section. Pipeline natural gas means a naturally occurring fluid mixture of hydrocarbons as defined in 40 CFR 72.2. PM means total filterable particulate matter. PM10 means total particulate matter less than 10 microns in diameter. SO2 means sulfur dioxide. Unit means the EGU identified paragraph (j)(1) of this section. (3) Emission limitations. The owner/ operator of the unit shall not emit or cause to be emitted pollutants in excess of the following limitations, in pounds of pollutant per million british thermal units (lb/MMBtu), from the subject unit. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9369 VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Pollutant Frm 00053 Fmt 4701 Pollutant emission limit Sfmt 4702 E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9370 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Step two to calculate the 30-day rolling SO2 emission rate, in pounds per million BTU for that unit. Each 30-day rolling SO2 emission rate shall include all emissions and all heat input that occur during all periods within any boiler operating day, including emissions from startup, shutdown and malfunction. If a valid SO2 pounds per hour or heat input is not available for any hour for the unit, that heat input and SO2 pounds per hour shall not be used in the calculation of the 30-day rolling emission rate. (v) Compliance determination for PM. Compliance with the PM emission limit described in paragraph (j)(3) shall be determined from annual performance stack tests. Within sixty (60) days either preceding or following the compliance deadline specified in paragraph (j)(5)(ii) of this section, and on at least an annual basis thereafter, the owner/operator of the unit shall conduct a stack test on the unit to measure PM using EPA Method 5, in 40 CFR part 60, Appendix A. Each test shall consist of three runs, with each run at least 120 minutes in duration and each run collecting a minimum sample of 60 dry standard cubic feet. Results shall be reported in lb/MMBtu using the calculation in 40 CFR Part 60 Appendix A, Method 19. (8) Alternative compliance determination. If the owner/operator chooses to comply with the emission limits of paragraph (j)(4) of this section, this paragraph may be used in lieu of paragraph (j)(7) of this section to demonstrate compliance with the emission limits in paragraph (j)(4). (i) Continuous emission monitoring system. (A) At all times after the compliance date specified in paragraph (j)(6) of this section, the owner/operator of the unit shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR part 75, to accurately measure NOX, diluent, and stack gas volumetric flow rate from the unit. All valid CEMS hourly data shall be used to determine compliance with the emission limitations for NOX in paragraph (j)(4) of this section. When the CEMS is out-of-control as defined by Part 75, that CEMS data shall be treated as missing data and not used to calculate the emission average. Each required CEMS must obtain valid data for at least 90 percent of the unit operating hours, on an annual basis. (B) The owner/operator of the unit shall comply with the quality assurance procedures for CEMS found in 40 CFR part 75. In addition to these part 75 requirements, relative accuracy test audits shall be calculated for both the NOX pounds per hour measurement and the heat input measurement. The CEMS VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 monitoring data shall not be bias adjusted. Calculations of relative accuracy for lb/hr of NOX and heat input shall be performed each time the Part 75 CEMS undergo relative accuracy testing. (ii) Compliance determination for NOX. Compliance with the NOX emission limit described in paragraph (j)(4) of this section shall be determined based on a rolling 30 boiler-operatingday basis. The 30-day rolling NOX emission rate for the unit shall be calculated for each boiler operating day in accordance with the following procedure: Step one, sum the hourly pounds of NOX emitted for the current boiler operating day and the preceding twenty-nine (29) boiler operating days, to calculate the total pounds of NOX emitted over the most recent thirty (30) boiler operating day period for that unit; Step two, sum the total heat input, in millions of BTU, during the current boiler operating day and the preceding twenty-nine (29) boiler operating days, to calculate the total heat input over the most recent thirty (30) boiler operating day period for that unit; Step three, divide the total amount of NOX calculated from Step one by the total heat input calculated from Step two to calculate the 30-day rolling NOX emission rate, in pounds per million BTU for that unit. Each 30-day rolling NOX emission rate shall include all emissions and all heat input that occur during all periods within any boiler operating day, including emissions from startup and shutdown. If a valid NOX pounds per hour or heat input is not available for any hour for the unit, that heat input and NOX pounds per hour shall not be used in the calculation of the 30-day rolling emission rate. (iii) Compliance determination for SO2. Compliance with the SO2 emission limit for the unit shall be determined from fuel sulfur documentation demonstrating the use of pipeline natural gas. (iv) Compliance determination for PM10. Compliance with the PM10 emission limit for the unit shall be determined from performance stack tests. Within sixty (60) days following the compliance deadline specified in paragraph (j)(6) of this section, and at the request of the Regional Administrator thereafter, the owner/ operator of the unit shall conduct a stack test on the unit to measure PM10 using EPA Method 201A and Method 202, per 40 CFR part 51, Appendix M. Each test shall consist of three runs, with each run at least 120 minutes in duration and each run collecting a minimum sample of 60 dry standard cubic feet. Results shall be reported in PO 00000 Frm 00054 Fmt 4701 Sfmt 4702 lb/MMBtu using the calculation in 40 CFR part 60 Appendix A, Method 19. (9) Recordkeeping. The owner or operator shall maintain the following records for at least five years: (i) CEMS data measuring NOX in lb/ hr, SO2 in lb/hr, and heat input rate per hour. (ii) Daily 30-day rolling emission rates of NOX and SO2 calculated in accordance with paragraphs (j)(7)(iii) and (iv) of this section. (iii) Records of the relative accuracy test for NOX lb/hr and SO2 lb/hr measurement, and hourly heat input measurement. (iv) Records of quality assurance and quality control activities for emissions systems including, but not limited to, any records required by 40 CFR part 75. (v) Records of all major maintenance activities conducted on emission units, air pollution control equipment, and CEMS. (vi) Any other records required by 40 CFR part 75. (vii) Records of ammonia consumption for the unit, as recorded by the instrumentation required in paragraph (j)(7)(ii) of this section. (viii) All PM stack test results. (10) Alternative recordkeeping requirements. If the owner/operator chooses to comply with the emission limits of paragraph (j)(4) of this section, the owner/operator shall maintain the records listed in this paragraph in lieu of the records contained in paragraph (j)(9) of this section. The owner or operator shall maintain the following records for at least five years: (i) CEMS data measuring NOX in lb/ hr and heat input rate per hour. (ii) Daily 30-day rolling emission rates of NOX calculated in accordance with paragraph (j)(8)(ii) of this section. (iii) Records of the relative accuracy test for NOX lb/hr measurement and hourly heat input measurement. (iv) Records of quality assurance and quality control activities for emissions systems including, but not limited to, any records required by 40 CFR part 75. (v) Records of all major maintenance activities conducted on emission units, air pollution control equipment, and CEMS. (vi) Any other records required by 40 CFR part 75. (vii) Records sufficient to demonstrate that the fuel for the unit is pipeline natural gas. (viii) All PM10 stack test results. (11) Notifications. (i) By July 31, 2015, the owner/operator shall notify the Regional Administrator by letter whether it will comply with the emission limits in paragraph (j)(3) of this section or whether it will comply E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules with the emission limits in paragraph (j)(4) of this section. (ii) The owner/operator shall notify EPA of commencement of construction of any equipment which is being constructed to comply with either the NOX or SO2 emission limits in paragraph (j)(3) of this section. (iii) The owner/operator shall submit semiannual progress reports on construction of any such equipment. (iv) The owner/operator shall submit notification of initial startup of any such equipment. (12) Reporting. All reports required under this section shall be submitted by the owner/operator to the Director, Enforcement Division (Mail Code ENF– 2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this section shall be submitted within 30 days after the applicable compliance date(s) in paragraph (j)(5) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall submit a report that lists the daily 30-day rolling emission rates for NOX and SO2. (ii) The owner/operator shall submit excess emission reports for NOX and SO2 limits. Excess emissions means emissions that exceed the emissions limits specified in paragraph (j)(3) of this section. Excess emission reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. (iii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. (iv) The owner/operator shall submit the results of any relative accuracy test audits performed during the two preceding calendar quarters. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 (v) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the semiannual report. (vi) The owner/operator shall submit results of any PM stack tests conducted for demonstrating compliance with the PM limit specified in paragraph (j)(3). (13) Alternative reporting requirements. If the owner/operator chooses to comply with the emission limits of paragraph (j)(4) of this section, the owner/operator shall submit the reports listed in this paragraph in lieu of the reports contained in paragraph (j)(12) of this section. All reports required under this paragraph shall be submitted by the owner/operator to the Director, Enforcement Division (Mail Code ENF–2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this paragraph shall be submitted within 30 days after the applicable compliance date(s) in paragraph (j)(6) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall submit a report that lists the daily 30-day rolling emission rates for NOX. (ii) The owner/operator shall submit excess emissions reports for NOX limits. Excess emissions means emissions that exceed the emissions limits specified in paragraph (j)(4) of this section. The reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. (iii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. (iv) The owner/operator shall submit the results of any relative accuracy test PO 00000 Frm 00055 Fmt 4701 Sfmt 4702 9371 audits performed during the two preceding calendar quarters. (v) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the semiannual report. (vi) The owner/operator shall submit results of any PM10 stack tests conducted for demonstrating compliance with the PM10 limit specified in paragraph (j)(4) of this section. (14) Equipment operations. (i) At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Pollution control equipment shall be designed and capable of operating properly to minimize emissions during all expected operating conditions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (ii) After completion of installation of ammonia injection on a unit, the owner or operator shall inject sufficient ammonia to achieve compliance with NOX emission limits contained in paragraph (j)(3) of this section for that unit while preventing excessive ammonia emissions. (15) Enforcement. Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (16) Affirmative defense for malfunctions. The following provisions of the Arizona Administrative Code are incorporated by reference and made part of this federal implementation plan: (i) R–18–2–101, paragraph 65; (ii) R18–2–310, sections (A), (B), (D) and (E) only; and (iii) R18–2–310.01. (k) Source-specific federal implementation plan for regional haze at Clarkdale Cement Plant and Rillito Cement Plant—(1) Applicability. This E:\FR\FM\18FEP2.SGM 18FEP2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules and (g), to accurately measure concentration by volume of NOX, diluent, and stack gas volumetric flow rate from the in-line/raw mill stack, as well as the stack gas volumetric flow rate from the coal mill stack. The CEMS shall be used by the owner/operator to determine compliance with the emission limitation in paragraph (k)(3) of this section, in combination with data on actual clinker production. The owner/operator must operate the monitoring system and collect data at all required intervals at all times the affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (B) At all times after the compliance date specified in paragraph (k)(4) of this section, the owner/operator of the unit at the Rillito Plant shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.63(f) and (g), to accurately measure concentration by volume of NOX, diluent, and stack gas volumetric flow rate from the unit. The CEMS shall be used by the owner/ operator to determine compliance with the emission limitation in paragraph (k)(3) of this section, in combination with data on actual clinker production. The owner/operator must operate the monitoring system and collect data at all required intervals at all times the affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and NOX emission required monitoring system quality Cement Kiln limitation assurance or quality control activities Clarkdale Plant, Kiln 4 ........ 2.12 (including, as applicable, calibration Rillito Plant, Kiln 4 .............. 2.67 checks and required zero and span adjustments). (ii) Methods. (A) The owner/operator (4) Compliance date. The owner/ of each unit shall record the daily operator of each unit identified in clinker production rates. paragraph (k)(i) of this section shall (B)(1) The owner/operator of each comply with the NOX emissions unit shall calculate and record the 30limitations and other NOX-related kiln operating day average emission rate requirements of this paragraph (k) no of NOX, in lb/ton of clinker produced, later than (three years after date of as the total of all hourly emissions data publication of the final rule in the for the cement kiln in the preceding 30Federal Register). kiln operating days, divided by the total (5) Compliance determination—(i) tons of clinker produced in that kiln Continuous emission monitoring during the same 30-day operating system. (A) At all times after the period, using the following equation: compliance date specified in paragraph (k)(4) of this section, the owner/operator of the unit at the Clarkdale Plant shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.63(f) Where: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 paragraph (k) applies to each owner/ operator of the following cement kilns in the state of Arizona: Kiln 4 located at the cement plant in Clarkdale, Arizona, and Kiln 4 located at the cement plant in Rillito, Arizona. (2) Definitions. Terms not defined in this paragraph (k)(2) shall have the meaning given them in the Clean Air Act or EPA’s regulations implementing the Clean Air Act. For purposes of this paragraph (k): Ammonia injection shall include any of the following: Anhydrous ammonia, aqueous ammonia or urea injection. Continuous emission monitoring system or CEMS means the equipment required by this section to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of NOX emissions, diluent, or stack gas volumetric flow rate. Kiln operating day means a 24-hour period between 12 midnight and the following midnight during which the kiln operates. NOX means nitrogen oxides. Owner/operator means any person who owns or who operates, controls, or supervises a cement kiln identified in paragraph (k)(1) of this section. Unit means a cement kiln identified in paragraph (k)(1) of this section. (3) Emissions limitations. The owner/ operator of each unit identified in paragraph (k)(1) of this section shall not emit or cause to be emitted NOX in excess of the following limitations, in pounds per ton of clinker produced, based on a rolling 30-kiln operating day basis. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 ED = 30 kiln operating day average emission rate of NOX, lb/ton of clinker; Ci = Concentration of NOX for hour i, ppm; Qi = volumetric flow rate of effluent gas for hour i, where Ci and Qi are on the same basis (either wet or dry), scf/hr; Pi = total kiln clinker produced during production hour i, ton/hr; k = conversion factor, 1.194 × 10¥7 for NOX; and. n = number of kiln operating hours over 30 kiln operating days, n = 1 to 720. (2) For each kiln operating hour for which the owner/operator does not have at least one valid 15-minute CEMS data value, the owner/operator must use the average emissions rate (lb/hr) from the most recent previous hour for which valid data are available. Hourly clinker production shall be determined by the owner/operator in accordance with the requirements found at 40 CFR 60.63(b). (C) At the end of each kiln operating day, the owner/operator shall calculate and record a new 30-day rolling average emission rate in lb/ton clinker from the arithmetic average of all valid hourly emission rates for the current kiln operating day and the previous 29 successive kiln operating days. (D) Upon and after the completion of installation of ammonia injection on a unit, the owner/operator shall install, and thereafter maintain and operate, instrumentation to continuously monitor and record levels of ammonia consumption that unit. (6) Recordkeeping. The owner/ operator of each unit shall maintain the following records for at least five years: (i) All CEMS data, including the date, place, and time of sampling or measurement; parameters sampled or measured; and results. (ii) All records of clinker production. (iii) Daily 30-day rolling emission rates of NOX, calculated in accordance with paragraph (k)(5)(ii) of this section. (iv) Records of quality assurance and quality control activities for emissions measuring systems including, but not limited to, any records required by 40 CFR part 60, appendix F, Procedure 1. (v) Records of ammonia consumption, as recorded by the instrumentation required in paragraph (k)(5)(ii)(D) of this section. (vi) Records of all major maintenance activities conducted on emission units, air pollution control equipment, CEMS and clinker production measurement devices. (vii) Any other records required by 40 CFR part 60, Subpart F, or 40 CFR part 60, Appendix F, Procedure 1. (7) Reporting. All reports required under this section shall be submitted by the owner/operator to the Director, Enforcement Division (Mailcode ENF– E:\FR\FM\18FEP2.SGM 18FEP2 EP18FE14.000</GPH> 9372 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules 2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this section shall be submitted within 30 days after the applicable compliance date in paragraph (k)(4) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall submit a report that lists the daily 30-day rolling emission rates for NOX. (ii) The owner/operator shall submit excess emissions reports for NOX limits. Excess emissions means emissions that exceed the emissions limits specified in paragraph (k)(3) of this section. The reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. (iii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. (iv) The owner/operator shall also submit results of any CEMS performance tests required by 40 CFR part 60, appendix F, Procedure 1 (Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder Gas Audits). (v) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the reports required by paragraph (k)(7)(ii) of this section. (8) Notifications. (i) The owner/ operator shall submit notification of commencement of construction of any equipment which is being constructed to comply with the NOX emission limits in paragraph (k)(3) of this section. (ii) The owner/operator shall submit semiannual progress reports on construction of any such equipment. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 (iii) The owner/operator shall submit notification of initial startup of any such equipment. (9) Equipment operation. (i) At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Pollution control equipment shall be designed and capable of operating properly to minimize emissions during all expected operating conditions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (ii) After completion of installation of ammonia injection on a unit, the owner or operator shall inject sufficient ammonia to achieve compliance with NOX emission limits from paragraph (k)(3) for that unit while preventing excessive ammonia emissions. (10) Enforcement. Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (11) Affirmative defense for malfunctions. The following provisions of the Arizona Administrative Code are incorporated by reference and made part of this Federal implementation plan: (i) R–18–2–101, paragraph 65; (ii) R18–2–310, sections (A), (B), (D) and (E) only; and (iii) R18–2–310.01. (l) Source-specific federal implementation plan for regional haze at Hayden Copper Smelter—(1) Applicability. This paragraph (l) applies to each owner/operator of each batch copper converter and anode furnaces #1 and #2 at the copper smelting plant located in Hayden, Gila County, Arizona. (2) Definitions. Terms not defined in this paragraph (l)(2) shall have the meaning given them in the Clean Air Act or EPA’s regulations implementing the Clean Air Act. For purposes of this paragraph (l): PO 00000 Frm 00057 Fmt 4701 Sfmt 4702 9373 Anode furnace means a furnace in which molten blister copper is refined through introduction of a reducing agent such as natural gas. Batch copper converter means a Pierce-Smith converter or Hoboken converter in which copper matte is oxidized to form blister copper by a process that is performed in discrete batches using a sequence of charging, blowing, skimming, and pouring. Blister copper means an impure form of copper, typically between 98 and 99 percent pure copper that is the output of the converters. Calendar day means a 24 hour period that begins and ends at midnight, local standard time. Continuous emission monitoring system or CEMS means the equipment required by this section to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of SO2 emissions, other pollutant emissions, diluent, or stack gas volumetric flow rate. Copper matte means a material predominately composed of copper and iron sulfides produced by smelting copper ore concentrates. NOX means nitrogen oxides. Owner/operator means any person who owns or who operates, controls, or supervises the equipment identified in paragraph (l)(1) of this section. SO2 means sulfur dioxide. (3) Emission capture. (i) The owner/ operator of the batch copper converters identified in paragraph (l)(1) of this section must operate a capture system that has been designed to maximize collection of process off gases vented from each converter. At all times when one or more converters are blowing, you must operate the capture system consistent with a written operation and maintenance plan that has been prepared according to the requirements in 40 CFR 63.1447(b) and approved by EPA within 180 days of the compliance date in paragraph (l)(5) of this section. The capture system must include a primary capture system as described in 40 CFR 63.1444(d)(2) and a secondary hood as described in 40 CFR 63.1444(d)(2). (ii) The operation of the batch copper converters and secondary hood shall be optimized to capture the maximum amount of process off gases vented from each converter at all times. (4) Emission limitations and work practice standards. (i) SO2 emissions collected by the capture system required by paragraph (l)(3) of this section must be controlled by one or more control devices and reduced by at least 99.81 E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9374 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules percent, based on a 30-day rolling average. (ii) The owner/operator must not cause or allow to be discharged to the atmosphere from any primary capture system required by paragraph (l)(3) offgas that contains nonsulfuric acid particulate matter in excess of 6.2 mg/ dscm as measured using the test methods specified in 40 CFR 63.1450(b). (iii) The owner/operator must not cause or allow to be discharged to the atmosphere from any secondary capture system required by paragraph (l)(3) of this section off-gas that contains particulate matter in excess of 23 mg/ dscm as measured using the test methods specified in 40 CFR 63.1450(a). (iv) Total NOX emissions from anode furnaces #1 and #2 and the batch copper converters shall not exceed 40 tons per 12-continuous month period. (v) Anode furnaces #1 and #2 shall only be charged with blister copper or higher purity copper. (5) Compliance dates. The owner/ operator of each batch copper converter identified in paragraph (l)(1) of this section shall comply with the emissions limitations and other requirements of this section no later than (three years after date of publication of the final rule in the Federal Register). (6) Compliance determination—(i) Continuous emission monitoring system. At all times after the compliance date specified in paragraph (e) of this section, the owner/operator of each batch copper converter identified in paragraph (l)(1) of this section shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to accurately measure the mass emission rate in pounds per hour of SO2 emissions entering each control device used to control emissions from the converters, and venting from the converters to the atmosphere after passing through a control device or an uncontrolled bypass stack. The CEMS shall be used by the owner/operator to determine compliance with the emission limitation in paragraph (l)(4) of this plan. The owner/operator must operate the monitoring system and collect data at all required intervals at all times that an affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (ii) Compliance determination for SO2. The 30-day rolling SO2 emission VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 control efficiency for the converters shall be calculated for each calendar day in accordance with the following procedure: Step one, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and to each control device used to control emissions from the converters for the current calendar day and the preceding twentynine (29) calendar days, to calculate the total pounds of pre-control SO2 emissions over the most recent thirty (30) calendar day period; Step two, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and emitted from the release point of each control device used to control emissions from the converters for the current calendar day and the preceding twenty-nine (29) calendar days, to calculate the total pounds of post-control SO2 emissions over the most recent thirty (30) calendar day period; Step three, divide the total amount of post-control SO2 emissions calculated from Step two by the total amount of pre-control SO2 emissions calculated from Step one, subtract the resulting quotient from one, and multiply the difference by 100 percent to calculate the 30-day rolling SO2 emission control efficiency as a percentage. (iii) Compliance determination for nonsulfuric acid particulate matter. Compliance with the emission limit for nonsulfuric acid particulate matter in paragraph (l)(4)(ii) of this section shall be demonstrated by the procedures in 40 CFR 63.1451(b) and 40 CFR 63.1453(a)(2). (iv) Compliance determination for particulate matter. Compliance with the emission limit for particulate matter in paragraph (l)(4)(iii) of this section shall be demonstrated by the procedures in 40 CFR 63.1451(a) and 40 CFR 63.1453(a)(1). (v) Compliance determination for NOX. Compliance with the emission limit for NOX in paragraph (l)(4)(iv) of this section shall be demonstrated by monitoring natural gas consumption in each of the units identified in paragraph (l)(1) of this section for each calendar day. At the end of each calendar month, the owner/operator shall calculate 12consecutive month NOX emissions by multiplying the daily natural gas consumption rates for each unit by an approved emission factor and adding the sums for all units over the previous 12-consecutive month period. (7) Alternative compliance determination for sulfuric acid plants. If the owner/operator uses one or more double contact acid plants to control SO2 from the batch copper converters identified in paragraph (l)(1) of this section, this paragraph may be used to PO 00000 Frm 00058 Fmt 4701 Sfmt 4702 demonstrate compliance with the emission limit in paragraph (l)(4)(i) of this section. (i) Continuous emission monitoring system. At all times after the compliance date specified in paragraph (l)(5) of this section, the owner/operator of each batch copper converter identified in paragraph (l)(1) of this section shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to accurately measure the mass emission rate in pounds per hour of SO2 emissions venting from the converters to the atmosphere after passing through a control device or an uncontrolled bypass stack. The CEMS shall be used by the owner/operator to determine compliance with the emission limitation in paragraph (l)(4) of this section. The owner/operator must operate the monitoring system and collect data at all required intervals at all times that an affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (ii) Daily sulfuric acid production monitoring. At all times after the compliance date specified in paragraph (l)(5) of this section, the owner/operator of each batch copper converter subject to this section shall monitor and maintain records of sulfuric acid production for each calendar day. (iii) Compliance determination for SO2. The 30-day rolling SO2 emission rate for the converters shall be calculated for each calendar day in accordance with the following procedure: Step one, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and emitted from the release point of each double contact acid plant used to control emissions from the converters for the current calendar day and the preceding twenty-nine (29) calendar days, to calculate the total pounds of SO2 emissions over the most recent thirty (30) calendar day period; Step two, sum the total sulfuric acid production in tons of pure sulfuric acid for the current calendar day and the preceding twentynine (29) calendar days, to calculate the total tons of sulfuric acid production over the most recent thirty (30) calendar day period; Step three, divide the total amount of SO2 emissions calculated from Step one by the total tons of sulfuric acid production calculated from Step one to calculate the 30-day rolling E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules SO2 emission rate in lbs-SO2 per ton of sulfuric acid. An emission rate of 4.06 or lower shall be deemed to be in compliance with the emission limit in paragraph (i)(4) of this section. (8) Capture system monitoring. For each operating limit established under the capture system operation and maintenance plan required by paragraph (l)(4) of this section, the owner/operator must install, operate, and maintain an appropriate monitoring device according to the requirements in 40 CFR 63.1452(a)(1) though (6) to measure and record the operating limit value or setting at all times the required capture system is operating. Dampers that are manually set and remain in the same position at all times the capture system is operating are exempted from these monitoring requirements. (9) Recordkeeping. The owner/ operator shall maintain the following records for at least five years: (i) All CEMS data, including the date, place, and time of sampling or measurement; parameters sampled or measured; and results. (ii) Records of quality assurance and quality control activities for emissions measuring systems including, but not limited to, any records required by 40 CFR part 60, appendix F, Procedure 1. (iii) Records of all major maintenance activities conducted on emission units, air pollution control equipment, and CEMS. (iv) Any other records required by 40 CFR part 60, Subpart F, or 40 CFR part 60, Appendix F, Procedure 1. (v) Records of all monitoring required by paragraph (l)(8) of this section. (vi) Records of daily sulfuric acid production in tons per day of pure sulfuric acid if the owner/operator chooses to use the alternative compliance determination method in paragraph (l)(7) of this section. (vii) Records of daily natural gas consumption in each units identified in paragraph (l)(1) and all calculations performed to demonstrate compliance with the limit in paragraph (l)(4)(iv). (10) Reporting. All reports required under this section shall be submitted by the owner/operator to the Director, Enforcement Division (Mail Code ENF– 2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this section shall be submitted within 30 days after the applicable compliance date in paragraph (l)(5) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall promptly submit excess emissions reports for the SO2 limit. Excess emissions means emissions that exceed the emissions limit specified in paragraph (d) of this section. The reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. For the purpose of this paragraph, promptly shall mean within 30 days after the end of the month in which the excess emissions were discovered. (ii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. The owner/operator shall submit reports semiannually. (iii) The owner/operator shall also submit results of any CEMS performance tests required by 40 CFR part 60, appendix F, Procedure 1 (Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder Gas Audits). (iv) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the semiannual report. (v) When performance testing is required to determine compliance with an emission limit in paragraph (l)(4) of this section, the owner/operator shall submit test reports as specified in 40 CFR part 63, subpart A. (11) Notifications. (i) The owner/ operator shall notify EPA of commencement of construction of any equipment which is being constructed to comply with the capture or emission limits in paragraph (l)(3) or (4) of this section. (ii) The owner/operator shall submit semiannual progress reports on construction of any such equipment. (iii) The owner/operator shall submit notification of initial startup of any such equipment. PO 00000 Frm 00059 Fmt 4701 Sfmt 4702 9375 (12) Equipment operations. At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Pollution control equipment shall be designed and capable of operating properly to minimize emissions during all expected operating conditions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (13) Enforcement. Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. (14) Affirmative defense for malfunctions. The following provisions of the Arizona Administrative Code are incorporated by reference and made part of this Federal implementation plan: (i) R–18–2–101, paragraph 65; (ii) R18–2–310, sections (A), (B), (D) and (E) only; and (iii) R18–2–310.01. (m) Source-specific federal implementation plan for regional haze at Miami Copper Smelter—(1) Applicability. This paragraph (m) applies to each owner/operator of each batch copper converter and the electric furnace at the copper smelting plant located in Hayden, Gila County, Arizona. (2) Definitions. Terms not defined in this paragraph (m)(2) shall have the meaning given them in the Clean Air Act or EPA’s regulations implementing the Clean Air Act. For purposes of this paragraph (m): Batch copper converter means a Pierce-Smith converter or Hoboken converter in which copper matte is oxidized to form blister copper by a process that is performed in discrete batches using a sequence of charging, blowing, skimming, and pouring. Calendar day means a 24 hour period that begins and ends at midnight, local standard time. E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 9376 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules Continuous emission monitoring system or CEMS means the equipment required by this section to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of SO2 emissions, other pollutant emissions, diluent, or stack gas volumetric flow rate. Copper matte means a material predominately composed of copper and iron sulfides produced by smelting copper ore concentrates. Electric furnace means a furnace in which copper matte and slag are heated by electrical resistance without the mechanical introduction of air or oxygen. NOX means nitrogen oxides. Owner/operator means any person who owns or who operates, controls, or supervises the equipment identified in paragraph (m)(1) of this section. Slag means the waste material consisting primarily of iron sulfides separated from copper matte during the smelting and refining of copper ore concentrates. SO2 means sulfur dioxide. (3) Emission capture. (i)The owner/ operator of the batch copper converters identified in paragraph (m)(1) of this section must operate a capture system that has been designed to maximize collection of process off gases vented from each converter. At all times when one or more converters are blowing, you must operate the capture system consistent with a written operation and maintenance plan that has been prepared according to the requirements in 40 CFR 63.1447(b) and approved by EPA within 180 days of the compliance date in paragraph (m)(5) of this section. The capture system must include a primary capture system as described in 40 CFR 63.1444(d)(3) and a secondary hood as described in 40 CFR 63.1444(d)(2). (ii) The operation of the batch copper converters and secondary hood shall be optimized to capture the maximum amount of process off gases vented from each converter at all times. (4) Emission limitations and work practice standards. (i) SO2 emissions collected by the capture system required by paragraph (m)(3) of this section must be controlled by one or more control devices and reduced by at least 99.7 percent, based on a 30-day rolling average. (ii) Total NOX emissions the electric furnace and the batch copper converters shall not exceed 40 tons per 12continuous month period. (iii) The owner/operator shall not actively aerate the electric furnace. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 (5) Compliance dates. The owner/ operator of each batch copper converter identified in paragraph (m)(1) of this section shall comply with the emissions limitations and other requirements of this section no later than (three years after date of publication of the final rule in the Federal Register). (6) Compliance determination—(i) Continuous emission monitoring system. At all times after the compliance date specified in paragraph (e) of this section, the owner/operator of each batch copper converter identified in paragraph (m)(1) of this section shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to accurately measure the mass emission rate in pounds per hour of SO2 emissions entering each control device used to control emissions from the converters, and venting from the converters to the atmosphere after passing through a control device or an uncontrolled bypass stack. The CEMS shall be used by the owner/operator to determine compliance with the emission limitation in paragraph (m)(4) of this section. The owner/operator must operate the monitoring system and collect data at all required intervals at all times that an affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (ii) Compliance determination for SO2. The 30-day rolling SO2 emission control efficiency for the converters shall be calculated for each calendar day in accordance with the following procedure: Step one, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and to each control device used to control emissions from the converters for the current calendar day and the preceding twentynine (29) calendar days, to calculate the total pounds of pre-control SO2 emissions over the most recent thirty (30) calendar day period; Step two, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and emitted from the release point of each control device used to control emissions from the converters for the current calendar day and the preceding twenty-nine (29) calendar days, to calculate the total pounds of post-control SO2 emissions over the most recent thirty (30) calendar day period; Step three, divide the total amount of post-control SO2 emissions calculated from Step two by the total PO 00000 Frm 00060 Fmt 4701 Sfmt 4702 amount of pre-control SO2 emissions calculated from Step one, subtract the resulting quotient from one, and multiply the difference by 100 percent to calculate the 30-day rolling SO2 emission control efficiency as a percentage. (iii) Compliance determination for NOX. Compliance with the emission limit for NOX in paragraph (m)(4)(ii) of this section shall be demonstrated by monitoring natural gas consumption in each of the units identified in paragraph (m)(1) of this section for each calendar day. At the end of each calendar month, the owner/operator shall calculate monthly and 12-consecutive month NOX emissions by multiplying the daily natural gas consumption rates for each unit by an approved emission factor and adding the sums for all units over the previous 12-consecutive month period. (7) Alternative compliance determination for sulfuric acid plants. If the owner/operator uses one or more double contact acid plants to control SO2 from the batch copper converters identified in paragraph (m)(1) of this section, this paragraph may be used to demonstrate compliance with the emission limit in paragraph (m)(4)(i) of this section. (i) Continuous emission monitoring system. At all times after the compliance date specified in paragraph (m)(5) of this section, the owner/operator of each batch copper converter identified in paragraph (m)(1) of this section shall maintain, calibrate, and operate a CEMS, in full compliance with the requirements found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to accurately measure the mass emission rate in pounds per hour of SO2 emissions venting from the converters to the atmosphere after passing through a control device or an uncontrolled bypass stack. The CEMS shall be used by the owner/operator to determine compliance with the emission limitation in paragraph (m)(4) of this section. The owner/operator must operate the monitoring system and collect data at all required intervals at all times that an affected unit is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments). (ii) Daily sulfuric acid production monitoring. At all times after the compliance date specified in paragraph (m)(5) of this section, the owner/ operator of each batch copper converter subject to this section shall monitor and E:\FR\FM\18FEP2.SGM 18FEP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules maintain records of sulfuric acid production for each calendar day. (iii) Compliance determination for SO2. The 30-day rolling SO2 emission rate for the converters shall be calculated for each calendar day in accordance with the following procedure: Step one, sum the hourly pounds of SO2 vented to each uncontrolled bypass stack and emitted from the release point of each double contact acid plant used to control emissions from the converters for the current calendar day and the preceding twenty-nine (29) calendar days, to calculate the total pounds of SO2 emissions over the most recent thirty (30) calendar day period; Step two, sum the total sulfuric acid production in tons of pure sulfuric acid for the current calendar day and the preceding twentynine (29) calendar days, to calculate the total tons of sulfuric acid production over the most recent thirty (30) calendar day period; Step three, divide the total amount of SO2 emissions calculated from Step one by the total tons of sulfuric acid production calculated from Step one to calculate the 30-day rolling SO2 emission rate in lbs-SO2 per ton of sulfuric acid. An emission rate of 4.06 or lower shall be deemed to be in compliance with the emission limit in paragraph (i)(4) of this section. (8) Capture system monitoring. For each operating limit established under the capture system operation and maintenance plan required by paragraph (m)(4) of this section, the owner/ operator must install, operate, and maintain an appropriate monitoring device according to the requirements in 40 CFR 63.1452(a)(1) though (6) to measure and record the operating limit value or setting at all times the required capture system is operating. Dampers that are manually set and remain in the same position at all times the capture system is operating are exempted from these monitoring requirements. (9) Recordkeeping. The owner/ operator shall maintain the following records for at least five years: (i) All CEMS data, including the date, place, and time of sampling or measurement; parameters sampled or measured; and results. (ii) Records of quality assurance and quality control activities for emissions measuring systems including, but not limited to, any records required by 40 CFR part 60, appendix F, Procedure 1. (iii) Records of all major maintenance activities conducted on emission units, air pollution control equipment, and CEMS. (iv) Any other records required by 40 CFR part 60, Subpart F, or 40 CFR part 60, Appendix F, Procedure 1. VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 (v) Records of all monitoring required by paragraph (m)(8) of this section. (vi) Records of daily sulfuric acid production in tons per day of pure sulfuric acid if the owner/operator chooses to use the alternative compliance determination method in paragraph (m)(7) of this section. (vii) Records of daily natural gas consumption in each units identified in paragraph (m)(1) and all calculations performed to demonstrate compliance with the limit in paragraph (m)(4)(iv). (10) Reporting. All reports required under this section shall be submitted by the owner/operator to the Director, Enforcement Division (Mail Code ENF– 2–1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105–3901. All reports required under this section shall be submitted within 30 days after the applicable compliance date in paragraph (m)(5) of this section and at least semiannually thereafter, within 30 days after the end of a semiannual period. The owner/operator may submit reports more frequently than semiannually for the purposes of synchronizing reports required under this section with other reporting requirements, such as the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual period exceed six months. (i) The owner/operator shall promptly submit excess emissions reports for the SO2 limit. Excess emissions means emissions that exceed the emissions limit specified in paragraph (d) of this section. The reports shall include the magnitude, date(s), and duration of each period of excess emissions, specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted. For the purpose of this paragraph, promptly shall mean within 30 days after the end of the month in which the excess emissions were discovered. (ii) The owner/operator shall submit CEMS performance reports, to include dates and duration of each period during which the CEMS was inoperative (except for zero and span adjustments and calibration checks), reason(s) why the CEMS was inoperative and steps taken to prevent recurrence, and any CEMS repairs or adjustments. The owner/operator shall submit reports semiannually. (iii) The owner/operator shall also submit results of any CEMS PO 00000 Frm 00061 Fmt 4701 Sfmt 4702 9377 performance tests required by 40 CFR part 60, appendix F, Procedure 1 (Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder Gas Audits). (iv) When no excess emissions have occurred or the CEMS has not been inoperative, repaired, or adjusted during the reporting period, the owner/operator shall state such information in the semiannual report. (v) When performance testing is required to determine compliance with an emission limit in paragraph (m)(4) of this section, the owner/operator shall submit test reports as specified in 40 CFR part 63, subpart A. (11) Notifications. (i) The owner/ operator shall notify EPA of commencement of construction of any equipment which is being constructed to comply with the capture or emission limits in paragraph (m)(3) or (4) of this section. (ii) The owner/operator shall submit semiannual progress reports on construction of any such equipment. (iii) The owner/operator shall submit notification of initial startup of any such equipment. (12) Equipment operations. At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the unit including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Pollution control equipment shall be designed and capable of operating properly to minimize emissions during all expected operating conditions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, review of operating and maintenance procedures, and inspection of the unit. (13) Enforcement. Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant as to whether the unit would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard or applicable emission limit in the plan. E:\FR\FM\18FEP2.SGM 18FEP2 9378 Federal Register / Vol. 79, No. 32 / Tuesday, February 18, 2014 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 (14) Affirmative defense for malfunctions. The following provisions of the Arizona Administrative Code are VerDate Mar<15>2010 19:33 Feb 14, 2014 Jkt 232001 incorporated by reference and made part of this federal implementation plan: (i) R–18–2–101, paragraph 65; (ii) R18–2–310, sections (A), (B), (D) and (E) only; and PO 00000 Frm 00062 Fmt 4701 Sfmt 9990 (iii) R18–2–310.01. [FR Doc. 2014–02714 Filed 2–14–14; 8:45 am] BILLING CODE 6560–50–P E:\FR\FM\18FEP2.SGM 18FEP2

Agencies

[Federal Register Volume 79, Number 32 (Tuesday, February 18, 2014)]
[Proposed Rules]
[Pages 9317-9378]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-02714]



[[Page 9317]]

Vol. 79

Tuesday,

No. 32

February 18, 2014

Part II





Environmental Protection Agency





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40 CFR Part 51





Promulgation of Air Quality Implementation Plans; Arizona; Regional 
Haze and Interstate Visibility Transport Federal Implementation Plan; 
Proposed Rule

Federal Register / Vol. 79 , No. 32 / Tuesday, February 18, 2014 / 
Proposed Rules

[[Page 9318]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 51

[EPA-R09-OAR-2013-0588, FRL-9906-30-Region 9]


Promulgation of Air Quality Implementation Plans; Arizona; 
Regional Haze and Interstate Visibility Transport Federal 
Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This proposed Federal Implementation Plan (FIP) addresses the 
requirements of the Regional Haze Rule (RHR) and interstate visibility 
transport for the disapproved portions of Arizona's Regional Haze (RH) 
State Implementation Plan (SIP) as described in our final rule 
published on July 30, 2013. Our final rule on Arizona's RH SIP 
partially approved and partially disapproved the State's plan to 
implement the regional haze program for the first planning period. 
Today's proposed rule addresses the RHR's requirements for Best 
Available Retrofit Technology (BART), Reasonable Progress Goals (RPGs) 
and Long-term Strategy (LTS) as well as the interstate visibility 
transport requirements for pollutants that affect visibility in 
Arizona's 12 Class I areas as well as areas in nearby states. The BART 
sources addressed in this proposed FIP are Tucson Electric Power (TEP) 
Sundt Generating Station Unit 4, Lhoist Nelson Lime Plant Kilns 1 and 
2, ASARCO Incorporated Hayden Smelter, and Freeport-McMoran Inc. (FMMI) 
Miami Smelter. The sources with proposed controls for reasonable 
progress are the Phoenix Cement Clarkdale Plant and the CalPortland 
Cement Rillito Plant.

DATES: Written comments must be submitted to the designated contact at 
the address in the General Information section of SUPPLEMENTARY 
INFORMATION on or before March 31, 2014.

ADDRESSES: See the General Information section of SUPPLEMENTARY 
INFORMATION for further instructions on where and how to learn more 
about this proposal, attend a public hearing, or submit comments.

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9, 
Planning Office, Air Division, Air, 75 Hawthorne Street, San Francisco, 
CA 94105. Thomas Webb may be reached at telephone number (415) 947-4139 
and via electronic mail at r9azreghaze@epa.gov.

SUPPLEMENTARY INFORMATION: 

Table of Contents

I. General Information
    A. Definitions
    B. Docket
    C. Instructions for Submitting Comments to EPA
    D. Submitting Confidential Business Information
    E. Tips for Preparing Your Comments
    F. Public Hearings
II. Proposed Actions Background and Overview
    A. Background
    B. Regional Haze
    C. Interstate Transport of Pollutants That Affect Visibility
III. Review of State and EPA Actions on Regional Haze
    A. EPA's Schedule To Act on Arizona's RH SIP
    B. History of State Submittals and EPA Actions
    C. EPA's Authority To Promulgate a FIP
IV. EPA's BART Process
    A. BART Factors
    B. Visibility Analysis
    C. Explanation of Visibility Tables
V. EPA's Proposed BART Analyses and Determinations
    A. Sundt Generating Station Unit 4
    B. Nelson Lime Plant Kilns 1 and 2
    C. Hayden Smelter
    D. Miami Smelter
VI. EPA's Proposed Reasonable Progress Analyses and Determinations
    A. Reasonable Progress Analysis of Point Sources for 
NOX
    B. Reasonable Progress Analysis of Area Sources for 
NOX and SO2
    C. Reasonable Progress Goals
    D. Meeting the Uniform Rate of Progress
VII. EPA's Proposed Long-Term Strategy Supplement
    A. Emission Reductions for Out-of-State Class I Areas
    B. Emissions Limitations and Schedules for Compliance To Achieve 
RPGs
    C. Enforceability of Emissions Limitations and Control Measures
    D. Proposed Partial LTS FIP
VIII. EPA's Proposal for Interstate Transport
IX. Summary of Proposed Actions
    A. Regional Haze
    B. Interstate Transport
X. 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 Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and 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. Definitions

    (1) The words or initials Act or CAA mean or refer to the Clean Air 
Act, unless the context indicates otherwise.
    (2) The initials ADEQ mean or refer to the Arizona Department of 
Environmental Quality.
    (3) The words Arizona and State mean the State of Arizona.
    (4) The initials BACT mean or refer to Best Available Control 
Technology.
    (5) The initials BART mean or refer to Best Available Retrofit 
Technology.
    (6) The initials BOD mean or refer to boiler operating day.
    (7) The term Class I area refers to a mandatory Class I Federal 
area.
    (8) The initials CEMS refers to continuous emission monitoring 
system or systems.
    (9) The initials dv mean or refer to deciview, a measure of visual 
range.
    (10) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
    (11) The initials FGD mean or refer to flue gas desulfurization.
    (12) The initials FIP mean or refer to Federal Implementation Plan.
    (13) The initials FLM mean or refer to Federal Land Managers.
    (14) The initials IMPROVE mean or refer to Interagency Monitoring 
of Protected Visual Environments monitoring network.
    (15) The initials IPM mean or refer to Integrated Planning Model.
    (16) The initials lb/MMBtu mean or refer to pounds per one million 
British thermal units.
    (17) The initials LDSCR and HDSCR mean or refer to low and high 
dust Selective Catalytic Reduction, respectively.
    (18) The initials LNB mean or refer to low NOX burners.
    (19) The initials LTS mean or refer to Long-term Strategy.
    (20) The initials MACT mean or refer to Maximum Achievable Control 
Technology.
    (21) The initials MW mean or refer to megawatts.
    (22) The initials NAAQS mean or refer to National Ambient Air 
Quality Standards.
    (23) The initials NEI mean or refer to National Emissions 
Inventory.
    (24) The initials NESCAUM mean or refer to Northeast States for 
Coordinated Air Use Management.
    (25) The initials NM mean or refer to National Monument.
    (26) The initials NOX mean or refer to nitrogen oxides.

[[Page 9319]]

    (27) The initials NP mean or refer to National Park.
    (28) The initials NPS mean or refer to the National Park Service.
    (29) The initials NSCR mean or refer to non-selective catalytic 
reduction.
    (30) The initials NSPS mean or refer to new source performance 
standards.
    (31) The initials PM mean or refer to particulate matter.
    (32) The initials PM2.5 mean or refer to fine particulate matter 
with an aerodynamic diameter of less than 2.5 micrometers.
    (33) The initials PM10 mean or refer to particulate matter with an 
aerodynamic diameter of less than 10 micrometers.
    (34) The initials PSAT mean or refer to Particulate Source 
Apportionment Technology.
    (35) The initials PSD mean or refer to Prevention of Significant 
Deterioration.
    (36) The initials PTE mean or refer to potential to emit.
    (37) The initials RH mean or refer to regional haze.
    (38) The initials RHR mean or refer to the Regional Haze Rule, 
originally promulgated in 1999 and codified at 40 CFR 51.301-309.
    (39) The initials RMC mean or refer to Regional Modeling Center.
    (40) The initials RP mean or refer to Reasonable Progress.
    (41) The initials RPG or RPGs mean or refer to Reasonable Progress 
Goal(s).
    (42) The initials SCR mean or refer to Selective Catalytic 
Reduction.
    (43) The initials SIP mean or refer to State Implementation Plan.
    (44) The initials SNCR mean or refer to Selective Non-catalytic 
Reduction.
    (45) The initials SO2 mean or refer to sulfur dioxide.
    (46) The initials SOFA mean or refer to Separated Overfire Air.
    (47) The initials SRP mean or refer to Salt River Project 
Agricultural Improvement and Power District.
    (48) The initials tpy mean tons per year.
    (49) The initials TSD mean or refer to Technical Support Document.
    (50) The initials TSF mean or refer to tons of stone feed.
    (51) The initials ULNB mean or refer to ultra-low NOX 
burners.
    (52) The initials URP mean or refer to Uniform Rate of Progress.
    (53) The initials VOC mean or refer to volatile organic compounds.
    (54) The initials WRAP mean or refer to the Western Regional Air 
Partnership.

 B. Docket

    This proposed action relies on documents, information and data that 
are listed in the index on http://www.regulations.gov under docket 
number EPA-R09-OAR-2013-0588. Previous proposed and final actions 
regarding Arizona's RH SIP are under docket number EPA-R09-OAR-2012-
0904 and EPA-R09-OAR-2012-0021. Although listed in the index, some 
information is not publicly available (e.g., Confidential Business 
Information (CBI)). Certain other material, such as copyrighted 
material, is publicly available only in hard copy form. Publicly 
available docket materials are available either electronically at 
http://www.regulations.gov or in hard copy at the Planning Office of 
the Air Division, AIR-2, EPA Region 9, 75 Hawthorne Street, San 
Francisco, CA 94105. EPA requests that you contact the individual 
listed in the FOR FURTHER INFORMATION CONTACT section to view the hard 
copy of the docket. You may view the hard copy of the docket Monday 
through Friday, 9-5 PST, excluding Federal holidays.

C. Instructions for Submitting Comments to EPA

    Written comments must be submitted on or before March 31, 2014. 
Submit your comments, identified by Docket ID No. EPA-R09-OAR-2013-
0588, by one of the following methods:
     Federal Rulemaking portal: http://www.regulations.gov. 
Follow the on-line instructions for submitting comments.
     Email: r9azreghaze@epa.gov.
     Fax: 415-947-3579 (Attention: Thomas Webb).
     Mail, Hand Delivery or Courier: Thomas Webb, EPA Region 9, 
Air Division (AIR-2), 75 Hawthorne Street, San Francisco, California 
94105. Hand and courier deliveries are only accepted Monday through 
Friday, 8:30 a.m. to 4:30 p.m., excluding Federal holidays. Special 
arrangements should be made for deliveries of boxed information.
    EPA's policy is to include all comments received in the public 
docket without change.

We may make comments available online at http://www.regulations.gov, 
including any personal information provided, unless the comment 
includes information claimed to be CBI or other information for which 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or that is otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an email comment directly to EPA, without 
going through http://www.regulations.gov, we will include your email 
address as part of the comment that is placed in the public docket and 
made available on the Internet. If you submit an electronic comment, 
EPA recommends that you include your name and other contact information 
in the body of your comment and with any disk or CD-ROM you submit. If 
EPA cannot read your comment due to technical difficulties and cannot 
contact you for clarification, EPA may not be able to consider your 
comment. Electronic files should not include special characters or any 
form of encryption, and be free of any defects or viruses.

D. Submitting Confidential Business Information

    Do not submit CBI to EPA through http://www.regulations.gov or 
email. Clearly mark the part or all of the information that you claim 
as CBI. For CBI information in a disk or CD ROM that you mail to EPA, 
mark the outside of the disk or CD ROM as CBI and identify 
electronically within the disk or CD ROM the specific information that 
is claimed as CBI. In addition to one complete version of the comment 
that includes information claimed as CBI, you must submit a copy of the 
comment that does not contain the information claimed as CBI for 
inclusion in the public docket. We will not disclose information so 
marked except in accordance with procedures set forth in 40 CFR part 2.

 E. Tips for Preparing Comments

    When submitting comments, remember to:
     Identify the rulemaking by docket number and other 
identifying information (e.g., subject heading, Federal Register date 
and page number).
     Explain why you agree or disagree; suggest alternatives 
and substitute language for your requested changes.
     Describe any assumptions and provide any technical 
information and/or data that you used.
     If you estimate potential costs or burdens, explain how 
you arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
     Provide specific examples to illustrate your concerns, and 
suggest alternatives.
     Explain your views as clearly as possible, avoiding 
profanity or personal threats.
     Make sure to submit your comments by the identified 
comment period deadline.
    To provide opportunities for questions and discussion, EPA will 
hold an open house prior to the public hearing. During the open house, 
EPA staff will be available informally to

[[Page 9320]]

answer questions on our proposed rule. Any comments made to EPA staff 
during the open house must still be provided formally in writing or 
orally during a public hearing to be considered in the record. The open 
house and public hearing schedule is as follows.

 F. Public Hearings

    EPA will hold two public hearings at the dates, times and locations 
stated below to accept oral and written comments into the record. To 
request interpretation services or to request reasonable accommodation 
for a disability, please contact the person in the FOR FURTHER 
INFORMATION CONTACT section by February 14, 2014.
    Public Hearing in Phoenix:
    Date: February 25, 2014.
    Open House: 4-5 p.m.
    Public Hearing: 6-8 p.m.
    Location: Phoenix Convention Center, Rooms 150-153, 33 South 3rd 
Street, Phoenix, Arizona 85004.
    Public Hearing in Tucson:
    Date: February 26, 2014.
    Open House: 4-5 p.m.
    Public Hearing: 6-8 p.m.
    Location: Tucson High Magnet School, Auditorium, 400 North 2nd 
Avenue, Tucson, Arizona 85705.
    The public hearing will provide the public with an opportunity to 
present views or information concerning the proposed RH FIP for 
Arizona. EPA may ask clarifying questions during the oral 
presentations, but will not respond to the presentations at that time. 
We will consider written statements and supporting information 
submitted during the comment period with the same weight as any oral 
comments and supporting information presented at the public hearing. 
Please consult section I.C, I.D and I.E of this preamble for guidance 
on how to submit written comments to EPA. We will include verbatim 
transcripts of the hearing in the docket for this action. The EPA 
Region 9 Web site for the rulemaking, which includes the proposal and 
information about the public hearing, is at http://www.epa.gov/region9/air/actions.

II. Proposed Actions Background and Overview

A. Background

    The Clean Air Act (CAA) establishes as a national goal the 
prevention of any future, and the remedying of any existing man-made 
impairment of visibility in 156 national parks and wilderness areas 
designated as Class I areas. Arizona has a wealth of such areas. The 
sources addressed in this FIP affect many Class I areas in the State of 
Arizona and adjacent states. This FIP will ensure that progress is made 
toward natural visibility conditions at these national treasures, as 
Congress intended when it directed EPA to improve visibility in 
national parks and wilderness areas. Please refer to our previous 
rulemaking on the Arizona RH SIP for additional background regarding 
the CAA, regional haze and EPA's RHR.\1\
---------------------------------------------------------------------------

    \1\ 77 FR 75704, 75707-75702 (December 21, 2012).
---------------------------------------------------------------------------

B. Regional Haze

    We propose to promulgate a FIP as described in this notice and 
summarized in this section to address those portions of Arizona's RH 
SIP that we disapproved on July 30, 2013.\2\ We disapproved in part 
Arizona's BART control analyses and determinations for four sources, 
Reasonable Progress Goal (RPG) analyses and determinations, and Long-
term Strategy (LTS) for making reasonable progress. The proposed FIP 
includes emission limits, compliance schedules and requirements for 
equipment maintenance, monitoring, testing, recordkeeping and reporting 
for all affected sources and units. The regulatory language for the 
proposed FIP requirements is under Part 52 at the end of this notice.
---------------------------------------------------------------------------

    \2\ 78 FR 46142.
---------------------------------------------------------------------------

 1. Proposed BART Determinations
    EPA conducted BART analyses and determinations for four sources: 
Sundt Generating Station Unit 4, Nelson Lime Plant Kilns 1 and 2, 
Hayden Smelter and Miami Smelter. The results of our BART evaluations 
are summarized here for each source and are shown in Table 1. We are 
seeking comments on our proposals.
    Sundt: We propose that Sundt Unit 4 is BART-eligible and subject to 
BART for sulfur dioxide (SO2), nitrogen oxides 
(NOX) and particulate matter with aerodynamic diameter less 
than 10 micrometers (PM10). For NOX, we propose 
an emission limit of 0.36 lb/MMBtu as BART based upon an annual 
capacity factor of 0.49, which is consistent with the use of Selective 
Non-Catalytic Reduction (SNCR) as a control technology. For 
SO2, we propose an emission limit of 0.23 lb/MMBtu as BART 
on a 30-day boiler operating day (BOD) rolling basis, which is 
consistent with dry sorbent injection (DSI) as a control technology. 
For PM10, we propose a filterable PM10 emission 
limit of 0.030 lb/MMBtu as BART based on the use of the existing fabric 
filter baghouse. We also are proposing a switch to natural gas as a 
better-than-BART alternative to the other proposed controls for all 
three pollutants.
    Nelson Lime Plant: We propose that Nelson Lime Kilns 1 and 2 are 
subject to BART for NOX, SO2 and PM10. 
For NOX, we propose a BART emission limit at Kiln 1 of 3.80 
lb/ton lime and at Kiln 2 of 2.61 lb/ton lime on a 30-day rolling basis 
as verified by continuous emission monitoring systems (CEMS). This 
emission limit is consistent with the use of low-NOX burners 
(LNB) and SNCR as control technologies. We propose that BART for 
SO2 is an emission limit of 9.32 lb/ton for Kiln 1 and 9.73 
lb/ton for Kiln 2 on a 30-day rolling basis, which is consistent with 
the use of a lower sulfur fuel blend. For PM10, we propose a 
BART emission limit of 0.12 lb/tons of stone feed (TSF) to control 
PM10 at Kilns 1 and 2 based on the use of the existing 
fabric filter baghouses. This level of control is commensurate with the 
MACT standard that applies to this source.
    Hayden Smelter: We propose that the Hayden Smelter is subject to 
BART for NOX, and propose BART emission limits for 
NOX and SO2. EPA previously approved the State's 
determination that the Hayden Smelter is subject to BART for 
SO2. For NOX, we propose to find that controlling 
emissions from the converters and anode furnaces is cost-effective, but 
would not result in sufficient visibility improvement to warrant the 
cost. Therefore, we are proposing an annual emission limit of 40 tpy 
NOX emissions from the BART-eligible units, which is 
consistent with current emissions from these units. For SO2 
from the converters, we propose a BART control efficiency of 99.8 
percent on a 30-day rolling basis on all SO2 captured by 
primary and secondary control systems, which can be achieved with a new 
double contact acid plant. For SO2 from the anode furnaces, 
we propose to find that controlling the 37 tons per year (tpy) of 
SO2 emissions from these furnaces, while cost-effective, is 
not warranted as BART given the potential for only minimal visibility 
improvement. We propose as an emission limitation for the anode furnace 
a work practice standard requiring that the furnaces only be charged 
with blister copper or higher purity copper. We previously approved 
Arizona's determination that BART for PM10 at the Hayden 
Smelter is no additional controls. In order to ensure the 
enforceability of this determination, we are proposing to incorporate 
emission limitations and associated compliance requirements from the 
National Emission Standard for Hazardous Air Pollutants (NESHAP) for

[[Page 9321]]

Primary Copper Smelting at 40 CFR Part 63, Subpart QQQ, as part of the 
LTS.
    Miami Smelter: EPA proposes that the Miami Smelter is subject to 
BART for NOX, and proposes BART emission limits for 
NOX and SO2. EPA previously approved the State's 
determination that the Miami Smelter is subject to BART for 
SO2. For NOX, we propose to find that controlling 
the small amount of emissions from the converters and electric furnace 
is cost-effective, but would not result in sufficient visibility 
improvement to warrant the cost. Therefore, we are proposing an annual 
emission limit of 40 tpy NOX emissions from the BART-
eligible units, which is consistent with current emissions. For 
SO2 from the converters, we propose a BART control 
efficiency of 99.7 percent on a 30-day rolling basis on all 
SO2 emissions captured by the primary and secondary control 
systems as verified by CEMS. This control efficiency could be met 
through improvements to the primary capture system, construction of a 
secondary capture system, and application of the MACT QQQ standards to 
the capture systems. For SO2 emissions from the electric 
furnace, we propose as BART the work practice standard to prohibit 
active aeration. We previously approved Arizona's determination that 
BART for PM10 at the Miami Smelter is the NESHAP for Primary 
Copper Smelting. We now propose to find that the federally enforceable 
provisions of the NESHAP, which apply to the Miami Smelter and are 
incorporated into its Title V Permit, are sufficient to ensure the 
enforceability of this determination.

                                                    Table 1--Proposed Emission Limits on BART Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                Corresponding control
               Source                          Units                  Pollutants           Limit             Measure                  technology
--------------------------------------------------------------------------------------------------------------------------------------------------------
Sundt Generating Station............  Unit 4.................  NOX....................         0.36  lb/MMBtu..............  Selective Non-Catalytic
                                                               SO2....................         0.23                           Reduction.
                                                               PM10...................        0.030                          Dry Sorbent Injection.
                                                                                                                             Fabric filter baghouse
                                                                                                                              (existing).
                                      Unit 4 (Alternative)...  NOX....................         0.25  lb/MMBtu..............  Switch to natural gas.
                                                               SO2....................      0.00064
                                                               PM10...................        0.010
Chemical Lime Nelson................  Kiln 1.................  NOX....................         3.80  lb/ton feed...........  Selective Non-Catalytic
                                                               SO2....................         9.32                           Reduction.
                                                               PM10...................         0.12                          Lower sulfur fuel.
                                                                                                                             Fabric filter baghouse
                                                                                                                              (existing).
                                      Kiln 2.................  NOX....................         2.61  ......................  Selective Non-Catalytic
                                                               SO2....................         9.73                           Reduction.
                                                               PM10...................         0.12                          Lower sulfur fuel.
                                                                                                                             Fabric filter baghouse
                                                                                                                              (existing).
Hayden Smelter......................  Converters 1, 3-5......  NOX....................           40  tpy...................  None.
                                                               SO2....................         99.8  Control efficiency....  New double contact acid
                                                                                                                              plant.
                                      Anode Furnaces 1, 2....  SO2....................         None  None..................  Work practice standard.
Miami Smelter.......................  Converters 2-5.........  NOX....................           40  tpy...................  None.
                                                               SO2....................         99.7  Control efficiency....  Improve primary and new
                                                                                                                              secondary capture systems.
                                      Electric Furnace.......  SO2....................         None  None..................  Work practice standard.
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. Proposed RP Determinations
    Point Sources of NOX: EPA conducted an extensive RP analysis of 
NOX point sources that resulted in proposed determinations 
for nine sources and proposed controls on two sources as shown in Table 
2. We are proposing an emissions limit of 2.12 lb/ton on Kiln 4 of the 
Phoenix Cement Clarkdale Plant based on a 30-day rolling average, which 
is consistent with SNCR as a control technology. We are proposing an 
emissions limit of 2.67 lb/ton on Kiln 4 of the CalPortland Cement 
Rillito Plant based on a 30-day rolling average, which also is 
consistent with SNCR control technology. We are also taking comment on 
the possibility of requiring a rolling 12-month cap on NOX 
emissions in lieu of a lb/ton emission limit. For Phoenix Cement, this 
cap would be 947 tpy and apply to Kiln 4. For CalPortland, this cap 
would be 2,082 tpy and apply to Kilns 1-4.

                                                     Table 2--Proposed Emission Limits on RP Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
             Source                     Units            Pollutants         Limit           Measure              Corresponding control technology
--------------------------------------------------------------------------------------------------------------------------------------------------------
Phoenix Cement.................  Kiln 4............  NOX...............         2.12  lb/ton............  Selective Non-Catalytic Reduction.
CalPortland Cement.............  Kiln 4............  NOX...............         2.67  lb/ton............  Selective Non-Catalytic Reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Area Sources of NOX and SO2: We propose to find that it is 
reasonable not to require additional controls on these sources at this 
time. Primarily, these area source categories are distillate fuel oil 
combustion in industrial and commercial boilers and in internal 
combustion engines, and residential natural gas combustion. The State's 
area sources, which currently contribute a relatively small percentage 
of the visibility impairment at impacted Class I areas, would benefit 
from better emission inventories and an improved RP analysis in the 
next planning period.
    Reasonable Progress Goals: EPA is proposing RPGs consistent with a 
combination of control measures that include those in the approved 
Arizona RH SIP as well as the approved and proposed Arizona RH FIP. 
While not quantifying a new set of RPGs based on these control 
measures, we propose that it is reasonable to assume improved levels of 
visibility at Arizona's 12 Class I areas by 2018 since the measures in 
the FIP are significantly beyond what was in the State's plan.
    Demonstration of Reasonable Progress: EPA proposes to find that it 
is not reasonable to provide for rates of progress at the 12 Class I 
areas consistent with the uniform rate of progress (URP) in this 
planning period.\3\ Given the variety and location of sources 
contributing to visibility impairment in Arizona, EPA considers

[[Page 9322]]

it unlikely that Arizona's Class I areas will meet the URP in 2018. We 
propose to find that the RP analyses underlying our actions on the 
Arizona SIP \4\ and in this proposal are sufficient to demonstrate that 
it is not reasonable to provide for rates of progress in this planning 
period that would attain natural conditions by 2064.\5\ This is 
consistent with our proposed and final rules on the Arizona RH SIP in 
which we approved Arizona's determinations that it is not reasonable to 
require additional controls to address organic carbon, elemental 
carbon, coarse mass and fine soil during this planning period.\6\ We 
also approved the State's decision not to require additional controls 
(i.e., controls beyond what the State or we determine to be BART) on 
point sources of SO2.\7\
---------------------------------------------------------------------------

    \3\ 40 CFR 51.308(d)(1)(ii).
    \4\ See proposed actions at 77 FR 75727-75730, 78 FR 29297-
292300 and final action at 78 FR 46172.
    \5\ 40 CFR 51.308(d)(1)(ii).
    \6\ See 77 FR 75728 for a discussion on sources of organic 
carbon and elemental carbon (fires), and 78 FR 29297-29299 for a 
discussion of coarse mass and fine soil.
    \7\ 78 FR 46172.
---------------------------------------------------------------------------

 3. Long-Term Strategy Proposal
    EPA proposes to find that provisions in today's proposal in 
combination with provisions in the approved Arizona SIP and FIP \8\ 
fulfill the requirements of 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F). 
These requirements are to include in the LTS measures needed to achieve 
emission reductions for out-of-state Class I areas, emissions 
limitations and schedules for compliance to achieve the reasonable 
progress goals, and enforceability of emissions limitations and control 
measures.\9\ In today's notice we propose to promulgate emission 
limits, compliance schedules and other requirements for four BART 
sources and two RP sources to complete the actions taken in our 
previous final rule to address these requirements.
---------------------------------------------------------------------------

    \8\ 77 FR 75512-72580, December 5, 2012.
    \9\ See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)).
---------------------------------------------------------------------------

C. Interstate Transport of Pollutants That Affect Visibility

    We propose that a combination of SIP and FIP measures will satisfy 
the FIP obligation for the visibility requirement of CAA section 
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, 
and 2006 PM2.5 NAAQS. CAA section 110(a)(2)(D)(i)(II) 
requires that all SIPs contain adequate provisions to prohibit 
emissions that will interfere with other states' required measures to 
protect visibility. We refer to this requirement herein as the 
interstate transport visibility requirement. ADEQ submitted SIP 
revisions to address this requirement in 2007 for the 1997 8-hour ozone 
NAAQS \10\ and 1997 PM2.5 NAAQS \11\ (2007 Transport SIP) 
\12\ and in 2009 for the 2006 PM2.5 NAAQS \13\ (2009 
Transport SIP).\14\ Each of these SIP revisions indicated that it is 
appropriate to assess Arizona's interference with other states' 
measures to protect visibility in conjunction with the State's RH 
SIP.\15\ In our final rule published on July 30, 2013, EPA disapproved 
these SIP submittals with respect to the interstate transport 
visibility requirement, triggering the obligation for EPA to promulgate 
a FIP to address this requirement.\16\ Accordingly, today's notice 
describes our proposed FIP for the interstate transport visibility 
requirement for the 1997 8-hour ozone, 1997 PM2.5, and 2006 
PM2.5 NAAQS.
---------------------------------------------------------------------------

    \10\ 62 FR 38856, July 18, 1997.
    \11\ 62 FR 38652, July 18, 1997.
    \12\ ``Revision to the Arizona State Implementation Plan Under 
Clean Air Act Section 110(a)(2)(D)(i)--Regional Transport,'' 
submitted by ADEQ on May 24, 2007.
    \13\ 71 FR 61144, October 17, 2006.
    \14\ ``Arizona State Implementation Plan Revision under Clean 
Air Act Section 110(a)(1) and (2); 2006 PM2.5 NAAQS, 1997 
PM2.5 NAAQS, and 1997 8-hour Ozone NAAQS,'' submitted by 
ADEQ on October 14, 2009, which addressed the requirements of 
section 110(a)(2)(D)(i) with respect to the 2006 PM2.5 
NAAQS in Section 2.4 and Appendix B of the submittal.
    \15\ This concept is also presented in EPA's 2006 guidance memo 
on interstate transport, which recommended that states make a 
submission indicating that it was premature, at that time, to 
determine whether there would be any interference with other states' 
required measures to protect visibility until the submission and 
approval of regional haze SIPs. See ``Guidance for State 
Implementation Plan (SIP) Submissions to Meet Current Outstanding 
Obligations Under Section 110(a)(2)(D)(i) for the [1997] 8-Hour 
Ozone and PM2.5 National Ambient Air Quality Standards,'' 
August 15, 2006.
    \16\ 78 FR 46142, July 30, 2013.
---------------------------------------------------------------------------

III. Review of State and EPA Actions on Regional Haze

 A. EPA's Schedule To Act on Arizona's RH SIP

    EPA received a notice of intent to sue in January 2011 stating that 
we had not met the statutory deadline for promulgating RH FIPs and/or 
approving RH SIPs for dozens of states, including Arizona. This notice 
was followed by a lawsuit filed by several advocacy groups (Plaintiffs) 
in August 2011.\17\ In order to resolve this lawsuit and avoid 
litigation, EPA entered into a Consent Decree with the Plaintiffs, 
which sets deadlines for action for all of the states covered by the 
lawsuit, including Arizona. This decree was entered and later amended 
by the United States District Court for the District of Columbia over 
the opposition of Arizona.\18\ Under the terms of the Consent Decree, 
as amended, EPA is currently subject to three sets of deadlines for 
taking action on Arizona's RH SIP as listed in Table 3.\19\
---------------------------------------------------------------------------

    \17\ National Parks Conservation Association v. Jackson (D.D.C. 
Case 1:11-cv-01548).
    \18\ National Parks Conservation Association v. Jackson (D.D.C. 
Case 1:11-cv-01548), Memorandum Order and Opinion (May 25, 2012), 
Minute Order (July 2, 2012), Minute Order (November 13, 2012) and 
Minute Order (February 15, 2013).
    \19\ Id.

                      Table 3--Consent Decree Deadlines for EPA To Act on Arizona's RH SIP
----------------------------------------------------------------------------------------------------------------
              EPA actions                          Proposed rule                          Final rule
----------------------------------------------------------------------------------------------------------------
Phase 1--BART determinations for        July 2, 2012 \1\...................  November 15, 2012.\2\
 Apache, Cholla and Coronado.
Phase 2--All remaining elements of the  December 8, 2012 \3\...............  July 15, 2013.\4\
 Arizona RH SIP.
Phase 3--FIP for disapproved elements   January 27, 2014...................  June 27, 2014.
 of the Arizona RH SIP.
----------------------------------------------------------------------------------------------------------------
\1\ Published in the Federal Register on July 20, 2012, 77 FR 42834.
\2\ Published in the Federal Register on December 5, 2012, 77 FR 72512.
\3\ Published in the Federal Register on December 21, 2012, 77 FR 75704.
\4\ Published in the Federal Register on July 30, 2013, 78 FR 46142.

 B. History of State Submittals and EPA Actions

    Because four of Arizona's 12 mandatory Class I Federal areas are on 
the Colorado Plateau, the State had the option of submitting a RH SIP 
under CAA section 309 of the RHR. A SIP that is approved by EPA as 
meeting all of the requirements of section 309 is ``deemed to comply 
with the requirements for reasonable progress with respect to the 16 
Class I areas [on the Colorado

[[Page 9323]]

Plateau] for the period from approval of the plan through 2018.'' \20\ 
When these regulations were first promulgated, 309 SIPs were due no 
later than December 31, 2003. Accordingly, ADEQ submitted to EPA on 
December 23, 2003, a 309 SIP for Arizona's four Class I Areas on the 
Colorado Plateau. ADEQ submitted a revision to its 309 SIP, consisting 
of rules on emissions trading and smoke management, and a correction to 
the State's regional haze statutes, on December 31, 2004. EPA approved 
the smoke management rules submitted as part of the revisions in 
2004,\21\ but did not propose or take final action on any other portion 
of the 309 SIP.
---------------------------------------------------------------------------

    \20\ 40 CFR 51.309(a).
    \21\ 71 FR 28270 and 72 FR 25973.
---------------------------------------------------------------------------

    In response to a court decision,\22\ EPA revised 40 CFR 51.309 on 
October 13, 2006, making a number of substantive changes and requiring 
states to submit revised 309 SIPs by December 17, 2007.\23\ 
Subsequently, ADEQ sent a letter to EPA dated December 24, 2008, 
acknowledging that it had not submitted a SIP revision to address the 
requirements of 40 CFR 51.309(d)(4) related to stationary sources and 
40 CFR 51.309(g), which governs reasonable progress requirements for 
Arizona's eight mandatory Class I areas outside of the Colorado 
Plateau.\24\
---------------------------------------------------------------------------

    \22\ Center for Energy and Economic Development v. EPA, 398 F.3d 
653 (D.C. Circuit 2005).
    \23\ 71 FR 60612.
    \24\ Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA, 
dated December 24, 2008.
---------------------------------------------------------------------------

    EPA made a finding on January 15, 2009, that 37 states, including 
Arizona, had failed to make all or part of the required SIP submissions 
to address regional haze.\25\ Specifically, EPA found that Arizona 
failed to submit the plan elements required by 40 CFR 51.309(d)(4) and 
(g). EPA sent a letter to ADEQ on January 14, 2009, notifying the State 
of this failure to submit a complete SIP. ADEQ decided to submit a SIP 
under CAA section 308, instead of under section 309. EPA proposed on 
February 5, 2013,\26\ to disapprove Arizona's 309 SIP except for the 
smoke management rules that we had previously approved. Our final rule 
partially disapproving Arizona's 309 SIP was published on August 8, 
2013.\27\
---------------------------------------------------------------------------

    \25\ 74 FR 2392.
    \26\ 78 FR 8083.
    \27\ 78 FR 48326.
---------------------------------------------------------------------------

    ADEQ adopted and transmitted its 2011 RH SIP under section 308 of 
the RHR to EPA Region 9 in a letter dated February 28, 2011. The SIP 
was determined complete by operation of law on August 28, 2011.\28\ The 
SIP was properly noticed by the State and available for public comment 
for 30 days prior to one public hearing held in Phoenix, Arizona, on 
December 2, 2010. Arizona included in its SIP responses to written 
comments from EPA Region 9, the National Park Service, the U.S. Forest 
Service, and other stakeholders including regulated industries and 
environmental organizations. The 2011 RH SIP is available to review in 
the docket for this proposed rule.\29\
---------------------------------------------------------------------------

    \28\ CAA section 110(k)(1)(B).
    \29\ ``Arizona State Implementation Plan, Regional Haze under 
Section 308 of the Federal Regional Haze Rule,'' February 28, 2011.
---------------------------------------------------------------------------

    As shown in Table 3, the first phase of EPA's action on the 2011 RH 
SIP addressed three BART sources. The final rule for the first phase (a 
partial approval and partial disapproval of the State's plan and a 
partial FIP) was signed by the Administrator on November 15, 2012, and 
published in the Federal Register on December 5, 2012. The emission 
limits on the three sources will improve visibility by reducing 
NOX emissions by about 22,700 tons per year. In the second 
phase of our action, we proposed on December 21, 2012, to approve in 
part and disapprove in part the remainder of the 2011 RH SIP. ADEQ 
submitted an Arizona RH SIP Supplement on May 3, 2013, to correct 
certain deficiencies identified in that proposal. We then proposed on 
May 20, 2013, to approve in part and disapprove in part the Supplement. 
Our final rule approving in part and disapproving in part Arizona's RH 
SIP was published on July 30, 2013.

C. EPA's Authority To Promulgate a FIP

    Under CAA section 110(c), EPA is required to promulgate a FIP 
within 2 years of the effective date of a finding that a state has 
failed to make a required SIP submission. The FIP requirement is 
terminated if a state submits a regional haze SIP, and EPA approves 
that SIP before promulgating a FIP. See 74 FR 2392. Specifically, CAA 
section 110(c) provides:

    (1) The Administrator shall promulgate a Federal implementation 
plan at any time within 2 years after the Administrator--
    (A) finds that a State has failed to make a required submission 
or finds that the plan or plan revision submitted by the State does 
not satisfy the minimum criteria established under [CAA section 
110(k)(1)(A)], or
    (B) disapproves a State implementation plan submission in whole 
or in part, unless the State corrects the deficiency, and the 
Administrator approves the plan or plan revision, before the 
Administrator promulgates such Federal implementation plan.

Section 302(y) defines the term ``Federal implementation plan'' in 
pertinent part, as:

    [A] plan (or portion thereof) promulgated by the Administrator 
to fill all or a portion of a gap or otherwise correct all or a 
portion of an inadequacy in a State implementation plan, and which 
includes enforceable emission limitations or other control measures, 
means or techniques (including economic incentives, such as 
marketable permits or auctions or emissions allowances) . . .

Thus, because we determined that Arizona failed to timely submit a 
Regional Haze SIP, we are required to promulgate a Regional Haze FIP 
for Arizona, unless we first approve a SIP that corrects the non-
submittal deficiencies identified in our finding of January 15, 2009. 
For the reasons explained below, we approved in part and disapproved in 
part the Arizona Regional Haze SIP on July 30, 2013. Therefore, we are 
proposing a FIP to address those portions of the SIP that we 
disapproved.

IV. EPA's BART Process

 A. BART Factors

    The purpose of the BART analysis is to identify and evaluate the 
best system of continuous emission reduction based on the BART 
Guidelines \30\ as summarized below. Steps 1 through 3 address the 
availability, feasibility and effectiveness of retrofit control 
options. In our analysis of control technology options, we expressly 
include the emission baseline calculation that is a key factor in 
determining control effectiveness. Step 4 is the five-factor BART 
analysis that results in selecting the emission limit that represents 
BART in Step 5. Following the process steps is a short description of 
each BART factor.
---------------------------------------------------------------------------

    \30\ See July 6, 2005 BART Guidelines, 40 CFR 51, Regional Haze 
Regulations and Guidelines for Best Available Retrofit Technology 
Determinations.
---------------------------------------------------------------------------

    Step 1--Identify all available retrofit control technologies.
    Step 2--Eliminate technically infeasible options.
    Step 3--Evaluate control effectiveness of remaining control 
technologies.
    Step 4--Evaluate impacts and document the results.
     Factor 1: Cost of compliance.
     Factor 2: Energy and non-air quality environmental impacts 
of compliance.
     Factor 3: Pollution control equipment in use at the 
source.
     Factor 4: Remaining useful life of the facility.
     Factor 5: Visibility impacts.
    Step 5--Select BART.
    Factor 1: Costs of Compliance: The evaluation of costs is an 
important part of a five-factor analysis because it influences the 
cost-effectiveness that is

[[Page 9324]]

compared to the visibility benefits. Estimating the cost of compliance 
primarily depends on the cost estimates and control effectiveness of 
each technically feasible BART control option. For each of the four 
BART facilities evaluated in this section, we state the source of the 
cost-related information and how it was used in our analysis. While EPA 
relies primarily on the cost methods in our Control Cost Manual, we 
also rely on verified cost estimates from the companies and cost 
methods used for specific industries. In some cases, certain capital 
costs and annual operating costs were developed by our contractor based 
on actual costs associated with specific types of sources. Where 
possible, we have conducted new cost analyses considering more recent 
information from ADEQ or from the four BART facilities. Please refer to 
the TSD for the detailed cost analyses.
    Factor 2: Energy and Non-air Quality Environmental Impacts: In 
assessing the potential energy impacts of BART control options, we 
consider direct and indirect effects on energy availability and costs. 
An example of a direct energy impact is the cost of energy consumption 
from the control equipment. Examples of non-air quality impacts include 
safety issues associated with handling and transportation of anhydrous 
ammonia or the ability to sell fly ash rather than dispose of it.
    Factor 3: Pollution Equipment in Use at the Source: The presence of 
existing pollution control technology at each source is reflected in 
our BART analysis in two ways. First, we always consider simple 
retention of existing equipment as a BART candidate. We also consider 
existing equipment in determining available control technologies that 
can be used with or replace such equipment. Second, where appropriate, 
we consider existing equipment in developing baseline emission rates 
for use in cost calculations and visibility modeling. Pollutant-
specific discussions of these issues are included in the following 
sections.
    Factor 4: Remaining Useful Life of the Source: We consider each 
source's ``remaining useful life'' as one element of the overall cost 
analysis as allowed by the BART Guidelines.\31\ In cases where we are 
not aware of any enforceable shut-down date for a particular source or 
unit, we use a 20-year amortization period as the remaining useful life 
per the EPA Cost Control Manual.
---------------------------------------------------------------------------

    \31\ 40 CFR Part 51, Appendix Y, section IV.D.4.k.
---------------------------------------------------------------------------

    Factor 5: Anticipated Degree of Visibility Improvement: EPA relied 
on the CALPUFF modeling system (version 5.8) for visibility modeling, 
which consists of the CALPUFF dispersion model, the CALMET 
meteorological data processor, and the CALPOST post-processing program. 
The initial modeling was performed by our contractor, the University of 
North Carolina (UNC) at Chapel Hill. In some cases, companies submitted 
BART analyses including visibility modeling that we used to evaluate 
visibility benefits. An explanation of the visibility analysis and 
tables follows this section, a description of the modeling is included 
in the five-factor discussion for each source, and more details are 
available in the TSD.

 B. Visibility Analysis

    EPA estimated the degree of visibility improvement expected to 
result from various BART control options based on the difference 
between baseline visibility impacts prior to controls and visibility 
impacts with controls in operation. Baseline emissions were based on 
the highest 24-hour emissions from monitored emissions data when 
available, otherwise from estimates of production rates and emission 
factors. Control case emissions were derived from the baseline by 
applying the percent reduction in emission factor expected from the 
control. Impacts at all Class I areas within 300 km of each facility 
were assessed. EPA used the CALPUFF model version 5.8 \32\ to determine 
the baseline and post-control visibility impacts, following the 
modeling approach recommended in the BART Guidelines. Our contractor at 
UNC developed a modeling protocol and carried out most of the modeling 
and the post-processing of model output into tables of visibility 
impacts. EPA supplemented this for certain sources with modeling of 
additional control scenarios, corrections to some scenarios and post-
processing work, and some sensitivity simulations. Also, EPA performed 
the modeling for the two smelters. Details of the modeling are in the 
TSD.
---------------------------------------------------------------------------

    \32\ EPA relied on version 5.8 of CALPUFF because it is the EPA-
approved version promulgated in the Guideline on Air Quality Models 
(40 CFR part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 
2003). EPA updated the specific version to be used for regulatory 
purposes on June 29, 2007, including minor revisions as of that 
date; the approved CALPUFF modeling system includes CALPUFF version 
5.8, level 070623, and CALMET version 5.8 level 070623. At this 
time, any other version of the CALPUFF modeling system would be 
considered an ``alternative model'', subject to the provisions of 
Guideline on Air Quality Models section 3.2.2(b), requiring a full 
theoretical and performance evaluation.
---------------------------------------------------------------------------

    EPA modeled all units (stacks) and pollutants simultaneously for 
each source. Modeling of all emissions from all units accounts for the 
chemical interaction between multiple plumes, and between plumes and 
background concentrations. This also accounts for the fact that 
deciview benefits from controls on individual units are not strictly 
additive. As recommended in the BART Guidelines, the 98th percentile 
daily impact in deciviews is used as the basic metric of visibility 
impact. EPA relied on the 98th percentile over the merged 2001-2003 
period. The alternative of using the average of the three 98th 
percentiles from 2001, 2002 and 2003 was also calculated, and the 
results of using it are provided in the TSD, although they differ 
little from the merged approach. Both are valid indicators of the 98th 
percentile.\33\ EPA also mainly relied on the revised IMPROVE equation 
for translating pollutant concentrations into deciviews (CALPOST 
visibility method 8), the recommended method for new visibility 
analyses. The old IMPROVE equation (method 6) was used by most states 
in their original SIP submittals and was acceptable at that time. EPA 
used the best 20 percent of natural background days in calculating 
delta deciviews. For the original SIP submittals, states were free to 
use this or the annual average background. Overall, we refer to the 
method we used as method ``8b'' (``b'' for ``best''). Model results 
using visibility method 6 and annual average background conditions 
(``a'' for average) also are provided in the TSD (i.e., methods 6a, 6b, 
and 8a, as well as 8b).
---------------------------------------------------------------------------

    \33\ For each modeled day, the CALPUFF model provides the 
highest impact from among the receptor locations for a given Class I 
area. The baseline impact in the tables is the 98th percentile among 
these daily values. The improvement in the tables is the difference 
between that baseline impact and the 98th percentile impact after 
applying controls. The 98th percentile is represented by the 22nd 
high over the 2001-2003 period modeled. The TSD includes an 
alternative, the average of each of the three years' 8th highs, 
which yields slightly different values.
---------------------------------------------------------------------------

 C. Explanation of Visibility Tables

    For each facility, this notice provides one or more tables of 
visibility impacts and visibility improvement from controls in 
deciviews. Each table has the same format: columns list the Class I 
areas within 300 km of the facility, the distance,\34\ baseline modeled 
visibility impact from the facility for each area, and one or more 
columns with the

[[Page 9325]]

modeled visibility improvement from a candidate control option. A 
modeling run abbreviation, such as ``base'' or ``ctrl2'', is included 
along with a short description of the option. For several facilities, 
there are two different baselines incorporating different emission 
assumptions. For these, there are baseline and control columns for each 
of the two baselines. For Sundt Unit 4, there are separate tables for 
SO2 and NOX controls, and an additional table 
showing the effect of reductions for both SO2 and 
NOX for the proposed BART controls and for a better-than-
BART alternative. At the bottom of each table are five rows showing 
impacts and improvements from the facility for all the Class I areas 
considered together, and also two measures of visibility cost-
effectiveness. The cost-effectiveness here is ``dollars per deciview,'' 
where dollars is the annualized total cost of the control in millions 
of dollars per year, divided by either the sum of deciview improvements 
over all impacted Class I areas, or the largest single area deciview 
improvement. Cost-effectiveness in terms of dollars per ton is 
presented in other tables and has been considered for each source and 
BART option. The headings for these table rows are:
---------------------------------------------------------------------------

    \34\ The distances given are from the facility to the nearest 
model receptor location; distances to the actual Class I area 
boundary may be slightly less. Receptor locations are defined for 
all Class I areas by the National Park Service. See ``Class I 
Receptors'' Web site, http://www2.nature.nps.gov/air/maps/Receptors/
.
---------------------------------------------------------------------------

    (1) ``Cumulative (sum),'' the cumulative impact or improvement that 
is computed as the sum of impact or improvement over all the areas;
    (2) ``Maximum,'' single largest impact or improvement that is the 
maximum over all the areas;
    (3) `` CIAs >= 0.5 dv,'' the number of Class I areas 
having a baseline impact from the source of at least 0.5 dv (or, for 
the control columns, the number of areas showing improvement of at 
least 0.5 dv due to the control);
    (4) ``Million $/dv (cumul. dv),'' annual control cost in millions 
of dollars per deciview considering the improvement at all the Class I 
areas together; and
    (5) ``Million $/dv (max. dv),'' annualized cost per deciview 
considering the largest single area improvement.
    The Federal Land Managers have sometimes used $10 million/dv as a 
comparison benchmark for the $/dv computed from the maximum, and $20 
million/dv as a benchmark for $/dv computed from cumulative deciviews. 
We have not endorsed the use of these or any other $/dv benchmarks as 
criteria for making BART determinations.
    The TSD for this notice provides bar charts and additional 
visibility tables, including results for individual modeled years and 
their average, the old IMPROVE equation, and annual average background 
conditions instead of best 20 percent. There also are model results for 
various sensitivity analyses.

V. EPA's Proposed BART FIP

A. Sundt Generating Station Unit 4

    Summary: EPA is proposing to find that Sundt Unit 4 is eligible for 
and subject to BART. EPA is proposing BART emissions limits on Sundt 
Generating Station Unit 4 for NOX, SO2 and 
PM10 based on the corresponding control technologies listed 
in Table 4 and described in the following BART analyses. For 
NOX, we propose an emission limit of 0.36 lb/MMBtu 
consistent with the use of SNCR. For SO2, we propose an 
emission limit of 0.23 lb/MMBtu consistent with the use of DSI. For 
PM10, we propose a filterable PM10 emission limit 
of 0.03 lb/MMBtu based on the use of the existing fabric filter 
baghouse. Finally, we are also proposing a switch to natural gas as a 
better-than-BART alternative.

                            Table 4--Sundt 4: Summary of Proposed BART Determinations
----------------------------------------------------------------------------------------------------------------
                                   Emission limit (lb/
            Pollutant                    MMBtu)                            Control technology
----------------------------------------------------------------------------------------------------------------
NOX..............................               0.36   Selective Non-Catalytic Reduction.
SO2..............................               0.23   Dry Sorbent Injection.
PM10.............................               0.030  Fabric filter baghouse (existing).
----------------------------------------------------------------------------------------------------------------

    Affected Class I Areas: Ten Class I areas are within 300 km of 
Sundt. Their nearest borders range from 17 km to 247 km away, with 
Saguaro NP the closest, and Galiuro WA the second closest. The highest 
baseline visibility impact of Sundt Unit 4 is 3.4 dv at Saguaro. The 
second highest baseline impact is 1.1 dv at Galiuro. Other areas have 
visibility impacts of 0.5 dv or less. The cumulative sum of visibility 
impacts over all the Class I areas is 6.6 dv.
    Facility Overview: The Sundt Generating Station is an electric 
utility power plant located in Tucson, Arizona, operated by Tucson 
Electric Power. The plant consists of four steam electric boilers and 
three stationary combustion turbines for a total net generating 
capacity of approximately 500 megawatts (MW).\35\ Sundt Unit 4 is a 
steam electric boiler that was manufactured in 1964 and placed into 
operation in about 1967. Unit 4 is a dry bottom wall-fired boiler with 
a maximum gross capacity of 130 MW when firing coal. Originally 
designed to fire natural gas and fuel oil, Sundt Unit 4 was converted 
to also be able to fire coal in the early 1980s as a result of an order 
issued by the Department of Energy. The unit now fires both coal and 
natural gas, as explained in more detail below. As part of the coal 
conversion, the unit was equipped with a fabric filter for particulate 
matter control. Unit 4 was upgraded in 1999 with LNB and overfire air 
(OFA) designed to meet Phase II Acid Rain Program requirements. At 
present, Unit 4 operates with the pollution control equipment and is 
subject to the emission limits listed in Table 5 that reflects a coal-
operating scenario.
---------------------------------------------------------------------------

    \35\ As described in Pima DEQ Permit No. 1052, in the TSD.

[[Page 9326]]



                        Table 5--Sundt 4: Current Emission Limits and Control Technology
----------------------------------------------------------------------------------------------------------------
            Pollutant                Emission limit                          Control device
----------------------------------------------------------------------------------------------------------------
NOX.............................  0.46 lb/MMBtu \36\.  LNB with OFA.
SO2.............................  1 lb/MMBtu \37\....  None.
PM10............................  233 lb/hr \38\.....  Fabric filter/baghouse.
----------------------------------------------------------------------------------------------------------------

    TEP has indicated that the generating capacity of Sundt Unit 4 
while firing coal is reduced compared to its capacity using natural 
gas. As reported to the Energy Information Agency (EIA), Unit 4 has a 
173 MW nameplate capacity while firing natural gas. However, the 
maximum gross capacity at which the unit could operate for a sustained 
period of time while burning coal is about 130 MW. This is due 
primarily to the fact that the amount of coal that can be introduced to 
the boiler is limited by the size of the boiler. Excess coal injection 
causes the flame to impinge on the back wall of the boiler which 
damages the boiler tubes.\39\ A summary of historical emissions data 
for a recent period of time is in Table 6.
---------------------------------------------------------------------------

    \36\ Pima DEQ Permit No. 1052, Attachment F: Phase II Acid Rain 
Permit.
    \37\ Pima DEQ Permit No. 1052, Specific Condition II.A.2.b.
    \38\ As determined by Pima DEQ Permit No. 1052, Specific 
Condition II.A.1.
    \39\ TEP's letter dated May 10, 2013, page 2.

                                                   Table 6--Sundt 4: Historical Emissions (2008-2012)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       NOX                       SO2
                             Year                               Heat duty  ---------------------------------------------------- Coal (tons)  Natural gas
                                                                (MMBtu/yr)     (tpy)      (lb/MMBtu)     (tpy)      (lb/MMBtu)                  (MCF)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012.........................................................    6,313,719          945        0.297          371        0.118       44,049    4,660,701
2011.........................................................    5,993,769        1,366        0.445        2,185        0.729      265,111      157,919
2010.........................................................    6,869,999        1,303        0.368        1,733        0.505      162,212    1,904,433
2009.........................................................    4,801,971          709        0.285          636        0.265       73,464    2,642,992
2008.........................................................    8,709,923        1,880        0.429        2,882        0.661      378,956       18,422
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Baseline Emissions Calculations: The baseline period, baseline 
emissions, and capacity factor are three key variables in determining 
BART that are linked to fuel usage. TEP has indicated that while Sundt 
Unit 4 predominantly has operated as a coal-fired unit, it has recently 
expanded its use of natural gas as a result of historically low natural 
gas prices.\40\ As shown in the last column of Table 6, Unit 4 has used 
much higher amounts of natural gas during 2009-2010 and again in 2012 
that are not representative of anticipatable operations based on coal. 
Accordingly, we use calendar year 2011 emissions when Unit 4 
predominately used coal as the baseline period for annual average 
emission estimates. Although this represents only a single year of 
emissions data, we consider this period of coal usage, rather than a 
period of primarily natural gas usage, to represent a realistic 
depiction of anticipated annual emissions when burning coal.\41\ In 
addition, we rely on an annual capacity factor of 0.49 based on a coal-
fired capacity of 130 MW and actual generation from the baseline period 
of 2011. For visibility modeling, we used baseline emissions for 
NOX and SO2 based on maximum daily emission 
rates, as reported to EPA's CAMD Acid Rain Program database, for the 
period from 2008 to 2010. While this time period is prior to the 2011 
baseline period used for the annual emission estimates, the highest 
daily emission rates from 2008 to 2010 correspond to coal usage. Since 
these maximum daily emission rates still correspond to coal usage, we 
consider them reasonable estimates of baseline emissions despite the 
fact that they are drawn from a baseline period different from the one 
used to estimate annual emission rates. For PM10, the 
baseline emission rate used in visibility modeling is based on the 
value in the original Western Regional Air Partnership (WRAP) 
visibility modeling that reflects the use of coal and the existing 
fabric filter. For a more detailed analysis of how we determined the 
baseline period, baseline emissions and capacity factor, please refer 
to the TSD.
---------------------------------------------------------------------------

    \40\ TEP's letter dated May 10, 2013, page 2.
    \41\ As discussed in the BART Guidelines, 40 CFR Part 51, 
Appendix Y, section IV.D.4.d.
---------------------------------------------------------------------------

    Modeling Overview: EPA's contactor UNC performed the initial 
modeling of Sundt's visibility impacts. EPA performed supplemental 
modeling to correct some minor errors in the initial work and to 
estimate impacts from additional control scenarios, such as switching 
entirely to natural gas fuel. EPA also modeled the impacts for the 
western unit of Saguaro NP, whereas originally only the eastern unit 
was included. Although only Unit 4 is BART-eligible, all four Sundt 
units were included in the CALPUFF modeling to more accurately 
represent the chemistry of the facility's pollutant plume. Baseline 
emissions for modeling were based on daily CAMD emissions monitoring 
data for 2008-2010, a period with no changes in pollution controls at 
the facility. Control case emissions were derived from the baseline by 
applying the percent reduction expected from the control.
    Saguaro NP has an eastern unit, the Rincon Mountain District, and a 
western unit, the Tucson Mountain District. In the original set of 
modeling receptor locations developed by the National Park Service, 
only the eastern unit was included. CALPUFF modeling typically covered 
only the eastern unit. This is true of modeling by the WRAP, and also 
of modeling by EPA's contractor UNC, which used the WRAP work as a 
starting point. A more recent set of NPS modeling receptors from 2008 
is available that covers both eastern and western units of Saguaro. For 
this FIP, EPA remodeled for both Saguaro units where needed for a given 
facility. The only facilities for which it makes a significant 
difference are TEP Sundt and CalPortland Cement due to their close 
proximity to Saguaro.

[[Page 9327]]

 1. Proposed Eligible and Subject to BART
    EPA is proposing to find that Sundt Unit 4 is eligible for and 
subject to BART. In our final rulemaking on the Arizona RH SIP dated 
July 30, 2013, we disapproved ADEQ's finding that Sundt Unit 4 was not 
eligible for BART.\42\ In particular, we found that, although this unit 
was ``reconstructed'' in 1987, it remains BART-eligible because it did 
not undergo prevention of significant deterioration (PSD) review at the 
time of reconstruction.\43\ For this reason, we propose to find Sundt 
Unit 4 is eligible for a BART analysis of the three haze-causing 
pollutants: NOX, SO2 and PM10.
---------------------------------------------------------------------------

    \42\ 78 FR 46175 (codified at 40 CFR 52.145(e)(2)(i)).
    \43\ See 78 FR 75722, 78 FR 46151, and ``TEP Sundt Unit I4 BART 
Eligibility Memo'' (November 21, 2012).
---------------------------------------------------------------------------

    Under the RHR and the BART Guidelines, any BART-eligible source 
that either ``causes'' or ``contributes'' to visibility impairment at 
any Class I area is subject to BART.\44\ EPA previously approved ADEQ's 
decision to set 0.5 dv as the threshold for determining whether a 
source contributes to visibility impairment at a given Class I 
area.\45\ In order to determine whether Sundt Unit 4 is subject to 
BART, EPA's contractor UNC evaluated whether Unit 4 has an impact of 
0.5 dv or more at any Class I area. UNC's visibility modeling showed 
that two Class I areas experienced a 98th percentile impact greater 
than 0.5 dv due to emissions from Sundt Unit 4.\46\ In particular, the 
98th percentile impact across the three years modeled was 2.798 dv at 
Saguaro and 0.839 dv at Galiuro.\47\ These results indicate that Sundt 
Unit 4 causes visibility impairment at Saguaro and contributes to 
impairment at Galiuro. Therefore, EPA proposes to find that Sundt Unit 
4 is subject to BART.
---------------------------------------------------------------------------

    \44\ 40 CFR part 51, appendix Y, section III.A.
    \45\ 77 FR 46152-53.
    \46\ Technical Analysis for Arizona and Hawaii Regional Haze 
FIPs: Report on Identification of Sources Subject to BART, UNC, July 
20, 2012, Table 4.
    \47\ For an expanded discussion of our approach to visibility 
modeling, please refer to Section III (General Approach to the Five-
Factor BART analysis) of the Sundt4 TSD. This approach was used in 
both determining whether Sundt 4 was subject to BART, as well as in 
evaluating the visibility factor in the BART analysis.
---------------------------------------------------------------------------

 2. Proposed BART Analysis and Determination for NOX
    For our NOX BART analysis, we identify all available 
control technologies, eliminate options that are not technically 
feasible, and evaluate the control effectiveness of the remaining 
control options. We then evaluate each technically feasible control in 
terms of a five-factor BART analysis and propose a determination for 
BART.
a. Control Technology Availability, Technical Feasibility, and 
Effectiveness
    EPA proposes to find that SNCR and selective catalytic reduction 
(SCR) are available and technically feasible options to control 
NOX emissions with a control efficiency of approximately 50 
percent for SNCR and approximately 89 percent for SCR.
    SNCR involves the non-catalytic decomposition of NOX to 
molecular nitrogen and water. Typical NOX control 
efficiencies for SNCR range from 40 to 60 percent, depending on inlet 
NOX concentrations, fluctuating flue gas temperatures, 
residence time, amount and type of nitrogenous reducing agent, mixing 
effectiveness, acceptable levels of ammonia slip, and presence of 
interfering chemical substances in the gas stream. Because Sundt Unit 4 
already operates with NOX combustion controls, we have used 
an SNCR control efficiency of 30 percent from a baseline that includes 
LNB with OFA. Considering typical combustion control technologies such 
as LNB and OFA can achieve control efficiencies of about 25 to 30 
percent, the result is total control efficiency from an uncontrolled 
baseline of about 50 percent, which is in the mid-range of SNCR control 
efficiencies.
    SCR is a post-combustion gas treatment technique that uses either 
ammonia or urea in the presence of a metal-based catalyst to 
selectively reduce NOX to molecular nitrogen, water, and 
oxygen. The catalyst lowers the temperature required for the chemical 
reaction between NOX and the reducing agent. Technical 
factors that impact the effectiveness of this technology include the 
catalyst reactor design, operating temperature, type of fuel fired, 
sulfur content of the fuel, design of the ammonia injection system, and 
the potential for catalyst poisoning. SCR has been installed on 
numerous coal-fired boilers of varying sizes, and is considered 
technically feasible. We note that SCRs are classified as a low dust 
SCR (LDSCR) or high dust SCR (HDSCR). As explained in the TSD, the SCR 
system considered in this analysis is the HDSCR.
    Existing vendor literature and technical studies indicate that SCR 
systems are capable of achieving approximately 80 to 90 percent control 
efficiency, and that this emission rate can be achieved on a retrofit 
basis, particularly when combined with combustion control technology 
such as LNB.\48\ Our contractor used a design emission rate of 0.050 
lb/MMBtu (annual average), which in the case of Sundt Unit 4 
corresponds to a control efficiency of 89 percent. While this is a 
value close to the upper range of SCR control efficiency, we consider 
the use of 0.050 lb/MMBtu appropriate for Sundt Unit 4. A review of 
Acid Rain Program data indicates that there are up to seven dry-bottom, 
wall-fired boilers operating with SCR on a retrofit basis that have 
achieved an annual average emission rate of 0.050 lb/MMBtu or lower in 
practice.\49\ However, there are design differences between Sundt Unit 
4 and these other units (i.e., boiler size, coal type and 
characteristics, and loading profile) that have the potential to affect 
this comparison. If we receive additional comments that sufficiently 
document source-specific considerations justifying the use of an 
emission rate higher than 0.050 lb/MMBtu, we may incorporate such 
considerations in our selection of BART.
---------------------------------------------------------------------------

    \48\ See ``Emissions Control: Cost-Effective Layered Technology 
for Ultra-Low NOx Control'' (2007), ``What's New in SCRs'' (2006), 
and ``Nitrogen Oxides Emission Control Options for Coal-Fired 
Electric Utility Boilers'' (2005).
    \49\ See spreadsheet ``CAMD Wall-fired Coal EGUs.xlsx'' in the 
docket.
---------------------------------------------------------------------------

b. BART Analysis for NOX
    Costs of Compliance: In evaluating the costs of compliance for SNCR 
and SCR, we calculated the control costs ($) and emission reductions 
(tons/year of pollutant) for each control technology, and developed 
average cost-effectiveness ($/ton) values. Estimated NOX 
emission reductions are summarized in Table 7 and cost-effectiveness 
numbers are summarized in Table 8 for each option. A more detailed 
version of emission calculations are in our docket \50\ and in our 
contractor's report. The heat duty and capacity factor used in the 
emission calculations below differ from the values used in the 
calculations originally prepared by our contractor, due to the unit's 
lower capacity when burning coal (130 MW) rather than natural gas (173 
MW). The heat duty (MMBtu/hr) and capacity factor (0.49) reflect the 
coal-burning heat duty, rather than the natural gas-burning heat 
duty.\51\
---------------------------------------------------------------------------

    \50\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
    \51\ As noted by TEP in its May 10, 2013 letter, although the 
calculated capacity factor is different, the annual emissions in 
tons per year removed do not change significantly, as the change in 
capacity factor is largely offset by the change in maximum unit 
gross rating.

[[Page 9328]]



                                                 Table 7--Sundt 4: NOX Control Option Emission Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Control      Emission    Heat duty     Capacity       NOX emission rate         NOX
                                                                efficiency     factor   -------------    factor   --------------------------   emission
                        Control option                        --------------------------             -------------                            reduction
                                                                                           MMBtu/hr                   lb/hr         tpy     ------------
                                                                    %         lb/MMBtu                     %                                     tpy
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline (LNB+OFA)...........................................  ...........        0.445        1,371         0.49          610        1,310
SNCR+LNB+OFA.................................................           30        0.312        1,371         0.49          427          917          393
SCR+LNB+OFA..................................................           89        0.050        1,371         0.49           69          147        1,162
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Our consideration of the cost of compliance focuses primarily on 
the cost-effectiveness of each control option as measured in average 
cost per ton and incremental cost per ton of each control option as 
shown in Table 8. SCR is the most stringent option with the highest 
average cost-effectiveness of $5,176/ton, and incremental cost-
effectiveness over SNCR of $6,174/ton. Detailed cost calculations can 
be found in our docket.\52\ While we have relied primarily upon the 
cost calculations prepared by our contractor, we have incorporated 
certain elements of TEP's analysis \53\ into our cost calculations. The 
most significant revisions to cost estimates include the following:
---------------------------------------------------------------------------

    \52\ See spreadsheet ``Sundt4 Control Costs 2014-01-26.xlsx'' in 
the docket.
    \53\ Letter dated May 10, 2013.
---------------------------------------------------------------------------

     We have changed the unit size from 173 MW to 130 MW to 
reflect the gross capacity of using coal. Although this has the net 
effect of decreasing certain costs, particularly several operation and 
maintenance (O&M) costs, the revised capital cost estimates increased 
for SCR (from $38 million to $45 million) and SNCR (from $2.8 million 
to $3.1 million).
     We have used a retrofit difficulty value of 1.5 (increased 
from 1.0) in cost estimates due to certain difficulties associated with 
retrofit installation of SCR. These difficulties are the result of site 
congestion and the configuration of the existing boiler structure and 
coal handling system as noted by TEP.
     We have included the cost of air preheater modifications 
that TEP stated are necessary in order to accommodate SCR due to site 
congestion and coal handling configuration.

                                                 Table 8--Sundt 4: NOX Control Option Cost-Effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Capital     Annualized     Annual       Total       Emission    Cost-effectiveness  ($/
                                                                   cost       capital     operating   annual cost   reduction             ton)
                        Control option                        -------------     cost         cost    ---------------------------------------------------
                                                                           --------------------------
                                                                   ($)          ($)          ($)         ($/yr)       (tpy)         Ave      Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR.........................................................   $3,079,089     $290,644     $975,124   $1,265,768          393       $3,222
SCR..........................................................   45,167,561    4,263,498    1,753,975    6,017,474        1,162        5,176       $6,174
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Pollution Control Equipment in Use at the Source: The presence of 
existing pollution control technology at Sundt Unit 4 is reflected in 
the consideration of available control technologies and in the 
development of baseline emission rates for use in cost calculations and 
visibility modeling. In the case of NOX, current pollution 
controls are reflected in our selection of 2011 as the baseline period, 
which includes the use of LNB and OFA.
    Energy and Non-Air Quality Environmental Impacts: Regarding 
potential energy impacts of the BART control options, we note that SCR 
incurs a draft loss that will result in certain load loss, and that 
other emissions controls may also have modest energy impacts. The costs 
for direct energy impacts, i.e., power consumption from the control 
equipment and additional draft system fans from each control 
technology, are included in the cost analyses. Indirect energy impacts, 
such as the energy to produce raw materials, are not considered, which 
is consistent with the BART Guidelines. Ammonia adsorption (resulting 
from ammonia injection from SCR or SNCR) to fly ash is generally not 
desirable due to odor but does not impact the integrity of the use of 
fly ash in concrete. The ability to sell fly ash is unlikely to be 
affected by the installation of SNCR or SCR technologies. Finally, SNCR 
and SCR may involve potential safety hazards associated with the 
transportation and handling of anhydrous ammonia. However, since the 
handling of anhydrous ammonia will involve the development of a risk 
management plan (RMP), we consider the associated safety issues to be 
manageable as long as established safety procedures are followed. As a 
result, we do not consider these impacts sufficient to warrant the 
elimination of either of the available control technologies.
    Remaining Useful Life of the Source: We are considering the 
``remaining useful life'' of Sundt Unit 4 as one element of the overall 
cost analysis as allowed by the BART Guidelines.\54\ Since there is not 
state- or federally-enforceable shut-down date for this unit, we have 
used a 20-year amortization period per the EPA Cost Control Manual as 
the remaining useful life for the facility.\55\
---------------------------------------------------------------------------

    \54\ 40 CFR Part 51, Appendix Y, section IV.D.4.k.
    \55\ We note that the 20 year amortization period is primarily 
used in NOX control cost calculations, such as for SCR. 
In order to promote consistency in the analysis, we have used the 20 
year period in the cost calculations for other control options, such 
as for SO2 control, for which the Control Cost Manual 
includes examples that use an amortization period of 15 years.
---------------------------------------------------------------------------

    Degree of Visibility Improvement: The visibility improvement due to 
NOX controls is modest. SNCR was modeled at a 30 percent 
NOX emission reduction. As shown in Table 9, this yields a 
maximum visibility improvement of just over 0.2 dv at Saguaro. Galiuro 
improves about half as much, and other areas much less. The cumulative 
improvement across all impacted Class I areas is 0.5 dv. SCR was 
modeled at 89 percent NOX reduction to achieve 0.05 lb/
MMBtu. SCR provides a maximum improvement of 0.8 dv, which occurs at 
Saguaro. Galiuro again improves about half as much, and the cumulative 
improvement across all Class I areas is 1.6 dv. This visibility 
improvement is substantially greater for SCR than for SNCR.

[[Page 9329]]



                      Table 9--Sundt 4: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                         Visibility     Visibility  improvement
                                                             Distance      impact    ---------------------------
                       Class I area                            (km)    --------------     SNCR
                                                                          Base case     (ctrl04)    SCR (ctrl08)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM............................................          144          0.43          0.03          0.12
Chiricahua WA............................................          141          0.51          0.05          0.15
Galiuro WA...............................................           64          1.10          0.12          0.34
Gila WA..................................................          232          0.17          0.02          0.04
Mazatzal WA..............................................          203          0.19          0.02          0.04
Mount Baldy WA...........................................          232          0.15          0.01          0.03
Pine Mountain WA.........................................          247          0.15          0.02          0.03
Saguaro NP...............................................           17          3.40          0.23          0.78
Sierra Ancha WA..........................................          178          0.19          0.01          0.04
Superstition WA..........................................          137          0.32          0.01          0.05
Cumulative (sum).........................................  ...........          6.6           0.5           1.6
Maximum..................................................  ...........          3.40          0.23          0.78
 CIAs >= 0.5 dv.................................  ...........          3             0             1
Million $/dv (cumul. dv).................................  ...........  ............         $2.4          $3.7
Million $/dv (max. dv)...................................  ...........  ............         $5.5          $7.7
----------------------------------------------------------------------------------------------------------------

c. Proposed BART Determination for NOX
    EPA proposes to find that BART for NOX is an emission 
limit of 0.36 lb/MMBtu on a 30-day BOD rolling basis that is achievable 
by SNCR with LNB and OFA. The primary factors supporting this proposed 
finding are the average cost-effectiveness and anticipated visibility 
benefits of controls. In particular, while SCR is anticipated to 
achieve the greatest degree of visibility improvement, it is also 
significantly more expensive than SNCR, with an average cost-
effectiveness of $5176/ton. We do not consider this average cost to be 
warranted by the projected visibility benefit of SCR for this facility. 
Table 10 provides a summary of our five-factor BART analysis.
    In proposing an emission limit of 0.36 lb/MMBtu, we have considered 
the annual average design value for SNCR of 0.31 lb/MMBtu as well as 
the need to account for emissions associated with startup and shutdown 
events. To account for this variability, we have examined the 
difference between the highest 30-day rolling NOX value and 
the highest annual average NOX value observed over the 
baseline period, which is approximately 17 percent.\56\ We have applied 
this variability to the annual average design value to develop a 30-day 
BOD rolling emission limit, which we consider to provide sufficient 
margin for a limit that will apply at all times.
---------------------------------------------------------------------------

    \56\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
---------------------------------------------------------------------------

    We propose to require compliance with this requirement within three 
years of the effective date of the final rule. A 2006 Institute of 
Clean Air Companies (ICAC) study indicated that the installation time 
for a typical SNCR retrofit, from bid to startup, is 10 to 13 
months.\57\ However, because we are also requiring the installation of 
additional SO2 controls, we consider a three year period for 
compliance with both BART determinations to be appropriate. We are 
seeking comment on whether this compliance date is reasonable and 
consistent with the requirement of the Clean Air Act that BART be 
installed ``as expeditiously as practicable but in no event later than 
five years after [promulgation of the applicable FIP].'' \58\ If we 
receive information during the comment period that establishes that a 
different compliance time frame is appropriate, we may finalize a 
different compliance date. Finally, we are proposing regulatory text 
that includes monitoring, reporting, and recordkeeping requirements to 
ensure that the emission limit and compliance deadline are enforceable. 
As part of the proposed monitoring requirements, we are including a 
requirement to monitor rates of ammonia injection in order to ensure 
proper operation of the SNCR in a manner that minimizes ammonia 
emissions.
---------------------------------------------------------------------------

    \57\ See ``Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources'', Institute of 
Clean Air Companies, December 4, 2006.
    \58\ Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4).

                               Table 10--Sundt 4: Summary of BART Analysis for NOX
----------------------------------------------------------------------------------------------------------------
                                                 LNB+OFA
            Sundt unit 4 (130 MW)               (baseline)           SNCR+LNB                   SCR+LNB
----------------------------------------------------------------------------------------------------------------
                                                    Emissions
----------------------------------------------------------------------------------------------------------------
Emission Factor (lb/MMBtu)...................        0.445  0.312....................  0.050
Emission Rate (tpy)..........................         1310  917......................  147
Emission Reduction (tpy).....................  ...........  393......................  1,162
Control Effectiveness (%)....................  ...........  30%......................  89%
----------------------------------------------------------------------------------------------------------------
                                               Costs of Compliance
----------------------------------------------------------------------------------------------------------------
Capital Cost ($).............................  ...........  $3,079,089...............  $45,167,561
Annualized Capital Cost ($)..................  ...........  $290,644.................  $4,263,498
Annual O&M ($)...............................  ...........  $975,124.................  $1,753,975

[[Page 9330]]

 
Total Annual Cost ($)........................  ...........  $1,265,768...............  $6,017,474
Ave Cost-Effectiveness ($/ton)...............  ...........  $3,222...................  $5,176
Incremental Cost-Effectiveness ($/ton).......  ...........  .........................  $6,174
----------------------------------------------------------------------------------------------------------------
                                       Pollution Control Equipment in Use
----------------------------------------------------------------------------------------------------------------
Low-NOX Burners and Over Fire Air
----------------------------------------------------------------------------------------------------------------
                                Energy and Non-Air Quality Environmental Impacts
----------------------------------------------------------------------------------------------------------------
Energy impacts have been reflected in annual O&M costs in the costs of compliance.
----------------------------------------------------------------------------------------------------------------
SCR and SNCR may create potential safety and environmental hazards from the transportation and handling of
 anhydrous ammonia. We consider these impacts manageable with the development of an RMP and additional safety
 procedures, and do not consider them sufficient enough to warrant eliminating either of these available control
 technologies.
----------------------------------------------------------------------------------------------------------------
                                              Remaining Useful Life
----------------------------------------------------------------------------------------------------------------
Control technology amortization period.......  ...........  20 years.................  20 years
----------------------------------------------------------------------------------------------------------------
                                             Visibility Improvement
----------------------------------------------------------------------------------------------------------------
Single largest Class I area improvement (dv).  ...........  0.23.....................  0.78
Single Class I area cost-effectiveness         ...........  $5.5.....................  $7.7
 (million $/dv).
Class I areas with >= 0.50 dv improvement....  ...........  0........................  1
Cumulative visibility improvement (dv).......  ...........  0.5......................  1.6
Cumulative cost-effectiveness (million $/dv).  ...........  $2.4.....................  $3.7
----------------------------------------------------------------------------------------------------------------

4. Proposed BART Analysis and Determination for SO2
    For our SO2 BART analysis, we identified all available 
control technologies, eliminated options that are not technically 
feasible, and evaluated the control effectiveness of the remaining 
control options. We then evaluated each control in terms of a five-
factor BART analysis and proposed a determination for BART.
a. Control Technology Availability, Technical Feasibility, and 
Effectiveness
    EPA identified three available and technically feasible 
technologies to control SO2 emissions from Sundt Unit 4. 
These technologies are lime or limestone-based wet flue gas 
desulfurization (wet FGD), lime spray dry absorber (SDA or dry FGD), 
and dry sorbent injection (DSI). While each of these control options 
has certain design concerns and constraints associated with their 
implementation, all three options are considered technically feasible.
    Lime or limestone-based wet FGD: Wet scrubbing systems mix an 
alkaline reagent, such as hydrated lime or limestone, with water to 
generate scrubbing slurry that is used to remove SO2 from 
the flue gas. The alkaline slurry is sprayed countercurrent to the flue 
gas, such as in a spray tower, or the flue gas may be bubbled through 
the alkaline slurry as in a jet bubbling reactor. As the alkaline 
slurry contacts the exhaust stream, it reacts with the SO2 
in the flue gas. Design variations may include changes to increase the 
alkalinity of the scrubber slurry, increase slurry/SO2 
contact, and minimize scaling and equipment problems. Insoluble calcium 
sulfite (CaSO3) and calcium sulfate (CaSO4) salts 
are formed in the chemical reaction that occurs in the scrubber, and 
exit as part of the scrubber slurry. The salts are eventually removed 
and handled as a solid waste byproduct. The waste byproduct is mainly 
CaSO3, which is difficult to dewater. Solid waste byproducts 
from wet lime scrubbing are typically managed in dewatering ponds and 
landfills.
    Design concerns associated with wet FGD involve the substantial 
water usage requirements needed to generate the alkaline reagent slurry 
as well as the substantial amount of wastewater and solid waste 
discharge associated with the spent byproduct. A wet FGD control system 
must be located after the fabric filter baghouse because the moist 
plume resulting from the wet scrubber system would create baghouse 
plugging issues if the control is placed ahead of the baghouse. In 
addition, a substantial footprint is required for the management of 
these waste products as well as for the absorber tower and associated 
process equipment such as the slurry preparation, mixing, associated 
tanks, and dewatering activities. While these design concerns do 
present some challenges, they do not warrant elimination of this option 
as technically infeasible.\59\
---------------------------------------------------------------------------

    \59\ TEP's review does not eliminate consideration of wet FGD, 
but does describe several design challenges that TEP notes should be 
reflected in the five factor analysis. We have incorporated certain 
elements of TEP's review in our analysis, as discussed in Step 4.
---------------------------------------------------------------------------

    Our contractor has estimated that newly constructed wet FGD systems 
could achieve design emission rates (annual average basis) of 0.06 lb/
MMBtu. Relative to baseline SO2 emission rates, this 
corresponds to a control efficiency of 92 percent. We recognize that 
FGD systems are designed to achieve more stringent emission rates, and 
have demonstrated an ability to achieve control efficiencies up to 98 
percent. Our contractor's report notes that the lower control 
efficiency cited here is regarded as a conservative estimate. While 
this is not the most stringent level of control that the technology is 
capable of achieving, we consider 92 percent control efficiency to be 
consistent with the median values reported for wet FGD systems.
    Lime SDA or dry FGD: A spray dryer absorber uses a stream of either 
dry lime or hydrated lime (semi-dry) in a reaction tower where it 
reacts with SO2 in the flue gas to form calcium sulfite 
solids. Unlike wet FGD systems that produce a slurry by-product that is 
collected

[[Page 9331]]

separately from the fly ash, dry FGD systems are designed to produce a 
dry byproduct that must be removed with the fly ash in the particulate 
control equipment. As a result, dry FGD systems must be located 
upstream of the particulate control device to remove the reaction 
products and excess reactant material. In instances where hydrated lime 
is used as a reagent, the reaction towers must be designed to provide 
adequate contact and residence time between the exhaust gas and the 
slurry to produce a relatively dry byproduct. Typical process equipment 
associated with a spray dryer typically includes an alkaline storage 
tank, mixing and feed tanks, an atomizer, spray chamber, particulate 
control device and a recycle system. The recycle system collects solid 
reaction products and recycles them back to the spray dryer feed system 
to reduce alkaline sorbent use.
    A design concern associated with a dry FGD system is that it must 
be installed prior to the fabric filter baghouse in order for the 
reagent to be captured and recycled. As noted in our contractor's 
report, the location of the existing fabric filter baghouse does not 
present enough space to install a new absorber between the boiler and 
the existing baghouse. As a result, a dry FGD at Sundt Unit 4 is 
assumed to include a new baghouse, which is reflected in the costs of 
compliance for the five-factor analysis. We consider this control 
option to be technically feasible.
    Our contractor has estimated that newly constructed dry FGD systems 
could achieve design emission rate (annual average basis) of 0.08 lb/
MMBtu. Relative to baseline SO2 emission rates, this 
corresponds to a control efficiency of 89 percent. As noted for wet FGD 
systems, this is a conservative estimate of what dry FGD systems can 
achieve, and is consistent with the median values reported for dry FGD 
systems.
    Dry Sorbent Injection: DSI involves the injection of powdered 
absorbent directly into the flue gas exhaust stream. These are simple 
systems that generally require a sorbent storage tank, feeding 
mechanism, transfer line and blower, and an injection device. The dry 
sorbent is typically injected countercurrent to the gas flow. An 
expansion chamber is often located downstream of the injection point to 
increase residence time and efficiency. Particulates generated in the 
reaction are controlled in the system's particulate control device. DSI 
requires less capital equipment, less physical space, and less 
modification to existing ductwork compared to a dry FGD system. 
However, reagent costs are much higher and, depending upon the 
absorbent and amount of sorbent injected, control efficiency is lower 
when compared to a dry FGD system. Soda ash and Trona (sodium 
sesquicarbonate) are potential options for reagent use. An important 
design consideration of DSI is the ability of the downstream 
particulate control device to accommodate the additional particulate 
loading resulting from the addition of the DSI reagent into the boiler 
flue gas. More effective particulate control devices allow for higher 
rates of sorbent injection, which in turn allow for more effective 
SO2 control.
    In a review of SO2 control options for BART eligible 
units, the Northeast States for Coordinated Air Use Management 
(NESCAUM) estimated control effectiveness for DSI in a range of 40-60 
percent.\60\ More recently, as part of work done as part of the 
Integrated Planning Model (IPM), EPA has estimated control 
effectiveness as high as 80 percent,\61\ depending upon factors such as 
the type of sorbent, the quantity of sorbent used, and the type of 
particulate control device employed. Generally, the use of more 
effective particulate control devices allow for higher rates of sorbent 
injection, and therefore greater DSI effectiveness. Since Sundt Unit 4 
operates with a fabric filter, we consider a control effectiveness 
value in the upper range appropriate, and have used 70 percent control 
effectiveness in our calculations. This value is above the range 
indicated in the NESCAUM study, but does not require the high sorbent 
injection rates required to achieve the upper range of control 
indicated in IPM documentation. A summary of the control technologies 
and their associated control effectiveness is presented in Table 11.
---------------------------------------------------------------------------

    \60\ ``Assessment of Control Technology Options for BART-
Eligible Sources'', Northeast States for Coordinated Air Use 
Management In Partnership with The Mid-Atlantic/Northeast Visibility 
Union, March 2005.
    \61\ IPM Model--Revisions to Cost and Performance for APC 
Technologies, Dry Sorbent Injection Cost Development Methodology, 
August 2010.

                 Table 11--Sundt 4: SO2 Control Options
------------------------------------------------------------------------
                                                              Control
                     Control option                        effectiveness
                                                                 %
------------------------------------------------------------------------
Dry Sorbent Injection...................................              70
Dry FGD or Lime SDA.....................................              89
Wet FGD (lime- or limestone-based)......................              92
------------------------------------------------------------------------

b. BART Analysis for SO2
    Costs of Compliance: Our consideration of the costs of compliance 
focuses primarily on the cost-effectiveness of each control option, as 
measured in cost per ton and incremental cost per ton. The emissions 
estimates and cost-effectiveness for the three control options are 
shown in Table 12 and Table 13, respectively. Both wet and dry FGD have 
average cost-effectiveness values over $5,000/ton, much greater than 
DSI, which is a control option that we consider very cost-effective at 
$1,857/ton. Moreover, both wet and dry FGD have very high incremental 
cost-effectiveness values, indicating that while they are more 
effective than less stringent control options, this additional degree 
of effectiveness comes at a substantial cost.
    In evaluating the costs of compliance for the control options, we 
have calculated the control costs ($) and emission reductions (tons/
year of pollutant) for each control technology, developed average cost-
effectiveness ($/ton) values, and arrived at the emission reductions 
for each option as summarized Table 12. A more detailed version of 
emission calculations is in our docket,\62\ and in our contractor's 
report. As noted previously in our NOX BART analysis, the 
heat duty and capacity factor used in these calculations differ from 
the values used in the calculations originally prepared by our 
contractor because the maximum gross capacity of Sundt Unit 4 while 
burning coal is about 130 MW, compared to its natural-gas nameplate 
capacity of 173 MW. The heat duty (MMBtu/hr) and capacity factor used 
in Table 12 reflect the coal-burning nameplate capacity.\63\ Detailed 
cost calculations presented in Table 13 are in the docket.\64\
---------------------------------------------------------------------------

    \62\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
    \63\ As noted by TEP and Burns and McDonnell, although the 
calculated capacity factor is different, the annual emissions in 
tons per year removed do not change significantly, as the change in 
capacity factor is largely offset by the change in maximum unit 
gross rating.
    \64\ See spreadsheet ``Sundt4 Control Costs 2014-01-26.xlsx'' in 
the docket.

[[Page 9332]]



                                                Table 12--Sundt 4: SO2 Control Option Emission Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Control      Emission    Heat  duty                   SO2 emission rate         SO2
                                                                efficiency     factor   -------------             --------------------------   emission
                        Control option                        --------------------------                Capacity                              reduction
                                                                                          (MMBtu/hr)     factor      (lb/hr)       (tpy)    ------------
                                                                   (%)       (lb/MMBtu)                                                         (tpy)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline (no control)........................................  ...........        0.729        1,371         0.49        1,000        2,145
DSI..........................................................           70        0.219        1,371         0.49          300          644        1,502
DFGD.........................................................           89        0.080        1,371         0.49          110          236        1,909
WFGD.........................................................           92        0.060        1,371         0.49           82          177        1,969
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                                Table 13--Sundt 4: SO2 Control Option Cost-Effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Capital     Annualized     Annual       Total       Emission    Cost-effectiveness  ($/
                                                                   cost       capital     operating   annual cost   reduction             ton)
                        Control option                        -------------     cost         cost    ---------------------------------------------------
                                                                           --------------------------
                                                                   ($)          ($)          ($)         ($/yr)       (tpy)         Ave      Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI..........................................................   $3,250,000     $306,777   $2,482,107   $2,788,884        1,502       $1,857
DFGD.........................................................   72,470,559    6,840,708    2,880,841    9,721,549        1,909        5,091      $17,007
WFGD.........................................................   80,629,663    7,610,870    3,227,467   10,838,337        1,969        5,505       18,795
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Pollution Control Equipment in use at Source: In the case of 
SO2, Sundt Unit 4 does not operate with any existing control 
technology. This is reflected in our selection of calendar year 2011 as 
the baseline period, which represents uncontrolled coal-fired 
emissions.
    Energy and Non-Air Quality Environmental Impacts: For wet FGD, 
energy impacts include certain auxiliary power requirements that are 
necessary to operate the wet FGD system and to potentially compensate 
for pressure head loss through the scrubber. These energy impacts are 
reflected as auxiliary power costs in the cost of compliance estimates. 
Non-air quality environmental impacts include water usage requirements 
and the storage and disposal of wet ash. Wet FGD requires very large 
quantities of water to ensure proper control effectiveness. Securing 
such quantities of water is a significant challenge in more arid 
regions of the country such as Arizona, and would preclude the use of 
that water for potentially more beneficial uses. The on-site storage 
and disposal of wet ash in large retention ponds triggers significant 
additional regulatory requirements, as it represents a substantial 
water pollution threat.
    For dry FGD, the energy and non-air environmental impacts are 
similar to those for wet FGD. Operation of a dry FGD system still 
requires securing significant supplies of water, although to a lesser 
degree than wet FGD systems. In addition, dry FGD systems will result 
in generation of larger quantities of boiler ash, and has the potential 
to affect negatively the properties and quality of boiler ash. In some 
instances, boiler ash that is suitable to sell for beneficial purposes 
may no longer be marketable following installation of a dry FGD system. 
Energy impacts also include auxiliary power requirements for operation 
of the dry FGD system, and for overcoming pressure head loss through 
the scrubber. While we note certain potential impacts resulting from 
the water resource requirements associated with wet FGD as well as the 
additional solid waste generation associated with wet and dry FGD, we 
do not consider these impacts sufficient enough to warrant eliminating 
these control technologies.
    DSI could potentially have an adverse effect on the quality of the 
boiler fly ash, which would make it unmarketable for beneficial uses. 
Use of DSI also results in an ash byproduct which would require 
landfill disposal, thereby increasing solid waste generation rates at 
the plant. Energy impacts are limited to auxiliary power requirements 
for operation of the DSI system. We do not consider these impacts 
sufficient enough to warrant eliminating this control technology.
    Remaining Useful Life of the Source: We are considering the 
remaining useful life of Sundt Unit 4 as one element of the overall 
cost analysis as allowed by the BART Guidelines. Since we are not aware 
of any federally- or State-enforceable shut down date for Sundt Unit 4, 
we have used a 20-year amortization period described in the EPA Cost 
Control Manual as the remaining useful life for the control options 
considered for Unit 4. We note that the remaining useful life of the 
source is reflected in the evaluation of cost of compliance through the 
use of a 20-year amortization period in control cost calculations.
    Degree of Visibility Improvement: The visibility improvement due to 
SO2 controls is modest. As shown in Table 14, control via 
DSI, with a 70 percent SO2 emissions reduction, gives a 
maximum visibility improvement of 0.2 dv, which occurs at Saguaro. 
Three other areas improve about half as much, and the cumulative 
improvement is 0.8 dv. Emissions controls via dry and wet FGD were 
modeled at 89 percent and 92 percent SO2 emissions 
reduction, respectively. Both dry and wet FGD would cause a visibility 
disbenefit at Saguaro as indicated by the negative improvements in 
Table 14. The disbenefit is mainly due to the decreased stack exit 
temperature and exit velocity associated with these technologies, and 
more so for wet FGD than for dry FGD. These stack decreases result in 
less plume rise and increased impacts nearby. At areas farther away, 
the disbenefit is outweighed by the benefit of SO2 
reductions from FGD. This issue is discussed further in the TSD. With 
FGD, the maximum benefit occurs not at Saguaro, but at Galiuro, with 
0.2 dv for dry FGD and 0.1 dv for wet FGD. The corresponding cumulative 
improvements are 0.6 dv and 0.4 dv for dry and wet FGD, respectively, 
including the areas of disbenefit. All these improvements are 
substantially lower than those from DSI, and the visibility cost-
effectiveness of each FGD is more than quadruple that of DSI. EPA finds 
that the improvement from DSI is substantial enough to support its 
selection as BART, and that it is clearly a better choice than dry FGD 
and wet FGD.

[[Page 9333]]



                     Table 14--Sundt 4: Visibility Impact and Improvement From SO2 Controls
----------------------------------------------------------------------------------------------------------------
                                                            Visibility             Visibility improvement
                                              Distance        impact      --------------------------------------
               Class I Area                     (km)    ------------------   DSI 70%      Dry FGD      Wet FGD
                                                            Base  case       (ctrl14)     (ctrl02)     (ctrl03)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM.............................          144              0.43         0.05         0.07         0.06
Chiricahua Wild...........................          141              0.51         0.10         0.10         0.11
Galiuro Wild..............................           64              1.10         0.10         0.16         0.09
Gila Wild.................................          232              0.17         0.04         0.05         0.05
Mazatzal Wild.............................          203              0.19         0.07         0.08         0.09
Mount Baldy Wild..........................          232              0.15         0.05         0.05         0.06
Pine Mountain Wild........................          247              0.15         0.05         0.06         0.06
Saguaro NP................................           17              3.40         0.20        -0.16        -0.27
Sierra Ancha Wild.........................          178              0.19         0.06         0.08         0.08
Superstition Wild.........................          137              0.32         0.09         0.10         0.10
Cumulative (sum)..........................  ...........               6.6          0.8          0.6          0.4
Maximum...................................  ...........              3.40         0.20         0.16         0.11
 CIAs >= 0.5 dv..................  ...........                 3            0            0            0
Million $/dv (cumul. dv)..................  ...........  ................         $3.5        $16.4        $25.1
Million $/dv (max. dv)....................  ...........  ................          $14          $60          $97
----------------------------------------------------------------------------------------------------------------

c. BART Determination for SO2
    EPA proposes an emission limit of 0.23 lb/MMBtu on a 30-day (BOD) 
rolling basis as BART to control SO2 from Sundt Unit 4. This 
emission limit, equivalent to using DSI, is considered very cost-
effective at $1,857/ton. In evaluating the appropriate emission limit 
for DSI, we have considered the annual average design value for DSI of 
0.21 lb/MMBtu as well as the need to account for emissions associated 
with startup and shutdown events. To determine how to account for this 
variability, we have examined the difference between the highest 30-day 
rolling SO2 value and the highest annual average 
SO2 value observed over the baseline period, which is 
approximately 9 percent.\65\ We have applied this variability to the 
annual average design value to develop a 30-day BOD rolling emission 
limit, which we consider a sufficient margin for a limit that will 
apply at all times. Please refer to Table 15 that provides a summary of 
our five-factor BART analysis.
---------------------------------------------------------------------------

    \65\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
---------------------------------------------------------------------------

    We propose to require compliance with this requirement within three 
years of the effective date of the final rule. However, we are seeking 
comment on whether this compliance date is reasonable and consistent 
with the requirement of the Clean Air Act that BART be installed ``as 
expeditiously as practicable but in no event later than five years 
after [promulgation of the applicable FIP].'' \66\ If we receive 
information during the comment period that establishes that a different 
compliance time frame is appropriate, we may finalize a different 
compliance date. We are also proposing regulatory text that includes 
monitoring, reporting, and recordkeeping requirements associated with 
this emission limit.
---------------------------------------------------------------------------

    \66\ Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4).

                               Table 15--Sundt 4: Summary of BART Analysis for SO2
----------------------------------------------------------------------------------------------------------------
     Sundt Unit 4 (130 MW)        Baseline            DSI                  Dry FGD                Wet FGD
----------------------------------------------------------------------------------------------------------------
Emission Factor (lb/MMBtu)....        0.729  0.219................  0.08.................  0.06
Emission Rate (tpy)...........         2145  644..................  236..................  177
Emission Reduction (tpy)......  ...........  1,502................  1,909................  1,969
Control Effectiveness.........  ...........  70%..................  89%..................  92%
----------------------------------------------------------------------------------------------------------------
                                               Cost of Compliance
----------------------------------------------------------------------------------------------------------------
Capital Cost ($)..............  ...........  $3,250,000...........  $72,470,559..........  $80,629,663
Annualized Capital Cost ($)...  ...........  $306,777.............  $6,840,708...........  $7,610,870
Annual O&M ($)................  ...........  $2,482,107...........  $2,880,841...........  $3,227,467
Total Annual Cost ($).........  ...........  $2,788,884...........  $9,721,549...........  $10,838,337
Ave CE ($/ton)................  ...........  $1,857...............  $5,091...............  $5,505
Incremental CE ($/ton)........  ...........  .....................  $23,081..............  $18,795
----------------------------------------------------------------------------------------------------------------
                                  Pollution Control Equipment in Use at Source
----------------------------------------------------------------------------------------------------------------
There is no existing control technology for SO2
----------------------------------------------------------------------------------------------------------------
                                Energy and Non-Air Quality Environmental Impacts
----------------------------------------------------------------------------------------------------------------
Energy impacts are reflected in annual O&M costs in the costs of compliance.
----------------------------------------------------------------------------------------------------------------
Wet ash from wet and dry FGD represents a substantial water pollution threat.
----------------------------------------------------------------------------------------------------------------
Water resources for wet and dry FGD may preclude more beneficial uses of water.
----------------------------------------------------------------------------------------------------------------
                                              Remaining Useful Life
----------------------------------------------------------------------------------------------------------------
Control technology              ...........  20 years.............  20 years.............  20 years
 amortization period.
----------------------------------------------------------------------------------------------------------------

[[Page 9334]]

 
                                             Visibility Improvement
----------------------------------------------------------------------------------------------------------------
Single largest Class I area     ...........  0.20.................  0.16.................  0.11
 improvement (dv).
Single Class I area cost-       ...........  $14.3................  $60.4................  $96.8
 effectiveness (million $/dv).
Class I areas with >= 0.50 dv   ...........  0....................  0....................  0
 improvement.
Cumulative visibility           ...........  0.8..................  0.6..................  0.4
 improvement (dv).
Cumulative cost-effectiveness   ...........  $3.5.................  $16.4................  $25.1
 (million $/dv).
----------------------------------------------------------------------------------------------------------------

 3. Proposed BART Analysis and Determination for PM10
a. Control Technology Availability, Technical Feasibility, and 
Effectiveness
    Sundt Unit 4 currently operates with a fabric filter baghouse for 
particulate control, which is considered the most stringent control 
device for particulate matter. These devices operate on the same 
principle as a vacuum cleaner. Air carrying dust particles is forced 
through a cloth bag that is designed and manufactured to trap particles 
greater than a certain specified diameter. As the air passes through 
the fabric, the dust accumulates on the cloth and is removed from the 
air stream. The accumulated dust is periodically removed from the cloth 
by shaking or by reversing the air flow. The layer of dust, known as 
dust cake, trapped on the surface of the fabric has the potential to 
result in high efficiency rates for particles ranging in size from 
submicron to several hundred microns in diameter.
b. BART Analysis for PM10
    The BART Guidelines provide that, where a source has controls 
already in place that are the most stringent controls available, it is 
not necessary to complete comprehensively a full five-factor BART 
analysis, as long the most stringent controls available are made 
federally enforceable. Therefore, instead of completing the remaining 
steps of a five-factor BART analysis, we have evaluated the appropriate 
level of emissions to ensure that the fabric filter achieves an 
appropriate degree of control.
c. Proposed BART Determination for PM10
    EPA is proposing a filterable PM10 BART emission limit 
of 0.03 lb/MMBtu based on the use of the existing fabric filter 
baghouse currently in operation, which is the most stringent control 
for particulate matter. We note that Mercury and Air Toxics (MATS) Rule 
establishes an emission standard of 0.03 lb/MMBtu filterable PM (as a 
surrogate for toxic non-mercury metals) as representing Maximum 
Achievable Control Technology (MACT) for coal-fired EGUs.\67\ This 
standard derives from the average emission limitation achieved by the 
best performing 12 percent of existing coal-fired EGUs, as based upon 
test data used in developing the MATS Rule.\68\ The BART Guidelines 
provide that, ``unless there are new technologies subsequent to the 
MACT standards which would lead to cost-effective increases in the 
level of control, you may rely on the MACT standards for purposes of 
BART.'' \69\ Therefore, we propose to find that 0.03 lb/MMBtu 
filterable PM10 is an appropriate limit for BART at Sundt 
Unit 4.
---------------------------------------------------------------------------

    \67\ 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40 
CFR 60.42Da(a), 60.50Da(b)(1)).
    \68\ See Memorandum from Jeffrey Cole (RTI International) to 
Bill Maxwell (EPA) regarding ``National Emission Standards for 
Hazardous Air Pollutants (NESHAP) Maximum Achievable Control 
Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric 
Utility Steam Generating Units for Final Rule'' (December 16, 2011).
    \69\ 40 CFR Part 51, Appendix Y, Section IV.C.
---------------------------------------------------------------------------

4. Better Than BART Alternative
    We are proposing a switch to natural gas on Sundt Unit 4 as a 
better-than-BART alternative to the emissions controls previously 
proposed in this section for a coal-fired unit. Unit 4 was originally 
constructed as a natural gas-fired boiler, and has used natural gas as 
a primary fuel for significant periods of time since 2009. While a 
change in fuel supply to natural gas instead of coal is an inherently 
less polluting option, the BART Guidelines do not require the 
consideration of fuel supply changes as a control option.\70\ As a 
result, the option of burning only natural gas is not considered in our 
BART analysis. However, TEP has submitted to EPA an alternative to BART 
based on the elimination of coal as a fuel source for Sundt Unit 4 by 
December 31, 2017. As part of this submittal, TEP compared the 
potential emission reductions and visibility benefit between a natural 
gas fuel change and certain combinations of NOX and 
SO2 controls.\71\
---------------------------------------------------------------------------

    \70\ 40 CFR Part 51, Appendix Y, Section IV.D.1.5, ``STEP 1: How 
do I identify all available retrofit emission control techniques?''
    \71\ Letter dated November 1, 2013.
---------------------------------------------------------------------------

    EPA has evaluated this alternative proposal pursuant to the 
``better-than-BART'' provisions of the RHR. In particular, the RHR 
allows for implementation of ``an emissions trading program or other 
alternative measure'' in lieu of BART if the alternative measure 
achieves greater reasonable progress than would be achieved through the 
installation and operation of BART.\72\ The rule further states that 
``[i]f the distribution of emissions is not substantially different 
than under BART, and the alternative measure results in greater 
emissions reductions, than the alternative measures may be deemed to 
achieve greater reasonable progress''.\73\ Because the emissions 
reductions under EPA's BART proposal for Sundt Unit 4 and the 
reductions from TEP's proposed alternative would occur at the same 
facility, the distribution of emissions under BART and the alternative 
are not substantially different. Therefore, if the alternative emission 
control strategy results in greater emissions reductions than our BART 
proposal, EPA may deem the alternative emission control strategy to 
achieve greater reasonable progress. A comparison of annual emission 
estimates between the BART determination and alternative to BART is 
summarized in Table 16. BART determination annual emissions are based 
upon the annual average emission factors and annual capacity factor 
used in our BART analysis, consistent with coal usage. For the 
alternative to BART, annual emissions are based on a combination of 
historical natural gas usage data as indicated in TEP's submittal, as 
well as standard emission factors for natural gas combustion. A more 
detailed discussion of emission estimates from these two scenarios is 
included in our TSD.
---------------------------------------------------------------------------

    \72\ 40 CFR 51.308(e)(2).
    \73\ 40 CFR 51.308(e)(3).

[[Page 9335]]



                   Table 16--Sundt 4: Comparison of BART Determination and Alternative to BART
----------------------------------------------------------------------------------------------------------------
                                                                               Natural gas fuel
            Parameters                    Units          BART determination         switch          Difference
----------------------------------------------------------------------------------------------------------------
Heat Duty........................  MMBtu/hr...........  1,371..............  1,828..............
Capacity Factor..................  ...................  0.49...............  0.37...............
NOX..............................  Ctrl Tech..........  SNCR+LNB+OFA.......  LNB+OFA............
                                   lb/MMBtu \1\.......  0.31...............  0.22...............
                                   tpy................  917................  652................             265
Particulate Matter...............  Ctrl Tech..........  Fabric Filter......  None...............
                                   lb/MMBtu \1\.......  0.03...............  0.01...............
                                   tpy................  88.................  30.................              59
SO2..............................  Ctrl Tech..........  Dry Sorbent          None...............
                                                         Injection.
                                   lb/MMBtu\1\........  0.22...............  0.00064............
                                   tpy................  644................  1.9................             642
----------------------------------------------------------------------------------------------------------------
\1\ Annual average emission factors.

    As seen in Table 16, a change to natural gas usage achieves greater 
emission reductions than each of the individual BART determinations for 
NOX, SO2, and particulate matter, as well as in 
the aggregate. Although visibility modeling is not required to support 
a better-than-BART determination in this instance, EPA conducted 
modeling to verify the visibility benefits of the proposed alternative, 
as compared with EPA's BART determination. This modeling is described 
in the TSD and the results are summarized in Table 17.

 Table 17--Sundt 4: Visibility Impact and Improvement From Combined SO2 and NOX BART, and From Better-Than-BART
                                                   Alternative
----------------------------------------------------------------------------------------------------------------
                                                                            Visibility   Visibility improvement
                                                                              impact   -------------------------
                        Class I Area                            Distance  -------------   SNCR DSI
                                                                  (km)                      70%      Natural gas
                                                                            Base case     (ctrl15)     (ctrl13)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM...............................................          144         0.43         0.09         0.19
Chiricahua WA...............................................          141         0.51         0.16         0.25
Galiuro WA..................................................           64         1.10         0.24         0.47
Gila WA.....................................................          232         0.17         0.06         0.10
Mazatzal WA.................................................          203         0.19         0.08         0.12
Mount Baldy WA..............................................          232         0.15         0.06         0.09
Pine Mountain WA............................................          247         0.15         0.06         0.09
Saguaro NP..................................................           17         3.40         0.49         1.06
Sierra Ancha WA.............................................          178         0.19         0.08         0.12
Superstition WA.............................................          137         0.32         0.11         0.19
Cumulative (sum)............................................  ...........          6.6          1.4          2.7
Maximum.....................................................  ...........         3.40         0.49         1.06
 CIAs >= 0.5 dv....................................  ...........            3            0            1
Million $/dv (cumul. dv)....................................  ...........  ...........         $2.8  ...........
Million $/dv (max. dv)......................................  ...........  ...........         $8.3  ...........
----------------------------------------------------------------------------------------------------------------

    Since Sundt is only 17 km from the eastern unit of Saguaro, its 
emitted NOX may not be fully converted to NO2 by 
the time it reaches there, as is assumed in the CALPUFF model. It thus 
may not be fully available to form visibility-degrading particulate 
nitrate. EPA explored this issue in CALPUFF sensitivity simulations 
described in the TSD. For EPA's proposed BART of SNCR plus DSI, the 
visibility improvement remains above 0.3 dv even when unrealistically 
low 10 percent NO-to-NO2 conversion is assumed (i.e., no 
additional conversion of NO to NO2 once the plume leaves the 
stack). The improvement from switching to natural gas remains above 0.7 
dv at Saguaro. These results show that the FIP's proposed BART 
determination remains reasonable despite any concern over the NO 
conversion rate; the visibility improvement from BART remains 
substantial. The finding that natural gas provides better visibility 
improvement than the proposed BART determination also remains sound 
regardless of the NO conversion assumed.
    Based on this information, we consider a natural gas fuel switch to 
result in greater emission reductions and achieve greater reasonable 
progress than the proposed BART determinations. Under this scenario, we 
are proposing a NOX emission limit of 0.25 lb/MMBtu based on 
a 30-day BOD rolling average. As discussed previously in the 
NOX BART determination, this represents about a 17 percent 
increase from the annual average emission rate of 0.22 lb/MMBtu, which 
we consider to provide sufficient margin for a limit that will apply at 
all times, including periods of startup and shutdown. In addition, we 
are proposing particulate matter and SO2 emission limits 
consistent with natural gas use, as well as monitoring, reporting, and 
recordkeeping requirements.

B. Chemical Lime Nelson Plant Kilns 1 and 2

    Summary: EPA is proposing to find that Chemical Lime Nelson is 
subject to BART. EPA is proposing BART emission limits for 
NOX, SO2 and PM10 for Kilns 1 and 2 at 
the Nelson Plant as listed in Table 18 and described in this section.

[[Page 9336]]



                      Table 18--Nelson Lime Plant: Summary of Proposed BART Determinations
----------------------------------------------------------------------------------------------------------------
                                                                                            Control technology*
               Source                       Pollutant        Emission Limit (lb/ton feed)  (for  reference only)
----------------------------------------------------------------------------------------------------------------
Kiln 1.............................  NOX...................                          3.80  Selective Non-
                                                                                            Catalytic Reduction
                                                                                            (SNCR).
                                     SO2...................                          9.32  Lower sulfur fuel.
                                     PM10..................                          0.12  Fabric filter
                                                                                            baghouse (existing).
Kiln 2.............................  NOX...................                          2.61  Selective Non-
                                                                                            Catalytic Reduction
                                                                                            (SNCR).
                                     SO2...................                          9.73  Lower sulfur fuel.
                                     PM10..................                          0.12  Fabric filter
                                                                                            baghouse (existing).
----------------------------------------------------------------------------------------------------------------
* The facility is not required to install the listed technology to meet the BART limit.

    Affected Class I Areas: Nine Class I areas are within 300 km of the 
Nelson Lime Plant. Their nearest borders range from 24 km to 289 km 
away, with the Grand Canyon the closest and other areas more than 100 
km away. The highest baseline visibility impact from the Nelson Plant 
is 1.79 dv at Grand Canyon NP followed by 0.31 at Sycamore Canyon WA 
and 0.28 at Zion NP. The cumulative sum of visibility impacts over all 
the Class I areas is 3.34 dv.
    Facility Overview: The Nelson Plant processes limestone and 
manufactures lime near Peach Springs in Yavapai County, Arizona. The 
limestone processing plant consists of a quarry mining operation, a 
limestone crushing and screening operation, a limestone kiln feed 
system, a solid fuel handling system, two rotary lime kilns, front and 
back lime handling systems, a lime hydrator, diesel electric 
generators, fuel storage tanks, and other support operations and 
equipment. The lime manufacturing equipment consists of two lime rotary 
kilns (Kiln 1 and Kiln 2) and auxiliary equipment necessary for 
receiving crushed limestone, processing it through the lime kilns, and 
processing the lime kiln product. The lime kilns are used to convert 
crushed limestone (CaCO3) into quicklime (CaO).
    We primarily relied on four sources of information for our proposed 
BART analyses and determinations. An initial BART analysis performed by 
our contractor \74\ is available in the docket in the form of a final 
contractor's report and associated modeling spreadsheets. We also 
incorporated elements of a five-factor BART analysis \75\ provided by 
Lhoist North America (LNA) of Arizona, owner of the Nelson Plant, that 
includes control cost estimates and visibility modeling. Another key 
document in our analysis is the Nelson Lime Plant's Title V Operating 
Permit.\76\
---------------------------------------------------------------------------

    \74\ Technical Analysis for Arizona and Hawaii Regional Haze 
FIPs: Task 7: Five-Factor BART Analysis for Chemical Lime Company 
Nelson, TEP Sundt (Irvington), and Catalyst Paper (Snowflake) 
Plants, Contract No. EP-D-07-102, Work Assignment 5-12; Prepared for 
EPA Region 9 by University of North Carolina at Chapel Hill, ICF 
International, and Andover Technology Partners; October 9, 2012.
    \75\ BART Five Factor Analysis, Lhoist North America Nelson Lime 
Plant; Prepared by Trinity Consultants in Conjunction with Lhoist 
North America of Arizona, Inc.; Project 131701.0061; August 2013. 
(Public version dated September 27, 2013).
    \76\ Title V Operating Permit and Technical Support Document for 
the Nelson Lime Plant, Permit  42782, Issued August 8, 2011 
by the Arizona Department of Environmental Quality.
---------------------------------------------------------------------------

    Baseline Emissions Calculations: LNA's approach to establishing 
baseline emissions was to first establish baseline emission factors in 
lb/ton lime based on CEMS testing performed from March to June 2013. 
Annual average baseline emissions were calculated by multiplying these 
lb/ton emission factors by the highest annual lime production rate 
observed over a period from 2001 to 2012. Maximum daily emissions were 
calculated by multiplying lb/ton emission factors by the maximum daily 
lime production rate observed during the March to June 2013 testing 
period. As explained in further detail in our TSD, we consider LNA's 
general approach appropriate, but also note that it represents a 
conservatively high estimate of baseline emissions, and potentially 
overstates the anticipated emission reductions and visibility benefit 
from the evaluated control options. Nonetheless, given the lack of 
measured annual emissions data, we concur with LNA's use of a 
conservatively high baseline emissions estimate and we have 
incorporated this estimate into our analysis. The baseline daily and 
annual emission rates and associated production levels are shown in 
Table 19.

                           Table 19--Nelson Lime Plant: Summary of Maximum Daily and Annual Baseline Emissions for NOX and SO2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                Lime production                              NOX                                    SO2
                                    --------------------------------------------------------------------------------------------------------------------
                                      Max daily    Max annual      Year       Emission       Maximum emissions       Emission       Maximum emissions
                Kiln                     \2\     --------------------------  factor \1\ --------------------------  factor \1\ -------------------------
                                    -------------                          -------------                          -------------
                                                     (tpy)                    (lb/ton      (lb/day)      (tpy)       (lb/ton      (lb/day)      (tpy)
                                        (tpd)                                  lime)                                  lime)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Kiln 1.............................          866  \3\ 258,508         2010         7.59        6,573          981        12.15       10,522        1,570
Kiln 2.............................        1,246  \4\ 378,296         2012         5.21        6,492          985        12.69       15,812        2,400
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Maximum emission factors observed during March, May and June 2013 CEMS testing.
\2\ Maximum daily rates occurring during the March 2013 CEMS testing.
\3\ 2010.
\4\ 2012.

1. Proposed Subject to BART
    As part of our July 30, 2013 final rulemaking on the Arizona RH 
SIP, we approved ADEQ's finding that Chemical Lime Nelson Plant (Nelson 
Lime Plant) Kilns 1 and 2 were BART-eligible, but disapproved ADEQ's 
determination that the Nelson Lime Plant was not subject to BART.\77\ 
In light of this disapproval, we have conducted our own evaluation of 
whether Nelson Lime Plant is subject to BART, relying primarily on 
emissions

[[Page 9337]]

data and modeling results provided by the facility's owner, LNA.\78\
---------------------------------------------------------------------------

    \77\ 78 FR 46175 (codified at 40 CFR 52.145(g)(1)(i)).
    \78\ BART Five Factor Analysis, Lhoist North America Nelson Lime 
Plant; Prepared by Trinity Consultants in Conjunction with Lhoist 
North America of Arizona, Inc.; Project 131701.0061; August 13, 2013 
(Public version dated September 27, 2013).
---------------------------------------------------------------------------

    As explained in the TSD, the baseline emissions estimates and the 
corresponding modeling results provided by LNA are conservative (i.e., 
tending to overestimate rather than underestimate the impacts, in this 
case). Nonetheless, we consider these results to be appropriate for 
purposes of a subject-to-BART determination, as well as for the five-
factor BART analysis. LNA's modeling results indicate that the 98th 
percentile impact for each of the 3 years modeled is well over 0.5 dv 
at Grand Canyon National Park.\79\ Therefore, we propose to determine 
that Nelson Lime Plant (Kilns 1 and 2) is subject to BART.
---------------------------------------------------------------------------

    \79\ Id., Table 4-7. We note that the visibility modeling 
performed by LNA used only the annual average Class I area 
background concentrations, rather than the best 20 percent days 
background concentrations. The use of annual average generally 
results in lower visibility impacts than the best 20 percent days. 
Therefore, had LNA used the best 20 percent days, the baseline 
impacts would likely have been even greater.
---------------------------------------------------------------------------

 2. Proposed BART for NOX
    For our NOX BART analysis, we identified all available 
control technologies, eliminated options that are not technically 
feasible, and evaluated the control effectiveness of the remaining 
control options. We then evaluated each control in terms of a five-
factor BART analysis and made a determination for BART.
a. Control Technology Availability, Technical Feasibility and 
Effectiveness
    EPA proposes to find that SNCR is the only technically feasible 
control option to control NOX emissions with a control 
efficiency of 50 percent. In order to determine a reasonable 
performance standard for controlling NOX emissions, we 
considered four available retrofit control technologies for 
NOX on Kilns 1 and 2. These control technologies are a LNB, 
mixing air technology (MAT), SCR, and SNCR. After evaluating each of 
these technologies to eliminate technically infeasible options, we 
determined that SNCR is the only remaining technically feasible control 
option.
    Low-NOX Burners: LNB are designed to reduce flame 
turbulence, delay fuel/air mixing, and establish fuel-rich zones for 
initial combustion. LNA indicated that it experimented with the 
installation of bluff body LNB on the Nelson Lime Plant kilns in 
2001.\80\ These LNB wore out in about six months, negatively affected 
production, caused brick damage, and resulted in unscheduled shutdowns 
of the kilns. We recognize that the staged combustion principle of LNB 
can present operational difficulties and potential product quality 
issues for lime production that are not exhibited in the cement 
industry. At this time we consider LNB to be technically infeasible for 
the Nelson Plant kilns, since we do not have any information to suggest 
otherwise at this time. The technical feasibility of LNB will be re-
evaluated for lime kilns in subsequent reasonable progress planning 
periods.
---------------------------------------------------------------------------

    \80\ Described on page 5-2, ``BART Five Factor Analysis, Lhoist 
North America Nelson Lime Plant'' (Public version dated September 
27, 2013).
---------------------------------------------------------------------------

    Mixing Air Technology: MAT is the practice of injecting a high 
pressure air stream into the middle of a kiln to help mix the air 
flowing through the kiln. While the theory behind MAT suggests that the 
technology is effective at reducing NOX emissions, it is not 
clear whether this control technology is effective on lime kilns. We 
propose to eliminate MAT as not technically feasible for retrofit on 
Kiln 1 and Kiln 2.
    Selective Catalytic Reduction: This process uses ammonia in the 
presence of a catalyst to selectively reduce NOX emissions 
from exhaust gases. In SCR, ammonia, usually diluted with air or steam, 
is injected through a grid system into hot flue gases that are then 
passed through a catalyst bed to carry out NOX reduction 
reactions. The catalyst is not consumed in the process but allows the 
reactions to occur at a lower temperature. However, SCR is subject to 
catalyst poisoning in high dust kiln exhausts. Therefore, SCR would 
have to be placed after the particulate control systems. According to 
LNA, given the operating temperature range for Kiln 1 and Kiln 2 at the 
Nelson Lime Plant, the SCR catalyst would need to be located prior to 
the kiln baghouses, which would result in poisoning or covering of the 
catalyst. In addition, there are no SCR systems currently operating on 
lime kilns. We propose to eliminate SCR as not technically feasible for 
retrofit on Kiln 1 and Kiln 2.
    Selective Non-Catalytic Reduction: SNCR is a technically feasible 
option for reducing NOX emissions from the Nelson Lime Plant 
kilns as shown in Table 20. This control technique relies on the 
reduction of NOX in exhaust gases by injection of ammonia or 
urea, without using any catalyst. This approach avoids the problems 
related to catalyst fouling and poisoning attributed to SCR, but 
requires injection of the reagents in the kiln at a temperature between 
1600[emsp14][deg]F to 2000[emsp14][deg]F. Because no catalyst is used 
to increase the reaction rate, the temperature window is critical for 
conducting this reaction. LNA has not conducted any detailed design 
work for an SNCR system for the Nelson Plant kilns, but anticipates 
that a 50 percent reduction is achievable based on LNA's experience 
with operating a urea-injection system at another LNA lime plant.

                   Table 20--Nelson Lime Plant: SNCR Control Efficiency for Baseline Emissions
----------------------------------------------------------------------------------------------------------------
                                      Control        Emission          Maximum emission rate         Emissions
                                    efficiency        factor     --------------------------------     removed
         Control option          --------------------------------                                ---------------
                                        (%)        (lb/ton lime)     (lb/day)          (tpy)           (tpy)
----------------------------------------------------------------------------------------------------------------
Kiln 1:
    Baseline....................  ..............            7.59           6,573             981
    SNCR........................              50            3.80           3,286             491             491
Kiln 2:
    1Baseline...................  ..............            5.21           6,492             985
    SNCR........................              50            2.61           3,246             493             493
----------------------------------------------------------------------------------------------------------------


[[Page 9338]]

b. BART Analysis for NOX
    EPA conducted a five-factor BART analysis of SNCR to evaluate its 
cost-effectiveness and visibility benefit. This analysis indicates that 
SNCR is cost-effective and results in visibility improvement.
    Cost of Compliance: The following table provides LNA's estimated 
cost for installation and operation of SNCR. Capital cost estimates 
developed by LNA relied primarily on vendor cost estimates and LNA's 
experience at other lime plants, with the remainder of the capital 
costs calculated using the cost methodology contained in EPA's Control 
Cost Manual. LNA has asserted a confidential business information (CBI) 
claim regarding certain annual operating costs such as reagent usage 
and auxiliary power costs. As a result, we have prepared our own 
independent estimate of annual operating costs based upon a combination 
of publicly available data and certain general assumptions as described 
in the Contractor's Report.\81\ Table 21 is a summary of the estimated 
cost for installation and operation of SNCR.
---------------------------------------------------------------------------

    \81\ Our estimate of annual operating costs is in the 
spreadsheet ``Nelson Control Costs 2013-10-21.xlsx'' in the docket.

                                                  Table 21--Nelson Lime Plant: Estimated Cost for SNCR
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Capital cost     Annualized        Annual       Total annual      Emission          Cost-
                                                         ----------------  capital cost   operating cost       cost          reduction     effectiveness
                          Kiln                                           -------------------------------------------------------------------------------
                                                                ($)             ($)             ($)           ($/yr)           (tpy)          ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Kiln 1..................................................        $450,000         $42,477        $358,459        $400,936             491            $817
Kiln 2..................................................         450,000          42,477         354,981         397,458             493             807
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: SNCR systems 
require electricity to operate the blowers and pumps, which will likely 
involve fuel combustion that will generate emissions. Overall, while 
the generation of the required electricity will result in emissions, 
the emissions should be low compared to the reduction in NOX 
that would be gained by operating an SNCR system. The operation of SNCR 
systems on Kiln 1 and Kiln 2 would require that either urea or ammonia 
be stored on site. The storage of the chemicals does not result in a 
direct non-air quality impact. However, the potential for the urea or 
ammonia that would be stored to leak or otherwise be released from the 
storage vessels means there is the potential for both air and non-air 
quality related impacts. The storage of these chemicals does not 
significantly impact the BART determination.
    Pollution Control Equipment in Use at the Source: The presence of 
existing pollution control technology at each source is reflected in 
our BART analysis in two ways: first, in the consideration of available 
control technologies, and second, in the development of baseline 
emission rates for use in cost calculations and visibility modeling. 
Air pollution control equipment in use at the Nelson Lime Plant 
includes a number of baghouses, two multi-cyclone dust collectors, and 
a Ducon wet scrubber to control particulate matter emissions. The 
facility does not currently have control equipment for NOX 
and SO2. The kilns are allowed to burn coal, petroleum coke, 
fuel oil, or any combination of these fuels.
    Remaining Useful Life of the Source: Since we are not aware of any 
enforceable shutdown date for the Nelson Lime Plant, we have used a 20-
year amortization period, as noted in the EPA Cost Control Manual, as 
the remaining useful life of the kilns.
    Degree of Visibility Improvement: LNA performed a visibility 
analysis \82\ to assess the visibility improvement associated with 
SNCR. LNA performed dispersion modeling using the CALPUFF modeling 
system, which consists of the CALPUFF dispersion model, the CALMET 
meteorological data processor, and the CALPOST post-processing program. 
The specific program versions that were relied upon in the analysis 
match the program versions relied upon by EPA's contractor, the 
University of North Carolina at Chapel Hill and ICF International (UNC/
ICF), in the BART analyses that they prepared for select sources, 
including the Nelson Plant. Most of the same data and parameter 
settings relied upon in the analysis are the same data and parameter 
settings that were relied upon in the contractor's report. Compared to 
the UNC work, LNA used updated higher base case SO2 and NOx 
emissions, lower PM emissions, and lower stack exit velocities. LNA's 
analysis included tables of visibility impacts and the improvement from 
controls, including results for the individual model years 2001, 2002, 
and 2003, and it used visibility method ``8a'' and focused on the 
highest value from among the three years' 98th percentiles. In order to 
put all the facilities on the same footing, EPA post-processed the 
modeling files provided by LNA using the approach followed for the 
other facilities.
---------------------------------------------------------------------------

    \82\ BART Five Factor Analysis, Lhoist North America Nelson Lime 
Plant, Trinity Consultants, August 2013.
---------------------------------------------------------------------------

    Table 22 represents the 98th percentile by the 22nd high over the 
2001-2003 period using visibility method ``8b.'' Using the EPA 
procedure, the maximum impact still occurs at the Grand Canyon, at 1.8 
dv. The 98th percentile impacts at other Class I areas are about 0.3 dv 
or below, and the cumulative impact is 3.3 dv. The maximum visibility 
improvement due to SNCR is 0.58 dv, and cumulative improvement is 0.85 
dv. There is little improvement at areas other than the Grand Canyon. 
These improvements yield a visibility cost-effectiveness of $1.4 
million/dv using the maximum, and $0.9 million/dv using the cumulative 
improvement. These visibility improvements support the choice of SNCR 
as BART for NOX.

[[Page 9339]]



                Table 22--Nelson Lime Plant: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                                    Visibility      Visibility
                                                                                      impact        improvement
                          Class I area                             Distance (km) -------------------------------
                                                                                     Base case      SNCR (ctr1)
----------------------------------------------------------------------------------------------------------------
Bryce Canyon NP.................................................             235            0.20            0.06
Grand Canyon NP.................................................              24            1.79            0.58
Joshua Tree NP..................................................             238            0.23            0.02
Mazatzal WA.....................................................             206            0.15            0.01
Pine Mountain WA................................................             199            0.15            0.02
Sierra Ancha WA.................................................             289            0.11            0.01
Superstition WA.................................................             288            0.13            0.01
Sycamore Canyon WA..............................................             132            0.31            0.07
Zion NP.........................................................             183            0.28            0.08
Cumulative (sum)................................................  ..............            3.34            0.85
Maximum.........................................................  ..............            1.79            0.58
 CIAs >= 0.5 dv........................................  ..............            1               1
Million $/dv (cumul. dv)........................................  ..............  ..............           $0.9
Million $/dv (max. dv)..........................................  ..............  ..............           $1.4
----------------------------------------------------------------------------------------------------------------

c. Proposed BART Determination for NOX
    We propose to find that BART for NOX for Kilns 1 and 2 
is SNCR, and are proposing a BART emission limit for Kiln 1 of 3.80 lb/
ton lime and for Kiln 2 of 2.61 lb/ton lime on a 30-day rolling basis, 
as demonstrated through the use of a CEMS. We consider SNCR to be a 
very cost-effective control option for Kilns 1 and 2, at $817/ton and 
$807/ton, respectively. In addition, we consider the anticipated 
visibility benefit from SNCR, 0.58 dv at Grand Canyon National Park and 
0.85 cumulatively at all Class I areas within 300 km, to be 
substantial. In considering the other factors, we do not consider their 
impact substantial relative to the cost and visibility factors. We note 
that the remaining useful life of the source is reflected in the 
evaluation of cost of compliance through the use of a 20-year 
amortization period in control cost calculations. Since there is no 
existing NOX control technology in use on the kilns, 
baseline emissions reflect uncontrolled NOX emissions. In 
examining energy and non-air quality impacts, while we note certain 
impacts associated with SNCR, we do not consider these impacts 
sufficient to warrant its elimination as a control option.
    We propose to require compliance with this requirement within three 
years after the effective date of the final rule. A 2006 Institute of 
Clean Air Companies (ICAC) study indicated that the installation time 
for a typical SNCR retrofit, from bid to startup-up, is 10-13 
months.\83\ In relation to other industrial sources, such as fossil 
fuel boilers, there are a limited number of examples of SNCR 
installation on lime kilns. Given this relative lack of information 
regarding SNCR installation schedules on lime kilns, we consider three 
years to be an appropriate length of time to design, install, and test 
an ammonia injection system for a lime kiln. In addition, we are also 
proposing regulatory text that includes monitoring, reporting, and 
recordkeeping requirements associated with this emission limit. As part 
of the proposed monitoring requirements, we are including a requirement 
to monitor rates of ammonia injection in order to ensure proper 
operation of the SNCR in a manner that minimizes ammonia emissions.
---------------------------------------------------------------------------

    \83\ See ``Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources,'' Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

3. Proposed BART for SO2
    For our BART analysis, we identify all available control 
technologies, eliminate options that are not technically feasible, and 
evaluate the control effectiveness of the remaining control options. We 
then evaluate each control in terms of a five-factor BART analysis and 
make a determination for BART.
a. Control Technology Analysis for SO2
    EPA proposes to find that DSI and switching to lower sulfur fuel 
are technically feasible controls, while wet or semi-dry scrubbing is 
not technically feasible.
    Wet or Semi-Dry Scrubbing: We do not consider wet or dry scrubbing 
to be a feasible technology to control SO2 emissions for 
this source. Wet scrubbing involves passing flue gas downstream from 
the main particulate matter control device through a sprayed aqueous 
suspension of lime or limestone that is contained in a scrubbing 
device. The SO2 reacts with the scrubbing reagent to form 
lime sludge that is collected. The sludge usually is dewatered and 
disposed of at an offsite landfill. However, LNA has concluded, and we 
agree, that there is not sufficient water available for this type of 
system. According to LNA, two ground water wells supply about 106 
gallons per minute (gpm) to the Nelson Plant, which currently uses 
about 80 gpm. Therefore, only 26 gpm of water is available for a 
scrubbing system that, even for a semi-dry scrubbing system that has 
lower water requirements than wet scrubbing, would require about 117 
gpm. Moreover, a 1998 hydrologic report indicates that the prospects 
for developing additional wells, even low-yield wells, on the Nelson 
property are poor.\84\ After reviewing the hydrologic report and the 
vendor estimate of water requirements for a semi-dry scrubber, we agree 
with this assessment.
---------------------------------------------------------------------------

    \84\ See ``Results of Hydrogeologic Investigations for 
Development of Additional Water Supply, Chemical Lime Company, 
Nelson Plant, Yavapai County, AZ,'' July 8, 1998.
---------------------------------------------------------------------------

    Dry Sorbent Injection: DSI involves the injection of powdered 
absorbent directly into the flue gas exhaust stream. The sorbent reacts 
with SO2 in the exhaust to form solid particles that are 
then removed by a particulate matter control device downstream of the 
sorbent injection. DSI is a simple system that generally requires a 
sorbent storage tank, feeding mechanism, transfer line and blower, and 
an injection device. DSI is generally considered technically feasible 
for the cement industry, although the level of control effectiveness 
may vary based upon site-specific conditions. We consider this option 
technically feasible for lime kilns. LNA has not included information 
in its analysis indicating

[[Page 9340]]

that DSI would be infeasible for the Nelson Plant kilns.
    Lower Sulfur Fuel: The lower sulfur fuel option described by LNA 
involves changing the proportion of coal and petroleum coke used as a 
fuel blend. LNA currently uses a blend of 27 percent coal and 73 
percent petroleum coke, on a mass basis, as the fuel for the kilns. 
Since coke has about four to five times more sulfur than coal, it is 
possible to decrease the sulfur in the fuel blend by increasing the 
proportion of coal. However, an increase in coal in the fuel blend will 
also increase the ash content of the fuel blend. Ash in the fuel can 
disrupt operations due to the buildup of ash rings in the kilns. A fuel 
blend with an ash content of about 6.5 percent or less must be used in 
order to avoid these operational challenges.
    As noted in fuel usage and purchase records, the Nelson Plant 
currently operates on a coal and petroleum coke mixture. As a result, 
we consider adjusting the coal/coke ratio in the fuel mixture to be a 
technically feasible option. We note, however, that since the BART 
Guidelines do not require fuel supply changes to be considered as a 
control option, we have typically not considered changes in fuel in 
BART analyses.\85\ However, because LNA included lower sulfur fuel in 
its analysis, we have retained it as a control option.
---------------------------------------------------------------------------

    \85\ 40 CFR Part 51, Appendix Y, Section IV.D.1.5, ``STEP 1: How 
do I identify all available retrofit emission control techniques?''
---------------------------------------------------------------------------

b. BART Analysis for SO2
    EPA conducted a five-factor BART analysis of the two technically 
feasible control options, DSI and lower sulfur fuel, to evaluate the 
cost-effectiveness and visibility benefit of each option along with any 
effect on the other factors.
    Cost of Compliance: Our consideration of the cost of compliance 
focuses primarily on the cost-effectiveness of each control option as 
measured in cost per ton and incremental cost per ton. We estimate the 
SO2 emissions rates for DSI and lower sulfur fuel as shown 
in Table 23, and the cost-effectiveness of these options as shown in 
Table 24. DSI has a control efficiency of 40 percent that results in 
about 1,588 tpy of SO2 removed from both kilns. Lower sulfur 
fuel has a control efficiency of 23.3 percent that results in about 925 
tpy of SO2 removed from both kilns. Based on the total 
annual costs of controlling SO2 emissions at both kilns, DSI 
would cost an average of about $4,200 per ton removed and lower sulfur 
fuel about $860 per ton removed. Since there is no existing 
SO2 control technology in use in the plant, baseline 
emissions reflect uncontrolled SO2 emissions.
    While we consider it appropriate to use 40 percent control 
efficiency \86\ for DSI, we are inviting comment on the control 
effectiveness of 23.3 percent for a lower sulfur fuel blend based on 
the ratio of coal (1.15 percent sulfur) to petroleum coke (5.64 percent 
sulfur). LNA estimates that the maximum coal-to-coke ratio to maintain 
overall fuel ash content below 6.5 percent is a 50 percent coal to 50 
percent coke fuel mixture. A 50/50 mix corresponds to a fuel sulfur 
reduction of 1.13 percentage points, which represents a 23.3 percent 
reduction from the current fuel mixture. Based on a review of coal and 
coke properties along with historical fuel usage at the Nelson Plant, 
we agree with the use of a 50/50 coal-to-coke ratio and 23.3 percent 
control effectiveness. However, LNA cites operational issues with fuel 
ash content above 6.5 percent. Since ash is a contaminant that can 
adversely affect lime product quality, we are seeking comment regarding 
the extent to which it is appropriate to use fuel ash content of 6.5 
percent as the upper bound for determining fuel mixture ratio. We may 
finalize a different fuel mixture ratio based upon the comments we 
receive.
---------------------------------------------------------------------------

    \86\ While the control efficiency for DSI is much higher for 
cement kilns, LNA conducted onsite testing of DSI on the lime kilns 
at the Nelson Plant that demonstrated it is appropriate to use 40 
percent control efficiency. The docket includes a comparison of 
LNA's tests of DSI to the analysis in our contractor's report.
---------------------------------------------------------------------------

    In estimating the costs of compliance, LNA relied on a vendor quote 
for purchased equipment provided by Noltech dated May 22, 2013, with 
the remainder of the capital costs calculated using the cost 
methodology contained in EPA's Control Cost Manual.\87\ While these 
capital costs are higher than those estimated by our contractor, we 
consider the use of the Noltech vendor quote for the Nelson Plant 
reasonable, and have incorporated it into our evaluation of the costs 
of compliance. With regard to annual operating & maintenance costs, LNA 
has asserted a confidential business information (CBI) claim regarding 
certain annual operating costs such as reagent usage. As a result, we 
have prepared our own independent estimate of annual operating costs 
based upon a combination of publicly available data and certain 
assumptions as described in the contractor's report. Detailed cost 
calculations can be found in the docket.\88\
---------------------------------------------------------------------------

    \87\ Vendor quote included as an attachment to BART Five Factor 
Analysis, Lhoist North America Nelson Lime Plant; (Public version 
dated September 27, 2013).
    \88\ See spreadsheet ``Nelson Control Costs 2013-10-24.xlsx'' in 
the docket.

                       Table 23--Nelson Lime Plant: SO2 Control Option Emission Estimates
----------------------------------------------------------------------------------------------------------------
                                                   Control      Emission     Maximum emission rate
             SO2 control technology               efficiency  factor (lb/ --------------------------   Removed
                                                     (%)       ton lime)      lb/day        Tpy         (tpy)
----------------------------------------------------------------------------------------------------------------
Kiln 1:
    Baseline...................................  ...........        12.15       10,526        1,571  ...........
    Lower Sulfur Fuel Blend....................        23.30         9.32        8,073        1,205          366
    Dry Sorbent Injection......................           40         7.29        6,316          943          628
Kiln 2:
    Baseline...................................  ...........        12.69       15,808        2,400  ...........
    Lower Sulfur Fuel Blend....................        23.30         9.73       12,125        1,841          559
    Dry Sorbent Injection......................           40         7.61        9,485        1,440          960
----------------------------------------------------------------------------------------------------------------


[[Page 9341]]


                                           Table 24--Nelson Lime Plant: SO2 Control Option Cost-Effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Capital       Annual       Annual       Total       Emission    Cost-effectiveness  ($/
                                                                   cost        direct      indirect   annual cost   reduction             ton)
                    SO2 control technology                    -------------    costs        costs    ---------------------------------------------------
                                                                           --------------------------
                                                                   ($)         ($/yr)       ($/yr)       ($/yr)       (tpy)       Average    Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
Kiln 1:
    Lower Sulfur Fuel Blend..................................  ...........  ...........  ...........     $313,096          366         $856  ...........
    Dry Sorbent Injection....................................   $2,497,559     $371,174   $2,621,832    2,621,832          628        4,174       $8,803
Kiln 2:
    Lower Sulfur Fuel Blend..................................  ...........  ...........  ...........      458,179          559          819  ...........
    Dry Sorbent Injection....................................    2,497,559      371,174    3,895,774    3,895,774          960        4,058        8,576
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Pollution Control Equipment in use at the Source: The presence of 
existing pollution control technology at the Nelson Plant is reflected 
in the BART analysis in two ways: first, in the consideration of 
available control technologies, and second, in the development of 
baseline emission rates for use in cost calculations and visibility 
modeling. In the case of SO2, the kilns at the Nelson Plant 
do not operate with any existing control technology. This is reflected 
in the baseline emission rates, which represent uncontrolled 
SO2 emissions.
    Energy and non-air quality environmental impacts: Regarding the 
first option, DSI systems require electricity for operation. The 
generation of the electricity needed to operate a DSI system will 
likely involve fuel combustion that will generate emissions. Emissions 
also are associated with the transport, handling, and storage of 
sorbent. Overall, while the use of DSI will cause emissions from select 
activities, the emissions should be low compared to the reduction in 
SO2 that would be gained by operating a DSI system. 
Regarding the second option, using a lower sulfur fuel blend means LNA 
will obtain more of the energy for lime production from coal and less 
of the energy from coke. Since the heating value of coke is slightly 
higher than the heating value of coal, it is likely that LNA will burn 
more total mass of fuel as a result of substituting some coal for coke. 
While burning a lower sulfur fuel blend will likely result in a 
reduction in SO2 emissions, it will involve the overall use 
of greater quantities of coal, which may result in a collateral 
increase of other pollutants such as NOX and CO.
    Remaining Useful Life of the Source: We are considering the 
``remaining useful life'' of the kilns as one element of the overall 
cost analysis as allowed by the BART Guidelines. In the absence of any 
enforceable closure date, we have used a 20-year amortization period 
described in the EPA Cost Control Manual as the remaining useful life 
for the control options considered for the Nelson Plant kilns. Since 
there is no capital costs associated with using a lower sulfur fuel 
blend, the remaining useful life of the kilns is not a factor in the 
evaluation of this technology.
    Degree of Visibility Improvement: As was the case for 
NOX, EPA post-processed LNA's modeling results for 
SO2 controls. The greatest improvement from DSI is 0.2 dv, 
occurring at the Grand Canyon, with improvements at other areas a third 
or less than this. The cumulative improvement is 0.6 dv. The maximum 
and cumulative improvements from switching to lower sulfur fuel are 
roughly half of these amounts. While visibility improvement by itself 
could support either DSI or lower sulfur fuel as BART, lower sulfur 
fuel is favored by its much lower average cost-effectiveness at $819-
856/ton compared to over $4000 for DSI. Baseline and control option 
emission rates used in SO2 control scenario modeling are 
summarized in Table 25 with the modeling results in Table 26.\89\
---------------------------------------------------------------------------

    \89\ These results are from EPA's post-processing of LNA's 
modeling. See the TSD for a discussion of the differences between 
EPA's results and the results reported by LNA in their BART 
analysis.

                          Table 25--Nelson Lime Plant: SO2 Control Model Emission Rates
----------------------------------------------------------------------------------------------------------------
                                                   Control      Emission     Maximum 24-hr model emission rate
                                                  efficiency     factor   --------------------------------------
             SO2 control technology             --------------------------
                                                      %       lb/ton lime     lb/day       lb/hr         g/s
----------------------------------------------------------------------------------------------------------------
Kiln 1:
    Baseline...................................  ...........        12.15       10,526          439           55
    Lower Sulfur Fuel Blend....................        23.30         9.32        8,073          336           42
    Dry Sorbent Injection (SBC)................           40         7.29        6,315          263           33
Kiln 2:
    Baseline...................................  ...........        12.69       15,808          659           83
    Lower Sulfur Fuel Blend....................        23.30         9.73       12,125          505           64
    Dry Sorbent Injection (SBC)................           40         7.61        9,489          395           50
----------------------------------------------------------------------------------------------------------------


                   Table 26--Nelson Lime Plant: SO2 Control Option Visibility Modeling Results
----------------------------------------------------------------------------------------------------------------
                                                                          Visibility    Visibility  improvement
                                                              Distance      impact    --------------------------
                       Class I area                             (km)    --------------                Low-S fuel
                                                                           Base case    DSI (ctr2)      (ctr3)
----------------------------------------------------------------------------------------------------------------
Bryce Canyon NP...........................................          235          0.20          0.03         0.02

[[Page 9342]]

 
Grand Canyon NP...........................................           24          1.79          0.21         0.10
Joshua Tree NP............................................          238          0.23          0.07         0.04
Mazatzal WA...............................................          206          0.15          0.04         0.02
Pine Mountain WA..........................................          199          0.15          0.04         0.02
Sierra Ancha WA...........................................          289          0.11          0.04         0.02
Superstition WA...........................................          288          0.13          0.04         0.02
Sycamore Canyon WA........................................          132          0.31          0.06         0.04
Zion NP...................................................          183          0.28          0.04         0.02
Cumulative (sum)..........................................  ...........          3.34          0.57         0.29
Maximum...................................................  ...........          1.79          0.21         0.10
 CIAs >= 0.5 dv..................................  ...........          1             0               0
Million $/dv (cumul. dv)..................................  ...........  ............        $11.5          $2.6
Million $/dv (max. dv)....................................  ...........  ............        $30.7          $8.1
----------------------------------------------------------------------------------------------------------------

c. Proposed BART Determination for SO2
    We propose to find that BART for SO2 is the use of a 
lower sulfur fuel blend with an emission limit of 9.32 lb/ton for Kiln 
1 and 9.73 lb/ton for Kiln 2 \90\ on a rolling 30-day basis. In 
evaluating the costs of compliance, we note that we consider DSI and 
lower sulfur fuel to both be cost-effective control options, with 
average cost-effectiveness values of approximately $800/ton and $4,000/
ton, respectively. In evaluating anticipated visibility benefit, while 
DSI is anticipated to achieve the greatest visibility improvement (0.21 
dv at Grand Canyon), this amount of visibility improvement is not 
large, nor is the benefit anticipated for the next most stringent 
control option, lower sulfur fuel (0.10 dv at Grand Canyon). In 
considering the other factors, there is no significant effect on the 
outcome of the cost and visibility analyses. The lack of existing 
control technology is reflected in the baseline in the form of 
uncontrolled SO2 emissions. In examining energy and non-air 
quality impacts, we note that there may be certain collateral increases 
in emissions, but that these increases are outweighed by the emission 
reductions achieved by implementing the control technology and do not 
warrant their elimination. The remaining useful life of the source is 
reflected in the evaluation of the cost of compliance. We consider both 
DSI and use of lower sulfur fuel to be cost-effective, but note that 
the most stringent option, DSI, is considerably less cost-effective 
than the use of lower sulfur fuel, with an incremental cost-
effectiveness, relative to lower sulfur fuel, of approximately $9,000/
ton. As a result, although DSI is the most stringent control option, 
the visibility benefit it achieves is not large, and is achieved at a 
very high incremental cost relative to the next most stringent control 
option. Based on this information, we propose to find that BART for 
SO2 is the use of a lower sulfur fuel blend.
---------------------------------------------------------------------------

    \90\ The differing emission limits are due to the different 
baseline performance of the two kilns.
---------------------------------------------------------------------------

4. Proposed BART for PM10
    For our BART analysis, we identified fabric filter baghouses, the 
existing control technology for PM10 on Kilns 1 and 2, as 
the most stringent control available for this type of source.
a. Control Technology Analysis for PM10
    The Nelson Plant, as a major source of hazardous air pollutants 
(HAPs), is subject to the Maximum Achievable Control Technology (MACT) 
Standard for Lime Manufacturing Plants, and is required to meet an 
emission limit of 0.12 lbs PM/TSF (ton of stone feed).\91\ The BART 
Guidelines provide that unless there are new technologies subsequent to 
the MACT standards that would lead to cost-effective increases in the 
level of control, one may rely on the MACT standards for purposes of 
BART.\92\ Based on information developed as part of the Lime MACT, we 
estimate that existing fabric filter upgrades would result in annual 
costs of $94,500.\93\ As noted in LNA's BART analysis, baseline PM 
emissions for the two kilns, based on PM filterable stack test data and 
annual lime production, are approximately 8 tpy and 15 tpy.\94\ This 
would result in an average cost-effectiveness of about $6,300 to 
$12,000/ton.
---------------------------------------------------------------------------

    \91\ 40 CFR Part 63, Subpart AAAAA, Table 1, Item 1 for existing 
lime kilns with no wet scrubber prior to 2005.
    \92\ 40 CFR Part 51, Appendix Y, Section IV.C.
    \93\ Annual costs as described in the Economic Impact Analysis 
for the Lime Manufacturing MACT Standard (EPA-452/R-03-013), Table 
3-2, Model Kiln F. Adjusted from 1997 to 2013 dollars using the 
consumer price index, available at ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt.
    \94\ As described in the LNA Nelson BART Analysis, Table 4-5.
---------------------------------------------------------------------------

b. BART Analysis for PM10
    The BART Guidelines provide that, in instances where a source 
already has the most stringent controls available (including all 
possible improvements), it is not necessary to complete each step of 
the BART analysis. Further, as long as the most stringent controls 
available are made federally enforceable for the purpose of 
implementing BART for that source, one may skip the remainder of the 
analysis, including the visibility analysis.\95\
---------------------------------------------------------------------------

    \95\ 40 CFR Part 51, Appendix Y, Section IV.D.9.
---------------------------------------------------------------------------

c. Proposed BART Determination for PM10
    We propose a BART emission limit of 0.12 lb/TSF to control 
PM10 at Kilns 1 and 2 based on the use of the existing 
fabric filter baghouses and commensurate with the MACT standard that 
applies to this source. We seek comment on any cost-effective upgrades 
or improvements that may result in a lower emission limit. We propose 
to require compliance with this requirement within 6 months after the 
effective date of the final rule. We also propose regulatory text that 
includes monitoring, reporting, and recordkeeping requirements 
associated with this emission limit that is found at the end of this 
notice.

 C. Hayden Smelter

    Summary: EPA proposes to find that the ASARCO Hayden Smelter is 
subject to BART for NOX in addition to SO2 as

[[Page 9343]]

determined by the State. ASARCO must capture and control SO2 
emissions from the converter units that are subject to BART. In the 
current method of operation, thousands of tons of SO2 from 
these units are vented to the atmosphere with no pollution control. One 
method to control SO2 emissions from the converter units is 
to install and operate a second double contact acid plant with a 
control efficiency of about 99.8 percent on a 30-day rolling average. 
We estimate the annual cost of constructing and operating a second acid 
plant to control SO2 emissions is about $872 per ton of 
SO2 removed. While we consider the cost of a new acid plant 
to be reasonable, we are proposing a performance standard as BART 
rather than prescribing a particular method of control. For 
NOX, we propose to set an annual emission limit of 40 tpy 
from the BART-eligible units, based on our proposed determination that 
no NOX controls are needed for BART at the Hayden Smelter. 
Finally, we are proposing an emission limit and associated compliance 
requirements for PM10.
    Affected Class I Areas: Twelve Class I areas are within 300 km of 
the Hayden Smelter. Their nearest borders range from 48 km to 239 km 
away. Galiuro WA and Superstition WA are the closest, followed by 
Saguaro NP and Sierra Ancha WA. The highest baseline 98th percentile 
visibility impact is 1.7 dv at Superstition, with impacts at Galiuro 
slightly lower. Baseline visibility impacts at each of the twelve areas 
exceed 0.5 dv. The cumulative sum of visibility impacts over all the 
Class I areas is 12.1 dv.
    Facility Overview: ASARCO Hayden Smelter is a batch-process copper 
smelter in Gila County, Arizona. We previously approved ADEQ's 
determination that converters 1, 3, 4 and 5 and Anode Furnaces 1 and 2 
at the facility are BART-eligible.\96\ We also approved ADEQ's 
determination that these units are subject to BART for SO2 
and that BART for PM10 at ASARCO Hayden is no additional 
controls. However, we disapproved ADEQ's determination that existing 
controls constitute BART for SO2 and that the units are not 
subject to BART for NOX. In light of these disapprovals and 
our FIP duty for regional haze in Arizona, we are required to 
promulgate a FIP to address BART for SO2 and NOX.
---------------------------------------------------------------------------

    \96\ 78 FR 46412 (July 30, 2013). Please refer to the TSD for a 
description of these units.
---------------------------------------------------------------------------

    Baseline Emissions Calculations: Since neither ASARCO nor ADEQ 
identified baseline emissions for the Hayden Smelter, we calculated 
baseline emissions for SO2 and NOX. For 
SO2, we used as the baseline the average of the two highest 
emitting years from the last five years that ASARCO reported to ADEQ. 
For NOX, we estimated emission rates based on the rated 
natural gas capacity of the burners in the four subject-to-BART 
converters and the two anode furnaces.\97\ As indicated in Table 27, 
the majority of the source's SO2 emissions (20,341 tpy of a 
total of 22,621 tpy) are process emissions from the converters. These 
process SO2 emissions are collected through a secondary 
capture system, but are emitted uncontrolled through an annular stack 
that bypasses the existing double contact acid plant. While our BART 
analysis focuses on these uncontrolled SO2 emissions from 
the converters, we also evaluated improved control of the 
SO2 emissions from the existing acid plant and from the 
anode furnaces as well as controlling NOX emissions from all 
the BART units.
---------------------------------------------------------------------------

    \97\ ASARCO Hayden Title V permit.

                                Table 27--Hayden Smelter: BART Baseline Emissions
                                                 [Tons per year]
----------------------------------------------------------------------------------------------------------------
                                                              Converters
                                              -----------------------------------------
                                                 Existing      Annular                     Anode
                                                acid plant      stack                     furnaces      Total
                                                 (primary    (secondary    Uncaptured
                                                 capture)     capture)
----------------------------------------------------------------------------------------------------------------
SO2..........................................        1,034     20,341         1,209              37       22,621
                                              ------------------------------------------------------------------
NOX..........................................                     31                             19           50
----------------------------------------------------------------------------------------------------------------

    Modeling Overview: EPA is relying on modeled baseline and post-
control impacts of the ASARCO Hayden Smelter using stack parameters 
provided by ASARCO in response to a 2013 EPA information request.\98\ 
We also modeled using stack parameters based on a 2012 stack test.\99\ 
Stack exit temperatures were comparable for these two models, but the 
exit velocities from the 2012 stack test were far lower than those 
provided by ASARCO in 2013. The 2012 stack test parameters resulted in 
visibility impacts and control benefits about 10 percent higher than 
the model using the 2013 parameters. We are conservatively using the 
2013 ASARCO parameters to evaluate controls, since using the 2012 
parameters would yield even greater visibility improvements. For both 
sets of modeling runs, EPA used emission rates that were developed 
using information provided by ASARCO.
---------------------------------------------------------------------------

    \98\ Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 
11, 2013; attached Memorandum from Ralph Morris and Lynsey Parker, 
ENVIRON, to Eric Hiser, Jorden, Bischoff and Hiser, PLC, March 4, 
2013.
    \99\ ASARCO Hayden CEMS Test Report, Energy and Environmental 
Measurement Corporation, Test date: September, 2012.
---------------------------------------------------------------------------

 1. BART Analysis and Determination for SO2 From Converters
a. Control Technology Availability, Technical Feasibility and 
Effectiveness
    EPA identified two available technology options to control the 
20,341 tons of SO2 emissions from the annular stack that are 
captured by a secondary collection system, but are released 
uncontrolled through the annular stack. These options are to construct 
and operate a second double contact acid plant or install a wet 
scrubber on the annular portion of the existing stack. In addition, we 
found that ASARCO could add a tail stack scrubber to the existing acid 
plant to address the remaining emissions that are not converted and 
removed as sulfuric acid by the acid plant. Regarding technical 
feasibility, we note that ASARCO Hayden currently uses a double contact 
acid plant to control SO2 emissions captured by the primary 
capture system. Wet scrubbing also is commonly used in many industries 
to control SO2. Thus, we find

[[Page 9344]]

that the double contact acid plant and wet scrubbing are technically 
feasible. In terms of control effectiveness, ASARCO indicated in a 
letter \100\ to EPA that its double contact acid plant is capable of 
recovering 99.8 percent of the SO2 vented to it.\101\ In the 
same letter, ASARCO noted that the expected control effectiveness of 
wet scrubbing is 85 percent. We used these removal efficiencies in our 
five-factor analyses. These analyses are explained in the TSD and 
summarized below.
---------------------------------------------------------------------------

    \100\ Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 
11, 2013.
    \101\ Ibid.
---------------------------------------------------------------------------

b. Option 1: Double Contact Acid Plant for Secondary Capture
    Cost of Compliance: EPA determined the cost-effectiveness of a new 
double contact acid plant is $872 per ton of SO2 removed as 
shown in Table 28. As explained in the TSD, we conservatively estimated 
the cost of construction of a double contact acid plant to be 
$81,621,297. The annualized capital costs are based on a 20-year 
lifespan and a seven percent interest rate. We applied a control 
efficiency of 99.8 percent, which the existing acid plant is currently 
achieving with limited cesium catalyst. The emission reduction was 
applied to the secondary capture system baseline emissions. This cost 
analysis does not include the offsetting value of any sulfuric acid 
produced and sold. It does assume full catalyst replacement every other 
year and air preheating with natural gas for 8,760 hours per year.

                                           Table 28--Hayden Smelter Option 1: Second Double Contact Acid Plant
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized         Annual        Total annual       Tons SO2         Control         $/ton SO2
                   Capital cost                       capital cost    variable cost         cost           reduced         efficiency        removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$81,621,297.......................................      $7,704,573      $10,006,010      $17,710,483           20,341            99.8%             $872
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: Controlling 
secondary capture with a sulfuric acid plant at the Hayden Smelter 
would require energy to heat inlet air from approximately 
177[emsp14][deg]F to 735[emsp14][deg]F. This would require a heat input 
of approximately 114 MMBtu/hour and could require 1,200 MMscf of 
natural gas per year, resulting in up to 30 tpy of NOX 
emissions.\102\ This assumes 100 percent of the needed heat results 
from natural gas combustion. Non-air quality impacts from a second acid 
plant are not expected to be significant given that ASARCO already has 
the capacity to handle and store the much larger quantities of sulfuric 
acid produced by the primary acid plant.
---------------------------------------------------------------------------

    \102\ This is based on the AP 42 factor for low-NOX 
burners.
---------------------------------------------------------------------------

    Pollution Control Equipment in Use at the Source: As noted above 
and further described in the TSD, a portion of the emissions from the 
converters are controlled by a gas cleaning plant to remove particulate 
matter and a double contact sulfuric acid plant that converts 
SO2 to sulfuric acid. We considered these controls as part 
of our analysis of available control technologies and in developing 
baseline emission rates for use in cost calculations and visibility 
modeling.
    Remaining Useful Life of the Source: The BART-eligible converters 
have each been in place for about 40 years or longer. ASARCO has not 
indicated that any of the converters would need to be replaced during 
the 20-year capital cost recovery period.
    Degree of Visibility Improvement: Controlling SO2 
emissions through a second double contact acid plant at a 98.8 percent 
efficiency results in visibility improvement in 12 Class I areas in 
Arizona and New Mexico as indicated in Table 29. Based on air quality 
modeling, visibility improvement from controlling SO2 by 
constructing a new acid plant to control converter emissions from the 
secondary capture system is 1.5 dv at Superstition, and nearly the same 
at Galiuro. Eleven of the Class I areas improve by at least 0.5 dv. The 
cumulative improvement is 10.3 dv. The large visibility improvement at 
many Class I Areas supports the choice of a new acid plant as BART for 
SO2.

  Table 29--Hayden Smelter Option 1: Visibility Impact and Improvement
                            From SO2 Controls
------------------------------------------------------------------------
                                                             Visibility
                                               Visibility    improvement
          Class I area             Distance    impact base    new acid
                                     (km)     case  (base)      plant
                                                               (ctrl2)
------------------------------------------------------------------------
Chiricahua NM..................          170          1.05          0.89
Chiricahua WA..................          174          1.01          0.87
Galiuro WA.....................           48          1.73          1.45
Gila WA........................          186          0.69          0.60
Mazatzal WA....................          121          0.88          0.75
Mount Baldy WA.................          151          0.66          0.56
Petrified Forest NP............          215          0.70          0.61
Pine Mountain WA...............          168          0.67          0.57
Saguaro NP.....................           82          1.38          1.18
Sierra Ancha WA................           84          1.09          0.93
Superstition WA................           50          1.74          1.47
Sycamore Canyon WA.............          239          0.51          0.44
Cumulative (sum)...............  ...........         12.10         10.32
Maximum........................  ...........          1.74          1.47
 CIAs >= 0.5 dv.......  ...........         12            11
Million $/dv (cumul. dv).......  ...........  ............         $1.7
Million $/dv (max. dv).........  ...........  ............        $12.1
------------------------------------------------------------------------


[[Page 9345]]

c. Option 2: Wet Scrubber on Existing Stack for Secondary Capture
    Cost of Compliance: EPA determined that the annual cost of using a 
wet scrubber to control SO2 emissions from the secondary 
capture system is $972 per ton of SO2 removed as displayed 
in Table 30. We calculated the costs of constructing and operating a 
wet scrubber based on information provided in ASARCO's letter \103\ 
from which we used the highest operating cost estimates to demonstrate 
cost-effectiveness. We also included a sludge hauling fee of $60 per 
ton and assumed one ton of SO2 controlled would result in 
five tons of sludge. According to ASARCO, these costs do not include 
the cost of a booster fan or a modified stack that may be needed, 
thereby somewhat increasing the cost over what is shown here. Although 
the calculation includes the cost of hauling sludge off site, it does 
not include the cost of treating or landfilling the sludge.
---------------------------------------------------------------------------

    \103\ Letter from Jack Garrity, ASARCO to Thomas Webb, EPA (July 
11, 2013).

                                            Table 30--Hayden Smelter Option 2: Wet Scrubber on Existing Stack
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized    Annual variable    Total annual       Tons SO2         Control         $/ton SO2
                   Capital cost                       capital cost         cost             cost           reduced         efficiency        removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$28,000,000.......................................      $2,643,002      $14,186,965      $16,829,967           17,290              85%             $972
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: Operation of a 
wet scrubber would likely require operation of a booster fan and a gas 
re-heater to force emissions through the 305 meter stack. The addition 
of a wet scrubber could result in a detached visible plume as water 
vapor emitted from the scrubber condenses. Addition of a scrubber would 
result in sludge which would have to be shipped off site to be treated 
or landfilled. Because of metals in the sludge, it may need to be 
treated as hazardous waste.
    Pollution Control Equipment in Use at the Source: This is the same 
as for Option 1.
    Remaining Useful Life of the Source: This is the same as for Option 
1.
    Degree of Visibility Improvement: We did not conduct visibility 
modeling for this option. Because a scrubber is less efficient at 
removing SO2 than a second acid plant, the emission rates 
would be higher and there would be less visibility improvement from a 
scrubber compared to an acid plant. Given that scrubbers are less cost-
effective than a second acid plant, we deemed it unnecessary to model 
impacts.
d. Option 3: Wet Scrubber on Acid Tail Stack for Primary Capture
    Cost of Compliance: EPA determined the annual cost of using a wet 
scrubber to control SO2 emissions from the existing acid 
plant tail stack is $13,564 per ton of SO2 removed as 
displayed in Table 31. We calculated the costs of constructing and 
operating a wet scrubber based on information provided by ASARCO.\104\ 
In this case, we used the low-end estimate of operating costs because 
we are demonstrating that this option is not cost-effective. We also 
included a sludge hauling fee of $60 per ton and assumed one ton of 
SO2 controlled would result in five tons of sludge. Again, 
these costs did not include the cost of a booster fan or a modified 
stack that may be needed. Although the calculation included the cost of 
hauling sludge off site, it did not include the cost of treating or 
disposing the sludge, which may be classified as hazardous waste 
depending on the metals content. In addition, we note that some of the 
SO2 that passes through the acid plant is emitted by the 
flash furnace that is not BART-eligible.
---------------------------------------------------------------------------

    \104\ Ibid.

                                           Table 31--Hayden Smelter Option 3: Wet Scrubber on Acid Tail Stack
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized    Annual variable    Total annual       Control          Tons SO2        $/ton SO2
                   Capital cost                       capital cost         cost             cost          efficiency        reduced          removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$28,000,000.......................................      $2,643,002       $9,274,521      $11,917,523              85%              879          $13,564
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: This is the same 
as for Option 2.
    Pollution Control Equipment in Use at the Source: This is the same 
as for Options 1 and 2.
    Remaining Useful Life of the Source: This is the same as for 
Options 1 and 2.
    Degree of Visibility Improvement: We did not conduct visibility 
modeling for a tail stack scrubber because of the high control cost per 
ton of SO2. However, because the scrubber would remove much 
less SO2 than options 1 or 2 (second acid plant and wet 
scrubber on the secondary capture, respectively), the expected 
visibility improvement is far less than for options 1 and 2.
e. Proposed BART Determination for SO2 From Converters
    Based on the results of our BART analysis, we propose that BART for 
SO2 from the converters is a level of control consistent 
with what ASARCO could achieve through the installation of a new double 
contact acid plant. This would control about 20,341 tpy of 
SO2 emissions from the converter units at a cost of about 
$872 per ton of SO2 removed, which we consider highly cost-
effective. The expected visibility benefits of this option are 
substantial with a greater than 0.5 dv improvement in eleven Class I 
areas with a maximum benefit of 1.47 dv at Superstition WA. We propose 
to find that the energy and non-air quality environmental effects of 
this option are not sufficient to warrant elimination of this option.
    Regarding the other options, a wet scrubber for the secondary 
capture (Option 2) is less effective at a similar annual cost but with 
greater non-air environmental impacts. Therefore, we do not propose to 
require this as BART. Adding a scrubber to the existing acid tail stack 
for the primary capture (Option 3) would result in a relatively small 
amount of additional emissions reductions at a relatively high cost 
($13,564 per ton of SO2 removed) and with potentially 
significant non-air environmental impacts. Therefore, we propose that 
the addition of a scrubber

[[Page 9346]]

to the existing acid plant is not required as BART.
    The specifics of our BART proposal for SO2 from the 
converters are as follows:
     An SO2 control efficiency of 99.8 percent, 30-
day rolling average, on all SO2 captured by the primary and 
secondary control systems. The control efficiency may be averaged 
between the two capture systems on a mass basis, if needed. (For every 
30-day period the total mass of SO2 exiting the two control 
systems must be no greater than 0.0019 percent of the SO2 
entering the control systems.)
     Compliance with the SO2 BART limit may be 
verified either through the use of SO2 CEMS before and after 
controls in each system or by using post-control CEMS and acid 
production rates. A limit of 2.49 lbs SO2 emissions per tons 
of sulfuric acid production is equivalent to 99.8 percent control.
     Operation and maintenance of primary and secondary capture 
systems meeting the requirements of 40 CFR part 63, subpart QQQ.
    We propose to require that these requirements be met within 3 years 
of promulgation of the final rule, consistent with the requirement of 
the CAA and the RHR that BART be installed ``as expeditiously as 
practicable.''
2. BART Analysis and Determination for SO2 From Anode 
Furnaces
a. BART Analysis for SO2 From Anode Furnaces
    We identified the same two control technologies for the anode 
furnaces: a new double contact acid plant and a wet scrubber. In 
addition, we considered whether emissions from the anode furnaces might 
be vented to the existing acid plant.
    Cost of Compliance: Based on our calculations, we estimated that 
the cost to control 37 tpy of SO2 from the anode furnaces by 
construction of a new acid plant is over $28,000 per ton, not including 
the cost of inlet preheating,\105\ as shown in Table 32. The estimated 
cost of installing and operating a wet scrubber is even more expensive 
at over $80,000 per ton\106\ as shown in Table 33.
---------------------------------------------------------------------------

    \105\ See the TSD for further discussion of this issue.
    \106\ See the TSD, Section III.D.4.

                                             Table 32--Hayden Smelter: New Acid Plant for the Anode Furnaces
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized         Annual        Total annual       Tons SO2         Control         $/ton SO2
                   Capital cost                       capital cost    variable cost         cost           reduced         efficiency        removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$8,583,190........................................        $810,192         $261,827       $1,071,920               37            99.8%          $28,616
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                            Table 33--Hayden Smelter: New Wet Scrubber for the Anode Furnaces
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized         Annual        Total annual       Tons SO2         Control         $/ton SO2
                   Capital cost                       capital cost    variable cost         cost           reduced         efficiency        removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$7,000,000........................................        $660,750       $2,009,570       $2,670,320               32              85%          $83,708
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: This is the same 
as for the converters.
    Pollution Control Equipment in Use at the Source: The anode 
furnaces currently have no SO2 controls in place.
    Remaining Useful Life of the Source: ASARCO has not indicated that 
any of the anode furnaces would need to be replaced during the 20-year 
capital cost recovery period.
    Degree of Visibility Improvement: We did not conduct visibility 
modeling for the anode furnace emissions. However, since the emissions 
from these units are a small fraction of those from the converters, the 
expected visibility improvement would be far less than for any of the 
controls considered for the converters.
b. Proposed BART Determination for SO2 From Anode Furnaces
    Given the high cost of control, and the small potential for 
visibility improvement, we propose that controlling the 37 tpy of 
SO2 emissions from the anode furnaces is not warranted as 
BART. Furthermore, while redirecting the anode furnace emissions to the 
existing acid plant might be technically feasible and cost-effective, 
the emission reductions and visibility benefit, although not 
calculated, would be much smaller than the calculated benefits from 
controlling additional emissions from the converters.
    In order to ensure that emissions from anode furnaces do not 
increase substantially in the future, we are proposing to establish a 
work practice standard for these units. While BART determinations are 
generally promulgated in the form of numeric emission limitations, the 
RHR allows for use of equipment requirements or work practice standards 
in lieu of a numeric limit where ``technological or economic 
limitations on the applicability of measurement methodology to a 
particular source would make the imposition of an emission standard 
infeasible.''\107\ In this case, we find that a numerical emission 
limitation for the anode furnaces would be infeasible because of the 
relatively small amount of emissions from these units, compared with 
the converters. Therefore, we are proposing to establish a work 
practice standard in the form of a requirement that the anode furnaces 
be charged with blister copper or higher purity copper. Because blister 
copper is generally 98 to 99 percent pure copper, this requirement will 
ensure that sulfur emission from the anode furnaces are minimized.
---------------------------------------------------------------------------

    \107\ 40 CFR 51.308(e)(1)(iii). See also 40 CFR 51.100(z) 
(defining ``emission limitation'' and ``emission standard'' to 
include ``any requirements which . . . prescribe equipment . . . for 
a source to assure continuous emission reduction.''
---------------------------------------------------------------------------

 3. Subject-to-BART, BART Analysis and BART Determination for 
NOX
a. Proposed Subject-to-BART Finding for NOX
    As explained in our final rule on the Arizona RH SIP, once a source 
is determined to be subject to BART, the RHR allows for the exemption 
of a specific pollutant from a BART analysis only if the potential to 
emit for that pollutant is below a specified de minimis level.\108\ 
Neither the Hayden Smelter's current Title V permit nor the Arizona RH 
SIP contains any physical or operational limitations that would limit 
the PTE of the BART-eligible

[[Page 9347]]

source below the NOX de minimis threshold of 40 tpy. 
Therefore, because the Hayden Smelter is subject to BART and has a PTE 
of more than 40 tons per year of NOX, we have analyzed 
potential NOX BART controls for the source.
---------------------------------------------------------------------------

    \108\ 40 CFR 51.308(e)(1)(ii)(C).
---------------------------------------------------------------------------

b. BART Analysis for NOX
    The Hayden Smelter's NOX emissions result from the 
combustion of natural gas to heat process equipment. LNB are an 
available, feasible and effective technical option for such process 
heaters, with an estimated control efficiency of 50 percent.\109\
---------------------------------------------------------------------------

    \109\ AirControlNet, Version 4.1, documentation report by E.H. 
Pechan and Associates, Inc. for U.S. EPA, Office of Air Quality, 
Planning, and Standards, May 2006, section III, page 445.
---------------------------------------------------------------------------

    Cost of Compliance: According to the Documentation Report 
accompanying AirControlNet, the cost to retrofit process heaters with 
LNB is $2,200 per ton.\110\
---------------------------------------------------------------------------

    \110\ Id.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: No significant 
energy and non-air environmental impacts are expected to result from 
use of LNB.
    Pollution Control Equipment in Use at the Source: No NOX 
controls are currently employed at either the converters or the anode 
furnaces.
    Remaining Useful Life of the Source: ASARCO has not indicated that 
any of the units would need to be replaced during the 20-year capital 
cost recovery period.
    Degree of Visibility Improvement: The maximum modeled 98th 
percentile visibility impact resulting from baseline NOX 
emissions from the Hayden Smelter is no higher than 0.01 dv\111\ at any 
of the Class I areas. Thus, the maximum visibility benefit of controls 
is less than 0.01 dv.
---------------------------------------------------------------------------

    \111\ Summary of WRAP RMC BART Modeling for Arizona, Draft 
Number 5, May 25, 2007. Also, ASARCO response letter, July 11, 2013, 
ENVIRON memo attachment, March 4, 2012, (``H-09 2013-03-04 ENVIRON 
report-Asarco-Hayden-BART.pdf''.
---------------------------------------------------------------------------

c. Proposed BART Determination for NOX
    Given the small potential for visibility improvement, we propose 
that controlling these NOX emissions is not warranted for 
purposes of BART. However, in order to ensure that NOX 
emissions do not increase in the future, we propose to set a 12-month 
rolling limit of 40 tons of NOX from the subject-to-BART 
units, which is equivalent to the de minimis level of emissions set out 
in the RHR.\112\ This emission limit is slightly lower than the annual 
50 tpy baseline emissions noted above. Nonetheless, we consider it to 
be a reasonable limit because the 50 tpy estimate assumes that all of 
the converters are all operating simultaneously, which is not how they 
typically operate. Therefore, we expect actual emissions to be well 
below 40 tpy, which is consistent with ASARCO's own estimate.\113\
---------------------------------------------------------------------------

    \112\ 40 CFR 51.308(e)(1)(ii)(C).
    \113\ Letter from Krishna Parameswaran, ASARCO, to Gregory Nudd, 
EPA dated March 6, 2013, page 15.
---------------------------------------------------------------------------

4. Summary of EPA's Proposed BART Determinations
    We propose that BART for SO2 from the converters is a 
control efficiency of 99.8 percent, 30-day rolling average, on all 
SO2 captured by the primary and secondary control systems. 
We propose to require compliance with this requirement within three 
years of promulgation of a final rule. We also are proposing 
monitoring, recordkeeping and reporting as well as operation and 
maintenance requirements, to ensure the enforceability of our proposed 
BART determination. We propose a work practice standard consistent with 
current practices for the anode furnaces. We also propose to set a 12-
month rolling limit of 40 tons of NOX from the subject-to-
BART units.
    We are seeking comment on all aspects of this proposal. In 
particular, we are seeking comment on the following elements of our 
BART analysis and determination for SO2 from the converters:
     The cost of controls;
     the collection efficiency for the primary collection 
system;
     the collection efficiency for the secondary collection 
system;
     the control efficiency to be applied to the primary and 
secondary collections systems;
     the compliance methodology; and
     the compliance schedule.

If we receive additional information concerning these or other elements 
of our analysis, we may finalize a BART determination that differs in 
some respects from this proposal.

D. Miami Smelter

    Summary: EPA proposes to find that the Miami Smelter is subject to 
BART for NOX in addition to SO2 and 
PM10, as determined by the State. For SO2 from 
the converters, we propose to require construction of a secondary 
capture system consistent with the requirements of MACT QQQ and an 
SO2 control efficiency of 99.7 percent, 30-day rolling 
average, on all SO2 captured by the primary and secondary 
capture systems. For SO2 emissions from the electric 
furnace, we propose to prohibit active aeration of the electric 
furnace. For NOX, we propose to find that controlling 
emissions from the converters and anode furnaces is cost-effective, but 
would not result in sufficient visibility improvement to warrant the 
cost. Therefore, we are proposing an annual emission limit of 40 tpy 
NOX emissions from the BART-eligible units at the Miami 
Smelter, which is consistent with current emissions from these units. 
We previously approved Arizona's determination that BART for 
PM10 at the Miami Smelter is the NESHAP for Primary Copper 
Smelting. Please refer to the Long Term Strategy in Section VII below, 
regarding our proposal to ensure the enforceability of this 
determination.
    Affected Class I Areas: Twelve Class I areas are within 300 km of 
the Miami Smelter with the nearest borders ranging from 55 km to 260 km 
away. The set of areas differs from the ones near the Hayden Smelter 
only in that Bosque Del Apache WA is included, and Sycamore Canyon WA 
is not. The baseline visibility impacts are 0.70 dv or less at all 
Class I areas except at Superstition where the visibility impact is 3.6 
dv. The cumulative sum of visibility impacts at all areas within 300 km 
is 8.2 dv.
    Facility Overview: The Miami Smelter is a batch-process copper 
smelter in Gila County, Arizona. We previously approved ADEQ's 
determination that Hoboken Converters 2, 3, 4 and 5 and the Electric 
Furnace at the facility are BART-eligible.\114\ We also approved ADEQ's 
determination that these units are subject to BART for SO2 
and that BART for PM10 at the Miami Smelter is the Maximum 
Achievable Control Technology (MACT) Subpart QQQ under the National 
Emission Standards for Hazardous Air Pollutants (NESHAP) for primary 
copper smelting. However, we disapproved ADEQ's determination that 
existing controls constitute BART for SO2 and that the units 
are not subject to BART for NOX. In light of these 
disapprovals and our FIP duty for Regional Haze in Arizona, we are 
required to promulgate a FIP to address BART for both SO2 
and NOX.
---------------------------------------------------------------------------

    \114\ 78 FR 46412 (July 30, 2013). See also the TSD for a 
description of these units.
---------------------------------------------------------------------------

    Baseline Emissions: Because neither FMMI nor ADEQ identified 
baseline emissions for the Miami Smelter, we selected emissions from 
2010 as the baseline. We chose 2010 because ADEQ provided the most 
detailed emissions information from this year in its RH SIP and because 
FMMI used 2010 as a basis for calculating uncaptured emissions of 
SO2 for 2011 and 2012. FMMI reports

[[Page 9348]]

emissions of SO2 to ADEQ by stack, and performs a mass-
balance equation to determine uncaptured emissions. SO2 
emissions in tons per year are presented in Table 34 as reported by 
FMMI to ADEQ for the acid plant duct, acid plant bypass duct, and the 
vent fume duct.\115\ Because each of these stacks vents emissions from 
both BART and non-BART emission units, EPA apportioned the emissions to 
BART and non-BART units for purposes of our analysis. The BART-eligible 
emissions from the acid plant were based on FMMI and ADEQ's estimate 
that 35 percent of SO2 sent to the acid plant is emitted by 
the converters and 65 percent of SO2 is emitted by the 
primary smelter (often called by a proprietary name, the IsaSmelt 
furnace) and electric furnace. Because it is not possible to 
differentiate which converter emissions are from the one converter that 
is not BART-eligible, we are treating all converter emissions as 
subject to BART. Subject-to-BART emissions from the vent fume duct were 
set at seven tons per year based on our estimate of the share of 
emissions originating from the electric furnace. Please refer to the 
TSD for an explanation for how the subject-to-BART uncaptured emissions 
are determined.
---------------------------------------------------------------------------

    \115\ The vent fume duct is the stack for a wet scrubber used to 
control emissions collected by the IsaSmelt secondary collection 
system, other collection systems associated with conveyors that are 
not BART-eligible, and emissions collected by the BART-eligible 
electric furnace secondary collection system.

                        Table 34--Miami Smelter: BART Baseline Emissions for SO2 in 2010
                                                 [Tons per year]
----------------------------------------------------------------------------------------------------------------
                                                    Acid plant      Acid plant
                                                       duct           bypass      Vent fume duct    Uncaptured
----------------------------------------------------------------------------------------------------------------
Total SO2 Emissions.............................           1,415              93             331           8,472
Subject-to-BART SO2 Emissions...................             495              33               7     3,231-8,078
----------------------------------------------------------------------------------------------------------------

    FMMI also reports potentially BART-eligible NOX 
emissions from the acid plant duct and from ``natural gas combustion'' 
to ADEQ as depicted in Table 35. FMMI estimates that 15 percent of 
NOX emitted from the acid plant duct originates from the 
BART-eligible converters. While ``natural gas emissions'' includes 
emissions from the converter burners, it is not possible to separate 
the BART-eligible emissions from ineligible emissions. Thus, we are 
assuming that all these emissions are BART-eligible.

    Table 35--Miami Smelter: BART Baseline Emissions for NOX in 2010
                             [Tons per year]
------------------------------------------------------------------------
                                            Acid plant      Natural gas
                                               duct         combustion
------------------------------------------------------------------------
Total NOx Emissions.....................             154              15
Subject-to-BART NOX Emissions...........              23              15
------------------------------------------------------------------------

    Modeling Overview: Using the CALPUFF model, EPA estimated the 
visibility impacts of the Miami Smelter in its current (i.e., baseline) 
configuration, and with two different control options for 
SO2 emissions. Model inputs were developed using work by the 
WRAP and updated stack and other information from FMMI. EPA made two 
different emissions calculations, incorporating high and low estimates 
of the amount of emissions that are not captured by the existing 
systems. Most of the discussion below focuses on modeling performed 
using the high estimate as shown in Table 37.
    An additional complication for this facility is that most of the 
emissions occur via a ``roofline,'' a long rectangular hole in the roof 
of the building containing the converters. Modeling the roofline as if 
it were a stack may be problematic, especially for nearby Class I 
areas. Modeling the roofline as a buoyant line source is a better 
characterization of the source. EPA performed sensitivity simulations, 
described in the TSD, and found that impacts do vary depending on 
whether it is modeled as a stack or a line source. Which modeling 
scenario resulted in higher impacts depended on the particular Class I 
area. EPA therefore modeled the main emissions from FMMI as a buoyant 
line source, despite the considerably longer model run times.
1. BART Analysis for SO2 From Converters
a. Control Technology Availability, Technical Feasibility and 
Effectiveness
    We identified two available and feasible technologies to control 
SO2 emissions from the converters: a double contact acid 
plant and wet scrubbing. FMMI already uses these two technologies in 
series to control SO2 emissions currently captured from the 
converters. Based on SO2 acid plant emissions and sulfuric 
acid production data provided to EPA by FMMI, we calculated that the 
existing acid plant and tail gas scrubber system is controlling at 
least 99.7 percent of the SO2 ducted to the acid plant,\116\ 
which we consider effective. Because FMMI already uses both of the two 
available control technologies to control SO2 emissions 
currently captured from the converters and achieves a high degree of 
control of these emissions, we did not further evaluate additional 
controls or upgrades to the existing controls as BART. Rather, we 
evaluated ways to improve the capture efficiency of the existing system 
so that additional emissions may be collected and controlled.
---------------------------------------------------------------------------

    \116\ Letter from Derek Cooke, FMMI, to Thomas Webb, EPA, 
Appendices A and C, January 25, 2013.
---------------------------------------------------------------------------

    In order to analyze options for improved capture, we requested 
information from FMMI regarding potential design improvements, upgrades 
to existing equipment or new equipment that could increase the degree 
of capture of SO2 emissions from the converters.\117\ In 
response, FMMI reported that it planned to improve the

[[Page 9349]]

converter mouth covers, reconfigure the roofline capture system and 
route the captured emissions to the existing acid plant.\118\ 
Accordingly, we performed a five-factor BART analysis for these 
improvements, which we refer to collectively as a ``secondary capture 
system.''
---------------------------------------------------------------------------

    \117\ Letter from Thomas Webb, EPA, to Derek Cooke, FMMI (June 
27, 2013).
    \118\ Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Item 2 
(July 12, 2013). FMMI indicated that ``[t]hese proposed changes are 
in anticipation of measures that may be adopted by ADEQ as necessary 
to demonstrate compliance'' with the 2012 SO2 NAAQS.'' 
Regardless of their regulatory purpose of the changes, FMMI's 
proposal indicates that these changes are technically feasible.
---------------------------------------------------------------------------

b. Secondary Capture System
    The purpose of the secondary capture system is to improve capture 
and control of SO2 emissions from the converters that can 
then be directed to the existing double contact acid plant.
    Cost of Compliance: FMMI claimed as confidential business 
information (CBI) the cost information for improvements in 
SO2 capture, so we relied on other information to estimate 
the cost of controls. In particular, we considered cost estimates 
supplied by ASARCO for the Hayden Smelter, a similar facility, for a 
series of upgrades to its capture systems.\119\ We estimated cost-
effectiveness using a capital cost of $47,850,000, and annualized those 
costs assuming a 20-year lifespan and a 7 percent interest rate with an 
operation and maintenance cost of 50 percent of the capital cost. We 
applied a control efficiency of 99.7 percent, which the existing acid 
plant and tail stack scrubber system currently achieves using very 
limited cesium catalyst. The emission reduction was applied to 85 
percent of the currently uncaptured SO2 emissions from the 
converters.\120\ Based on these calculations, we estimate the cost-
effectiveness of installing and operating a secondary capture system 
would be $990 to $2,474 per ton of SO2 removed, as shown in 
Table 36. This range reflects the uncertainty in the quantity of 
SO2 emissions that are currently not captured.
---------------------------------------------------------------------------

    \119\ See the TSD, Section III.D.4.
    \120\ Review of New Source Performance Standards for Primary 
Copper Smelters, OAQPS, EPA 450/3-83-018a, March 1984. According to 
Section 4.7.6.3, the overall collection efficiency of secondary 
fixed hoods is approximately 90 percent.

                                        Table 36--Miami Smelter: Cost of Secondary Capture of SO2 From Converters
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Annualized         Annual        Total annual       Tons SO2         Control         $/ton SO2
                   Capital cost                       capital cost    variable cost         cost           reduced         efficiency        removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
$47,850,000.......................................      $4,516,701       $2,258,351       $6,775,052      2,379-6,845            99.7%       $990-2,474
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: We do not 
anticipate significant energy or other non-air quality environmental 
impacts resulting from capturing and ducting additional emissions to 
the existing SO2 control system given that FMMI already has 
the capacity to handle and store the much larger quantities of sulfuric 
acid produced by emissions captured from the IsaSmelt and converter 
primary capture systems.
    Pollution Control Equipment in Use at the Source: SO2 
emissions collected from the converters are ducted to the four-pass, 
double contact acid plant. There is a wet scrubber (the tailstack 
scrubber) located after the acid plant outlet, to which emissions may 
be vented during periods of elevated SO2 
concentrations.\121\
---------------------------------------------------------------------------

    \121\ Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Item 2 
(July 12, 2013).
---------------------------------------------------------------------------

    Remaining Useful Life: The BART-eligible converters have each been 
in place for about 40 years. FMMI has not indicated that any of them 
would be replaced during the 20-year capital cost recovery period.
    Degree of Visibility Improvement: As shown in Table 37, installing 
a secondary capture system to collect and direct SO2 
emissions from the converters to the acid plant, the maximum 98th 
percentile baseline improvement ranges from a low of 0.41 dv to a high 
of 1.06 dv at Superstition WA. The cumulative improvement ranges from 
1.7 to 4.3 dv. These are large visibility improvements that support 
using the existing acid plant with a new secondary capture system as 
BART for SO2. The high and low visibility impacts and 
improvements in Table 37 correspond to the range of emissions that are 
not captured. The range is 3,231 (low) to 8,078 (high) tpy. For the low 
emission estimate, the maximum improvement from the secondary capture 
system is 0.41 dv, and the cumulative improvement is 1.7 dv. These are 
considerably less than for the high emission estimate, which has a 
maximum improvement of 1.06 dv and cumulative improvement of 4.3 dv, 
but is still substantial.

            Table 37--Miami Smelter: Visibility Impact and Improvement From Secondary Capture System
----------------------------------------------------------------------------------------------------------------
                                                             Impact      Improvement     Impact      Improvement
                                                         -------------- from control -------------- from control
                                               Distance                --------------              -------------
                Class I area                     (km)       High base     Converter     Low base      Converter
                                                              case       85% capture      case       85% capture
                                                            (basehi)      (opt1hi)      (baselo)      (opt1lo)
----------------------------------------------------------------------------------------------------------------
Bosque del Apache WA.......................          235          0.15          0.12          0.07          0.05
Chiricahua NM..............................          113          0.36          0.27          0.16          0.10
Chiricahua WA..............................          125          0.35          0.27          0.16          0.10
Galiuro WA.................................           99          0.56          0.40          0.28          0.17
Gila WA....................................           55          0.34          0.26          0.16          0.10
Mazatzal WA................................          220          0.64          0.44          0.32          0.17
Mount Baldy WA.............................           95          0.27          0.20          0.13          0.08
Petrified Forest NP........................          197          0.33          0.25          0.16          0.10
Pine Mountain WA...........................          260          0.43          0.32          0.20          0.12
Saguaro NP.................................          143          0.45          0.34          0.21          0.13
Sierra Ancha WA............................          158          0.70          0.40          0.42          0.17
Superstition WA............................          163          3.61          1.06          2.86          0.41

[[Page 9350]]

 
Cumulative (sum)...........................  ...........          8.2           4.3           5.1           1.7
Maximum....................................  ...........          3.61          1.06          2.86          0.41
 CIAs >= 0.5 dv...................  ...........          4             1             1             0
Million $/dv (cumul. dv)...................  ...........  ............         $1.6   ............         $4.0
Million $/dv (max. dv).....................  ...........  ............         $6.4   ............        $16.7
----------------------------------------------------------------------------------------------------------------

c. Proposed BART Determination for SO2 From Converters
    Based on the results of our BART analysis, we propose that BART for 
SO2 from the converters is construction of a secondary 
capture system (i.e., construction of hooding and ventilation systems 
to capture escaped SO2 emissions) and ducting the emissions 
to existing controls. We have determined that these improvements are 
feasible and cost-effective, will result in significant visibility 
improvements, and should not result in significant adverse impacts. As 
noted above, the RHR allows for use of equipment requirements or work 
practice standards in lieu of a numeric limit where ``technological or 
economic limitations on the applicability of measurement methodology to 
a particular source would make the imposition of an emission standard 
infeasible.'' \122\ In this instance, we propose to find that 
technological limitations on the source's ability to measure accurately 
uncaptured SO2 emissions make numeric capture efficiency 
infeasible. Therefore, we are proposing to prescribe specific equipment 
for capture of SO2 emissions, in addition to numeric control 
efficiency and related compliance requirements. Specifically, we are 
proposing the following as BART for SO2 from the converters:
---------------------------------------------------------------------------

    \122\ 40 CFR 51.308(e)(1)(iii). See also 40 CFR 
51.100(z)(defining ``emission limitation'' and ``emission standard'' 
to include ``any requirements which . . . prescribe equipment . . . 
for a source to assure continuous emission reduction.''
---------------------------------------------------------------------------

     Construction of a secondary capture system consistent with 
the requirements of MACT QQQ as a work practice standard.
     An SO2 control efficiency of 99.7 percent, 30-
day rolling average, on all SO2 captured by the primary and 
secondary capture systems.
     Compliance with the SO2 BART limit may be 
verified either through the use of SO2 CEMS before and after 
controls or by using post-control CEMS and acid production rates. A 
limit of 4.06 lbs SO2 emissions per tons of sulfuric acid 
production is equivalent to 99.7 percent control.
d. Alternative Control Efficiency
    We are also seeking comment on whether FMMI should be expected to 
meet a 99.8 percent control efficiency, 30-day rolling average, on all 
SO2 captured by the primary and secondary capture systems. 
ASARCO Hayden has demonstrated that a control efficiency of 99.8 
percent is achievable in practice at a batch copper smelter. FMMI could 
increase control efficiency by increasing its use of cesium promoted 
catalyst in the acid plant, increasing the volume of gas exiting the 
acid plant that is further controlled by the tail stack scrubber, and/
or using sodium rather than magnesium in the scrubbing liquor. If we 
received comments establishing that a control efficiency greater than 
99.7 percent is achievable at FMMI, we may finalize a control 
efficiency of up to 99.8 percent.
 2. BART Analysis for SO2 From Electric Furnace
a. Control Technology Availability, Technical Feasibility and 
Effectiveness
    EPA identified two possible technologies to control SO2 
emissions from the electric furnace: Double contact acid plant and wet 
scrubbing. FMMI has indicated to EPA that emissions from the electric 
furnace are already controlled by the existing double contact acid 
plant and tail stack scrubber.\123\ In addition, a secondary capture 
system ducts gases not captured by the primary capture system to the 
vent fume scrubber, which has a control efficiency of 80 percent. 
Because FMMI already uses both of the two available control 
technologies to control SO2 emissions currently captured 
from the furnace, we did not evaluate the addition of new controls, nor 
did we evaluate upgrades to the acid plant system, which already 
achieves a high degree of control. The one improvement to controls that 
we identified was upgrading the scrubber, which currently uses 
magnesium oxide, to use sodium hydroxide, which could increase the 
control efficiency from 80 percent to 98 percent.
---------------------------------------------------------------------------

    \123\ ADEQ Class 1 Permit Number 53592, Application for a 
Significant Permit Revision, July, 2013.
---------------------------------------------------------------------------

b. Existing Double Contact Acid Plant and Wet Scrubbing
    Cost of Compliance: We estimated the emissions from the electric 
furnace by multiplying the relevant AP 42 emission factors for copper 
smelters \124\ by the 2010 concentrate throughput provided by FMMI. 
This results in uncontrolled emissions of SO2 from the 
electric furnace of 379 tons per year. Because the scrubber is a 
secondary control device, however, this would likely result in an 
emissions decrease of no more than 5 to 10 tons per year. Replacing 
magnesium oxide with sodium hydroxide would cost at least $2,000,000 
per year, resulting in control costs of $200,000-$400,000 per ton of 
SO2 removed, as shown in Table 38.
---------------------------------------------------------------------------

    \124\ AP 42, Chapter 12.3, Primary Copper Smelters, Table 12.3-3 
(cleaning furnace) and Table 12.3-11 (converter slag return).

[[Page 9351]]



                                              Table 38--Miami Smelter: Cost of Upgrading Vent Fume Scrubber
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                 Annualized         Annual        Total annual       Tons SO2         Control
                Capital cost                    capital cost    variable cost         cost           reduced         efficiency      $/ton SO2 removed
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   $2,000,000       $2,000,000             5-10              98%      $200,000-$400,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts: We do not 
anticipate significant energy or non-air quality environmental impacts 
resulting from capturing and ducting additional emissions to the 
existing SO2 control system. Non-air quality impacts from 
venting additional captured emissions to the existing scrubber are not 
expected to be significant given that FMMI is already controlling much 
larger quantities of SO2 in the existing scrubber and 
managing the wastewater and sludge that result.
    Pollution Control Equipment in Use at the Source: SO2 
emissions collected from the electric furnace are ducted to the four-
pass, double contact acid plant. There is a wet scrubber (the tailstack 
scrubber) located after the acid plant outlet, to which emissions may 
be vented ``if needed.'' In addition, gases collected from the 
secondary collection system are ducted to the vent fume scrubber, which 
is another wet scrubber. The vent fume scrubber also controls secondary 
emissions from the IsaSmelt and emissions collected from other 
equipment.
    Remaining Useful Life: FMMI has not indicated any plans to remove 
the electric furnace from service.
    Degree of Visibility Improvement: Our modeling results did not 
demonstrate even modest visibility improvements at any Class I areas 
from this option. Improvements were 0.004 dv or less at each Class I 
area, and only 0.008 dv for the cumulative sum over all areas. These 
are negligible visibility improvements over the baseline levels, as 
expected from the small emission reductions associated with this 
option.
c. BART Determination for Electric Furnace
    Based on the high cost of compliance to upgrade the vent fume 
scrubber and low potential for visibility improvement, we are proposing 
that existing controls represent BART for SO2 emissions from 
the electric furnace. While we would prefer to set a numeric emission 
limit in order to ensure that SO2 emissions from the 
electric furnace do not increase in the future, such a limit is 
impracticable because emissions from the electric furnace are 
commingled with emissions from non-BART eligible units in the vent fume 
stack. Therefore, consistent with 40 CFR 51.308(e)(1), we propose a 
work practice standard prohibiting active aeration of the electric 
furnace.
3. BART Analysis for NOX From Process Heaters
    NOX emissions from the FMMI smelter result from the 
combustion of natural gas to heat process equipment. According to the 
Documentation Report accompanying AirControlNet, the cost to retrofit 
process heaters with low NOX burners, which can reduce 
NOX emissions by 50 percent, is $2,200 per ton.\125\ 
Although this is not necessarily cost-prohibitive, there is relatively 
little potential for visibility improvement from installation of any 
NOX controls at FMMI. In particular, the maximum modeled 
98th percentile visibility impact resulting from baseline 
NOX emissions from FMMI is 0.11 dv.\126\ In addition, the 
WRAP estimated the annual BART-eligible NOX emissions from 
the facility as 159 tons per year,\127\ whereas we estimate annual 
BART-eligible NOX baseline emissions as 38 tons per year. 
Therefore, the baseline visibility impact attributable to 
NOX, and thus, the potential for visibility improvement due 
to NOX reductions, is, in fact, significantly less than 0.11 
dv. Given the small potential for visibility improvement, we propose 
that NOX controls are not warranted for purposes of BART. 
However, in order to ensure that NOX emissions do not 
increase in the future, we propose to set a 12-month rolling cap of 40 
tons of NOX from the subject-to-BART units, which is 
equivalent to the de minimis level of emissions set out in the RHR and 
is roughly equivalent to current annual emissions from these 
units.\128\
---------------------------------------------------------------------------

    \125\ AirControlNet, Version 4.1, Documentation Report. Prepared 
by E.H. Pechan and Associates, Inc. for U.S. EPA, Office of Air 
Quality, Planning, and Standards. May, 2006, section III, page 445.
    \126\ Summary of WRAP RMC BART Modeling for Arizona, Draft 
Number 5, May 25, 2007, page 23.
    \127\ Id.
    \128\ 40 CFR 51.308(e)(1)(ii)(C).
---------------------------------------------------------------------------

VI. EPA's Proposed Reasonable Progress Analyses and Determinations

    Summary: In this section, EPA addresses point sources for 
NOX, area sources for NOX and SO2, the 
reasonable progress goals for the Class I areas, and a demonstration 
that the rate of progress is reasonable compared to the URP. In our 
previous actions on the Arizona RH SIP, EPA narrowed the focus of the 
RP analysis to point sources of NOX and area sources of 
NOX and SO2. Based on our analysis, we propose to 
require emissions reductions consistent with SNCR on Kiln 4 at the 
Phoenix Cement Clarkdale Plant and on Kiln 4 at the CalPortland Cement 
Rillito Plant. EPA proposes to find that it is not reasonable to 
require additional controls on area sources of NOX and 
SO2 at this time. We are also proposing RPGs consistent with 
a combination of control measures that include the approved Arizona RH 
SIP measures as well as the finalized and proposed Arizona RH FIP 
measures. Finally, we propose to find that it is not reasonable for any 
of Arizona's Class I areas to meet the URP during this planning period, 
and demonstrate that rate of progress is reasonable based on our RP 
analysis.
    Background: The RHR requires the State, or EPA in the case of a 
FIP, to set RPGs by considering four factors: ``the costs of 
compliance, the time necessary for compliance, the energy and non-air 
quality environmental impacts of compliance, and the remaining useful 
life of any potentially affected sources'' (collectively ``the RP 
factors'').\129\ The RPGs must provide for an improvement in visibility 
on the worst days and ensure no degradation in visibility on the best 
days during the planning period. Furthermore, if the projected progress 
for the worst days is less than the Uniform Rate of Progress (URP), 
then the state or EPA must demonstrate, based on the factors above, 
that it is not reasonable to provide for a rate of progress consistent 
with the URP.\130\
---------------------------------------------------------------------------

    \129\ 40 CFR 51.308(d)(1)(i)(A).
    \130\ 40 CFR 51.308(d)(1)(ii).
---------------------------------------------------------------------------

    In our final rule on the Arizona RH SIP published on July 30, 2013, 
we partially approved and partially disapproved the State's RP 
analysis.\131\ In particular, we approved the State's decision to focus 
on NOX and SO2 sources and its decision not to 
require additional controls on non-BART point sources of SO2 
for this planning period. However, we disapproved the State's RPGs for 
the worst days and best days, as well as its RP analyses and 
determinations for point sources of NOX

[[Page 9352]]

as well as area sources of SO2 and NOX. 
Accordingly, we have analyzed these remaining source categories to 
determine whether additional controls are reasonable based on an 
evaluation of the RP factors.
---------------------------------------------------------------------------

    \131\ See 78 FR 46173 (codified at 40 CFR 52.145(g)).
---------------------------------------------------------------------------

 A. Reasonable Progress Analysis of Point Sources for NOX

    EPA conducted an extensive statewide analysis of NOX 
point sources to determine whether cost-effective controls on sources 
near Class I areas would contribute to visibility improvements. In this 
section, we describe the process to identify and analyze these 
potentially affected NOX point sources for reasonable 
progress. Of the nine point sources evaluated for reasonable progress, 
EPA is proposing to require Phoenix Cement Clarkdale Plant and 
CalPortland Cement Rillito Plant to comply with new emissions limits 
for NOX based on the analysis presented below and in the TSD 
available in the docket. We are seeking comment on our analyses and 
proposed determinations for all the identified sources.
1. Identification of NOX Point Sources
    To identify point sources in Arizona that potentially affect 
visibility in Class I areas, EPA examined the annual emissions data 
from the WRAP 2002 planning inventory and identified those sources with 
facility-wide actual emissions that exceed 250 tpy of NOX or 
SO2. For these sources, we calculated the total actual 
emission rate (Q) in tpy of NOX and SO2 and 
determined the distance (D) in kilometers of each source to its closest 
Class I area.\132\ We employed a contractor to prepare an initial 
spreadsheet calculating these Q and D values.\133\ We used a Q divided 
by D value of ten as a threshold for further evaluation of RP controls. 
We selected this value based on guidance contained in the BART 
Guidelines, which state:
---------------------------------------------------------------------------

    \132\ The analysis included NOX, SO2, and 
particulate matter pollutants because we had not yet approved ADEQ's 
determination to focus on NOX and SO2, nor had 
we approved its conclusion regarding non-BART SO2 point 
sources, at the time this screening analysis was performed.
    \133\ ``EP-D-07-102 WA5-12 Task4 Deliverable (AZ-BART-QbyD-
Screening-report)-final.xlsx''.

    Based on our analyses, we believe that a State that has 
established 0.5 deciviews as a contribution threshold could 
reasonably exempt from the BART review process sources that emit 
less than 500 tpy of NOX or SO2 (or combined 
NOX and SO2), as long as these sources are 
located more than 50 kilometers from any Class I area; and sources 
that emit less than 1000 tpy of NOX or SO2 (or 
combined NOX and SO2) that are located more 
than 100 kilometers from any Class I area.\134\
---------------------------------------------------------------------------

    \134\ See 40 CFR part 51, app. Y, Sec.  III (How to Identify 
Sources ``Subject to BART'').

The approach described above corresponds to a Q/D threshold of ten. In 
addition, the use of a Q/D threshold of ten or greater is recommended 
by the Federal Land Managers' Air Quality Related Values Work Group 
(FLAG) as a screening threshold, as described in the FLAG 2010 Phase I 
Report.\135\ A summary of sources with a Q/D value greater than 10 is 
included in Table 39.
---------------------------------------------------------------------------

    \135\ Section 3.2, Initial Screening Criteria (New), Federal 
Land Managers' Air Quality Related Values Work Group (FLAG) Phase I 
Report--Revised (2010).

                             Table 39--Sources of NOX With Q/D Value Greater Than 10
----------------------------------------------------------------------------------------------------------------
             Owner/operator                        Facility name             Q  (tpy)     D  (km)        Q/D
----------------------------------------------------------------------------------------------------------------
Arizona Public Service..................  West Phoenix Plant.............          992        73.10           14
CalPortland Cement Co...................  Rillito Plant..................        5,075         6.99          726
Arizona Electric Power Coop.............  Apache Generating Station......       11,840        44.86          264
Arizona Public Service..................  Cholla Power Plant.............       33,588        31.75         1058
Lhoist North America....................  Douglas Lime Plant.............          755        55.16           14
El Paso Natural Gas Co..................  Tucson Compressor Station......          336        14.72           23
El Paso Natural Gas Co..................  Flagstaff Compressor Station...        1,010        34.94           29
Tucson Electric Power...................  Sundt Generating Station.......        5,659        15.84          357
Lhoist North America....................  Nelson Lime Plant..............        2,556        24.56          104
Freeport-McMoRan........................  Miami Smelter..................        5,996        15.58          385
Phoenix Cement..........................  Clarkdale Plant................        2,744        12.65          217
Pima County.............................  Ina Road Sewage Plant..........          258        12.56           21
ASARCO..................................  Smelter and Mill...............       18,486        47.22          392
Salt River Project......................  Coronado Generating Station....       29,674        48.53          611
Salt River Project......................  San Tan Generating Station.....          335        28.13           12
Catalyst Paper Abitibi..................  Snowflake Pulp Mill............        5,143        39.36          131
Salt River Project......................  Aqua Fria Generating Station...          994        68.87           14
Tucson Electric Power...................  Springerville Generating              32,434        60.46          536
                                           Station.
El Paso Natural Gas Co..................  Williams Compressor Station....        1,373        19.12           72
----------------------------------------------------------------------------------------------------------------

    Of the sources listed in Table 39, we eliminated several sources 
from further consideration by calculating updated Q/D values based on 
2008-2010 emission data.\136\ As a result, APS West Phoenix Plant, 
Lhoist Douglas Plant, SRP San Tan Generating Station, and SRP Agua Fria 
Generating Station have Q/D values less than or equal to ten. Thus, we 
eliminated these sources from further consideration for this planning 
period. However, if any of these sources resume operations at levels 
sufficient to increase their Q/D value to ten or greater, Arizona 
should consider them for potential RP controls in the next planning 
period.
---------------------------------------------------------------------------

    \136\ See spreadsheet ``10D Screening Update--2008-10 Emission 
Data.xlsx'' in the docket.
---------------------------------------------------------------------------

    Finally, we eliminated from further consideration those sources (or 
units at sources) that were evaluated under BART. These include the 
Apache Generating Station, Coronado Generating Station, Cholla Power 
Plant (except Unit 1), Sundt Generating Station (except for Units 1-3), 
Snowflake Pulp and Paper Mill, and Nelson Lime Plant. Because the BART 
analysis examines many of the same factors as those evaluated for 
reasonable progress, we propose that the BART determinations for these 
facilities satisfy the requirement for reasonable progress from these 
facilities during this planning period. The final list of sources 
considered for reasonable progress NOX controls is 
summarized in Table 40.

[[Page 9353]]



                            Table 40--Sources of NOX for Reasonable Progress Analyses
----------------------------------------------------------------------------------------------------------------
            Owner/operator                     Facility name                             Notes
----------------------------------------------------------------------------------------------------------------
CalPortland Cement Co................  Rillito Plant................
Arizona Public Service...............  Cholla Power Plant (Unit 1)..  Units 2-4 subject to BART.
El Paso Natural Gas Co...............  Tucson Compressor Station....
El Paso Natural Gas Co...............  Flagstaff Compressor Station.
Tucson Electric Power................  Sundt Generating Station       Unit 4 subject to BART.
                                        (Units 1-3).
Phoenix Cement.......................  Clarkdale Plant..............
Pima County..........................  Ina Road Sewage Plant........
Tucson Electric Power................  Springerville Generating       Units 3-4 have SCR.
                                        Station (Units 1-2).
El Paso Natural Gas Co...............  Williams Compressor Station..
----------------------------------------------------------------------------------------------------------------

2. Analysis of Potentially Affected NOX Point Sources
    EPA contracted with the University of North Carolina (UNC) and 
their subcontractor, Andover Technology Partners (ATP), to perform RP 
analyses for the nine sources listed in Table 40. EPA considered the 
four RP factors for each of these sources based on the work from UNC. 
In addition, for the larger point sources (EGUs and cement kilns), we 
conducted CALPUFF modeling to assess the potential visibility benefits 
of controls.\137\ These analyses are set out in the TSD and are 
summarized in the following sections.
---------------------------------------------------------------------------

    \137\ While visibility is not an explicitly listed factor to 
consider when determining whether additional controls are 
reasonable, the purpose of the four-factor analysis is to determine 
what degree of progress toward natural visibility conditions is 
reasonable. Therefore, it is appropriate to consider the projected 
visibility benefit of the controls when determining if the controls 
are needed to make reasonable progress.
---------------------------------------------------------------------------

a. Phoenix Cement Clarkdale Plant Kiln 4
    Costs of Compliance: This facility consists of one precalciner 
kiln, which currently uses LNB for NOX control. Our estimate 
of costs of compliance is based primarily on estimates provided by PCC 
in their March 6, 2013 comment letter, with revisions to certain cost 
items we considered to be unreasonable or not allowed by EPA's Control 
Cost Manual.\138\ As explained in further detail in the TSD, we 
estimated a total annual cost for SNCR of approximately $940,000 per 
year. SNCR is estimated to reduce emissions at the kiln by 810 tpy at a 
cost of $1,142/ton, based on baseline emissions of 1620 tpy and a 50 
percent SNCR control efficiency. As explained in the TSD, we are 
seeking comment on whether a different SNCR control efficiency is 
appropriate for this kiln. If we receive technical information 
demonstrating that a different SNCR control efficiency is appropriate 
for Kiln 4, we will incorporate this change into our analysis.
---------------------------------------------------------------------------

    \138\ Comments submitted on EPA's December 21, 2012 proposed 
rulemaking partially approving and disapproving Arizona's Regional 
Haze Plan. 77 FR 75704.
---------------------------------------------------------------------------

    Time Necessary for Compliance: We expect that SNCR could be 
installed in approximately 3 years from the final date of this action. 
The Institute of Clean Air Companies estimates that the installation 
time for SNCR on industrial sources is 10-13 months.\139\ CPCC 
estimates that it would require approximately three years to install 
SNCR on their similar technology kiln. Given these two pieces of 
information, a 3-year timeframe appears to be reasonable.
---------------------------------------------------------------------------

    \139\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
installation and operation of SNCR at the plant would require a small 
increase in energy usage. The cost of this additional energy usage is 
included in the cost analysis. Non-air quality environmental impacts 
associated with SNCR include the hazards of transporting and storing 
urea or ammonia, especially if anhydrous ammonia is used. However, 
since the handling of anhydrous ammonia will involve the development of 
a risk management plan (RMP), we consider the associated safety issues 
to be manageable as long as established safety procedures are followed. 
Therefore, we find that these impacts are not sufficient to warrant 
eliminating SNCR as a control option.
    Remaining Useful Life: EPA presumes that the kiln would continue 
operating for 20 years and fully amortize the cost of controls.
    Degree of Improvement in Visibility: There are twelve Class I areas 
within 300 km of the Clarkdale Plant. As shown in Table 41, the highest 
98th percentile baseline visibility impact of Phoenix Cement is 5.2 dv 
at Sycamore. Pine Mountain, Mazatzal, and the Grand Canyon all have 
visibility impacts over 0.5 dv, and other areas are at 0.1 dv or less. 
The cumulative sum of visibility impacts over all the Class I areas is 
7.5 dv. The maximum visibility improvement due to SNCR is 1.9 dv at 
Sycamore, 0.3 dv at Pine Mountain, and slightly less at Mazatzal and 
the Grand Canyon. The cumulative improvement from SNCR is 3.0 dv.

 Table 41--Phoenix Cement Kiln 4: Visibility Impact and Improvement From
                              NOX Controls
------------------------------------------------------------------------
                                               Visibility    Visibility
                                                 impact      improvement
          Class I Area             Distance  ---------------------------
                                     (km)       Base case    SNCR  -50%
                                                 (base)     NOX  (ctrl2)
------------------------------------------------------------------------
Bryce Canyon NP................          296          0.09          0.04
Galiuro WA.....................          278          0.03          0.01
Grand Canyon NP................          133          0.51          0.25
Mazatzal WA....................           59          0.51          0.24
Mount Baldy WA.................          249          0.05          0.02
Petrified Forest NP............          200          0.21          0.10
Pine Mountain WA...............           56          0.66          0.32

[[Page 9354]]

 
Saguaro NP.....................          284          0.03          0.01
Sierra Ancha WA................          142          0.09          0.04
Superstition WA................          151          0.10          0.05
Sycamore Canyon WA.............           10          5.15          1.85
Zion NP........................          272          0.09          0.05
Cumulative (sum)...............  ...........          7.5           3.0
Maximum........................  ...........          5.15          1.85
 CIAs >= 0.5 dv.......  ...........          4             1
Million $/dv (cumul. dv).......  ...........  ............         $0.3
Million $/dv (max. dv).........  ...........  ............         $0.5
------------------------------------------------------------------------

    Phoenix Cement is only 10.5 km away from the Sycamore Canyon 
Wilderness. Therefore NOX emitted by the Plant may not be 
fully converted to NO2 by the time it reaches Sycamore 
Canyon and may not be fully available to form visibility-degrading 
particulate nitrate. However, the CALPUFF model assumes 100 percent 
conversion. EPA explored this issue by scaling back the visibility 
extinction due to NO2 and nitrate to reflect lower NO-to-
NO2 conversion rates, described further in the TSD. As shown 
in Table 42, EPA found that visibility impacts and the improvement due 
to SNCR decrease along with the percent conversion assumed. However, 
the benefit of SNCR is 0.52 dv when NO conversion is reduced to 25 
percent. Even for an unrealistically low assumption of 10 percent 
(i.e., no conversion of NO to NO2 after the plume leaves the 
stack), the benefit of SNCR is 0.25 dv at Sycamore Canyon alone. 
Because the other Class I Areas are far enough away for NOX 
emitted by the Plant to be fully converted to NO2, the 
benefits at the other Class I areas would remain the same.

      Table 42--Benefit of SNCR on Phoenix Cement at Sycamore Canyon for Various NO-to-NO2 Conversion Rates
----------------------------------------------------------------------------------------------------------------
                NO % Conversion                      100%         75%          50%          25%          10%
----------------------------------------------------------------------------------------------------------------
Base case......................................         5.14         4.19         3.13         1.94         1.17
SNCR...........................................         3.30         2.68         2.07         1.42         0.92
Benefit........................................         1.85         1.51         1.06         0.52         0.25
----------------------------------------------------------------------------------------------------------------

    Proposed RP Determination: Based on our analysis of the four RP 
factors, as well as the expected degree visibility improvement, EPA 
proposes to require compliance with an emission limit of 2.12 lb/ton on 
Kiln 4 based on a 30-day rolling average basis.\140\ We propose to find 
that this emissions limit, equivalent to SNCR control, is cost-
effective at $1,142/ton and would result in significant visibility 
benefits at Sycamore Canyon Wilderness Area. We are proposing to 
require compliance with the 2.12 lb/ton limit by December 31, 2018.
---------------------------------------------------------------------------

    \140\ The basis for this specific emission rate is described in 
the TSD.
---------------------------------------------------------------------------

    We are also soliciting comment on the possibility of establishing 
an annual cap on NOX emissions from Kiln 4 in lieu of a lb/
ton emission limit. Such a cap would provide additional flexibility to 
PCC by allowing them to comply either by installing controls or by 
limiting production. In particular, we are seeking comment on an annual 
NOX emission cap for Kiln 4 of 810 tpy established on a 
rolling 12-month basis, effective December 31, 2018. If production 
remains at current levels, PCC could meet this cap without installing 
any additional controls. However, if production increases to pre-2008 
levels, we expect that PCC would need to install SNCR on Kiln 4 to 
comply with the cap.
b. CalPortland Cement Rillito Plant Kilns 1-4
    The facility consists of three long dry kilns (Kilns 1-3) and one 
precalciner kiln (Kiln 4). Due to the significant differences between 
long dry kilns and precalciner kilns, we have separately analyzed Kilns 
1-3 and Kiln 4.
1. Rillito Plant Kilns 1-3
    Kilns 1-3 have not operated since 2008 due to economic conditions. 
However, CPCC retains the ability to start using these kilns again at 
any time. Therefore, we conducted an analysis of the kilns using pre-
2008 emission levels.

[[Page 9355]]

    Costs of Compliance: Our estimate of the costs of compliance is 
based primarily on estimates provided by CalPortland in its RP 
analysis, with revisions to certain cost items we considered to be 
unreasonable or not allowed by EPA's Control Cost Manual.\141\ Our 
analysis identified SNCR with Mixing Air Technology (MAT) as the most 
cost-effective control technology. Installation of SNCR with MAT on 
Kilns 1-3 is estimated to reduce emissions at each kiln by 182 tpy at a 
cost of $5,603/ton reduced, based on an annualized cost of 
approximately $1 million per year and 30-percent control efficiency for 
SNCR.\142\
---------------------------------------------------------------------------

    \141\ ``Reasonable Progress Analysis for CalPortland Company 
Rillito Cement Plant Kiln, prepared by CalPortland Company.'' 
Submitted to EPA May 9, 2013.
    \142\ See TSD for an analysis of all control options and 
associated control efficiencies and control costs.
---------------------------------------------------------------------------

    Time Necessary for Compliance: CPCC estimates that the time needed 
to install the control equipment is about 3 years.
    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
installation and operation of SNCR at the plant would require a small 
increase in energy usage. The cost of this additional energy usage is 
included in the cost analysis. Non-air quality environmental impacts 
associated with SNCR include the hazards of transporting and storing 
urea or ammonia, especially if anhydrous ammonia is used. However, 
since the handling of anhydrous ammonia will involve the development of 
an RMP, we consider the associated safety issues to be manageable as 
long as established safety procedures are followed. Therefore, we find 
that these impacts are not sufficient to warrant eliminating SNCR as a 
control option.
    Remaining Useful Life: The plant's owner intends to shut down all 
four kilns and replace them with a new kiln that would be subject to 
Best Available Control Technology and a visibility impact 
analysis.\143\ This project has been on hold while the economy in 
Arizona recovers. As a result, it is unclear whether these kilns will 
be in service long enough to fully amortize the cost of controls. 
However, because there is no enforceable shutdown date at this time, we 
assume that the kilns will remain in service for a 20-year amortization 
period.
---------------------------------------------------------------------------

    \143\ See Arizona RH SIP supplement, page 32.
---------------------------------------------------------------------------

    Degree of Improvement in Visibility: The maximum visibility 
improvement due to SNCR on Kilns 1-3 is 0.22 dv at the eastern unit of 
Saguaro NP, 0.18 dv at Galiuro WA, and smaller for other areas. The 
cumulative visibility improvement is 0.7 dv.

     Table 43--CalPortland Cement Kilns 1-3 and Kiln 4: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                         Visibility     Visibility  improvement
                                                                           impact    ---------------------------
                       Class I area                          Distance  --------------    SNCR on
                                                               (km)       Base case    Kilns 1, 2,  SNCR on Kiln
                                                                            (c0)        3  (c22)       4 (c24)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM............................................          171          0.25          0.05          0.06
Chiricahua WA............................................          170          0.23          0.05          0.05
Galiuro WA...............................................           73          1.02          0.18          0.19
Gila WA..................................................          240          0.12          0.02          0.03
Mazatzal WA..............................................          171          0.13          0.02          0.03
Mount Baldy WA...........................................          223          0.11          0.03          0.03
Petrified Forest NP......................................          290          0.11          0.02          0.03
Pine Mountain WA.........................................          213          0.11          0.02          0.02
Saguaro NP...............................................            8          1.26          0.22          0.24
Sierra Ancha WA..........................................          153          0.13          0.02          0.03
Superstition WA..........................................          108          0.30          0.06          0.06
Sycamore Canyon WA.......................................          287          0.09          0.02          0.02
Cumulative (sum).........................................  ...........          3.9           0.7           0.8
Maximum..................................................  ...........          1.26          0.22          0.24
 CIAs >= 0.5 dv.................................  ...........          2             0             0
Million $/dv (cumul. dv).................................  ...........  ............         $1.5          $1.4
Million $/dv (max. dv)...................................  ...........  ............         $4.8          $4.6
----------------------------------------------------------------------------------------------------------------
The Saguaro NP results in this table are for the eastern unit of the park only.

    Proposed RP Determination: Given the lack of emissions from Kilns 
1-3 over the last five years and the relatively high cost of controls 
($5,603/ton), EPA proposes to find that requiring controls for these 
units is not reasonable at this time.
2. Rillito Plant Kiln 4
    Costs of Compliance: Our estimate of the costs of compliance is 
based primarily on estimates provided by CalPortland in its RP 
analysis, with revisions to certain cost items we considered to be 
unreasonable or not allowed by EPA's Control Cost Manual.\144\ Our 
analysis identified the addition of SNCR to the existing LNB as the 
most cost-effective available control technology. As explained in 
further detail in the TSD, we estimated a total annual cost for SNCR of 
approximately $1.1 million per year. SNCR is estimated to reduce 
emissions by 1,041 tpy at a cost of $1,047/ton reduced, based on 
baseline emissions of 2,082 tons per year and a 50 percent SNCR 
control-efficiency. As explained in the TSD, we are seeking comment on 
whether a different SNCR control efficiency is appropriate for Kiln 4. 
If we receive technical information demonstrating that a different SNCR 
control efficiency is appropriate for Kiln 4, we will incorporate this 
change into our analysis.
---------------------------------------------------------------------------

    \144\ ``Reasonable Progress Analysis for CalPortland Company 
Rillito Cement Plant Kiln, prepared by CalPortland Company.'' 
Submitted to EPA May 9, 2013.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
installation and operation of SNCR at the plant would require a small 
increase in energy usage. The cost of this additional energy usage is 
included in the cost analysis. Non-air quality environmental impacts 
associated with SNCR include the hazards of

[[Page 9356]]

transporting and storing urea or ammonia, especially if anhydrous 
ammonia is used. However, since the handling of anhydrous ammonia will 
involve the development of an RMP, we consider the associated safety 
issues to be manageable as long as established safety procedures are 
followed. Therefore, we find that these impacts are not sufficient to 
warrant eliminating SNCR as a control option.
    Existing Pollution Control Equipment: Kiln 4 is a precalciner kiln 
that currently uses LNB for NOX control.
    Remaining Useful Life: The plant's owner intends to shut down all 
four kilns and replace them with a new kiln that would be subject to 
Best Available Control Technology and a visibility impact 
analysis.\145\ This project has been on hold while the economy in 
Arizona recovers. As a result, it is unclear whether these kilns will 
be in service long enough to fully amortize the cost of controls. 
However, because there is no enforceable shutdown date at this time, we 
assume that the kilns will remain in service for a 20-year amortization 
period.
---------------------------------------------------------------------------

    \145\ See Arizona RH SIP supplement, page 32.
---------------------------------------------------------------------------

    Degree of Improvement in Visibility: As shown in Table 43, the 
maximum visibility improvement due to SNCR on Kiln 4 is 0.24 dv at the 
eastern unit of Saguaro NP, 0.19 dv at Galiuro WA, and smaller for 
other areas. The cumulative visibility improvement is 0.8 dv. The 
cumulative visibility improvement from SNCR on all four kilns would be 
about 1.5 dv.
    As discussed above in the section covering visibility improvements 
for TEP Sundt, EPA remodeled impacts at Saguaro NP to address both the 
eastern and western units of the park. The modeled visibility impact at 
the western unit of Saguaro, not shown in the table, is 6.04 dv, far 
greater than at the eastern unit. The modeled improvement there due to 
SNCR is 0.30 dv, still rather modest but 25 percent greater than for 
the eastern unit. However, CalPortland is only 7.8 km away from the 
western unit, so its emitted NOX may not be fully converted 
to NO2 by the time it reaches there, as is assumed in the 
CALPUFF model. It thus may not be fully available to form visibility-
degrading particulate nitrate. EPA explored this issue by scaling back 
the visibility extinction due to NO2 and nitrate to reflect 
lower NO-to-NO2 conversion rates, described further in the 
TSD. EPA found that visibility impacts and the improvement due to SNCR 
decrease along with the percent conversion assumed, so much so that at 
a 25 percent conversion rate, the SNCR benefit was only 0.05 dv. 
Therefore, EPA is relying on impacts and improvements for the more 
distant eastern unit of Saguaro NP.
    Proposed RP Determination: EPA finds that SNCR is cost-effective 
for Kiln 4 at $1,047/ton, would not result in undue non-air quality 
environmental impacts, and would result in modest visibility benefits 
at Saguaro NP and Galiuro WA. Therefore, we propose to determine that 
it is reasonable to require SNCR at Kiln 4. In particular, EPA proposes 
to require compliance with an emissions limit of 2.67 lb/ton at Kiln 4 
based on a 30-day rolling average by December 31, 2018.\146\ We are 
also soliciting comment on the possibility of requiring an annual cap 
on NOX emissions in lieu of a lb/ton emission limit. In 
order to avoid a shift in production from Kiln 4 to Kilns 1-3, we are 
proposing that the cap would apply to all four kilns. In particular, we 
are seeking comment on an annual NOX emission cap for Kilns 
1-4 of 2,082 tpy, established on a rolling 12-month basis. CPCC could 
meet this cap either by retaining production at current levels, or by 
increasing production and installing SNCR on Kiln 4. We are proposing 
to require compliance with this rolling 12-month limit by December 31, 
2018.
---------------------------------------------------------------------------

    \146\ See TSD for a discussion of how this emission limit was 
calculated.
---------------------------------------------------------------------------

c. APS Cholla Unit 1
    Costs of Compliance: Unit 1 is a 1,246 MMBtu/hr tangential coal-
fired boiler, which currently employs LNB with separated overfire air 
(SOFA) for NOX control. EPA identified two feasible 
additional controls: SNCR and SCR. The estimated emission reductions 
and costs for these two options are summarized in Tables 44 and 45.

                                 Table 44--Cholla Unit 1: NOX Emission Estimates
----------------------------------------------------------------------------------------------------------------
                                                                  NOX  emissions                     Emission
                                                 ------------------------------------------------    reduction
                 Control option                                                                  ---------------
                                                    (lb/MMBtu)        (lb/hr)          (tpy)           (tpy)
----------------------------------------------------------------------------------------------------------------
Baseline (LNB+OFA)..............................            0.22             274           1,032
SNCR............................................            0.15             192             723             310
SCR.............................................            0.05              62             235             798
----------------------------------------------------------------------------------------------------------------


                                                   Table 45--Cholla Unit 1: NOX Control Cost Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Total capital    Annualized      Annual O&M     Total annual     Cost-effectiveness  ($/ton)
                                                               cost        capital cost        costs           cost      -------------------------------
                     Control option                      ----------------------------------------------------------------
                                                                ($)             ($)             ($)             ($)             Ave            Incr
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline (LNB+OFA)
SNCR....................................................      $2,272,000        $241,725        $918,875      $1,160,599          $3,748
SCR.....................................................      26,437,190       2,812,730       1,425,137       4,237,867           5,313          $6,307
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 9357]]

    Time Necessary for Compliance: Given the estimate from the 
Institute of Clean Air Companies\147\ that about a year is required to 
install SNCR, and the estimate of three years for installing SNCR on a 
cement kiln discussed previously in this notice, EPA estimates that 
SNCR could be installed in less than three years. In our previous 
Arizona FIP action, EPA estimated that 5 years would be required to 
install SCR on coal-fired boilers.\148\ That estimate also holds for 
this source.
---------------------------------------------------------------------------

    \147\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
    \148\ See 77 FR 42834 at 42865 for more details.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: SCR 
and SNCR can result in additional ammonia emissions. There is also 
increased truck traffic bringing the reagent on site. SCR will also 
slightly reduce the efficiency of the plant, resulting in increased 
fuel usage.
    Remaining Useful Life: EPA assumes that this plant would continue 
operating for 20 years and fully amortize the cost of controls.
    Degree of Improvement in Visibility: CALPUFF modeling indicates 
that installation of SNCR at Unit 1 would provide a 0.10 dv visibility 
benefit at the most affected Class I area, Petrified Forest NP, while 
installation of SCR would provide a 0.20 dv benefit at the same area as 
shown in Table 46. Note that all of these results, including the base 
case, assume that SCR has been applied to Units 2, 3 and 4, consistent 
with EPA's previous BART determination for those units.

                  Table 46--Cholla Unit 1: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                         Visibility     Visibility improvement
                                                                           impact            from control
                                                             Distance  -----------------------------------------
                       Class I area                            (km)       Base case
                                                                           (ctrl0/    SNCR on Unit   SCR on Unit
                                                                         ctrl2--r2)   1  (ctrl2-1)  1  (ctrl2-2)
----------------------------------------------------------------------------------------------------------------
Capitol Reef NP..........................................          300          0.71          0.04          0.09
Galiuro WA...............................................          249          0.30          0.01          0.01
Gila WA..................................................          222          0.48          0.01          0.01
Grand Canyon NP..........................................          179          1.14          0.05          0.12
Mazatzal WA..............................................          128          0.79          0.02          0.04
Mesa Verde NP............................................          292          0.65          0.03          0.06
Mount Baldy WA...........................................          128          0.71          0.01          0.02
Petrified Forest NP......................................           39          3.38          0.10          0.20
Pine Mountain WA.........................................          149          0.55          0.01          0.03
Saguaro NP...............................................          300          0.23          0.00          0.00
Sierra Ancha WA..........................................          126          0.87          0.02          0.06
Superstition WA..........................................          166          0.81          0.03          0.06
Sycamore Canyon WA.......................................          147          0.76          0.03          0.07
Cumulative (sum).........................................  ...........         11.4           0.3           0.7
Maximum..................................................  ...........          3.38          0.10          0.20
 CIAs >= 0.5 dv.................................  ...........         10             0             0
Million $/dv (cumul. dv).................................  ...........  ............         $3.0          $5.7
Million $/dv (max. dv)...................................  ...........  ............        $10.3         $21.7
----------------------------------------------------------------------------------------------------------------

    Proposed Determination: EPA proposes to determine that it is not 
reasonable to require additional controls on this facility at this 
time. The costs for both SNCR and SCR are relatively high in light of 
the relatively small anticipated visibility benefits of the controls. 
However, this decision should be revisited in future planning periods.
d. El Paso Natural Gas Company's Tucson Compressor Station
    Costs of Compliance: This site includes seventeen 1,071 hp 
compressor engines. EPA's analysis indicates that the most cost-
effective control would be an air/fuel ratio controller that would 
reduce emissions by 578 tpy at a cost of $792/ton.\149\
---------------------------------------------------------------------------

    \149\ See spreadsheet ``Non EGU--RP--Ch5.xlsx'' in the docket.
---------------------------------------------------------------------------

    The site also includes four 370 hp engines. EPA's analysis 
indicates that the most cost-effective control would be a three-way 
catalyst that would reduce emissions by 96 tons per year at a cost of 
$290/ton.
    Time Necessary for Compliance: The Institute of Clean Air Companies 
estimates that 8 to 14 weeks would be required to install these kinds 
of controls.\150\
---------------------------------------------------------------------------

    \150\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: 
Both controls may increase fuel usage by reducing the thermal 
efficiency of the engines.
    Remaining Useful Life: EPA assumes that the engines would continue 
operating for 20 years and fully amortize the cost of controls.
    Proposed Determination: EPA proposes to find that it is not 
reasonable to require additional controls on this facility at this 
time. Natural gas engines similar to those at the Tucson Compressor 
Station are found in various locations throughout Arizona. EPA's 
assessment indicates that a state-wide or regional approach to 
controlling this source category could result in significant emissions 
reductions. Given the dispersed nature of these engines, it is not 
practical for EPA to control these sources. Therefore, EPA proposes to 
find that it is not reasonable to require additional controls on this 
particular source at this time. This source category should be given 
serious consideration for future planning periods, as it would be more 
appropriately controlled by the State.
e. El Paso Natural Gas Company's Flagstaff Compressor Station
    Costs of Compliance: This site includes two 5,500 hp compressor 
engines. EPA's analysis indicates that the most cost-effective control 
would be an air/fuel ratio controller that would

[[Page 9358]]

reduce emissions by 398 tpy at a cost of $432/ton.\151\
---------------------------------------------------------------------------

    \151\ See spreadsheet ``Non EGU--RP--Ch5.xlsx'' in the docket.
---------------------------------------------------------------------------

    Time Necessary for Compliance: The Institute of Clean Air Companies 
estimates that 8 to 14 weeks would be required to install these kinds 
of controls.\152\
---------------------------------------------------------------------------

    \152\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
controls may increase fuel usage by reducing the thermal efficiency of 
the engines.
    Remaining Useful Life: EPA assumes that the engines would continue 
operating for 20 years and fully amortize the cost of controls.
    Proposed RP Determination: EPA proposes to find that it is not 
reasonable to require additional controls on this facility at this 
time. Natural gas engines similar to those comprising the Flagstaff 
Compressor Station are found in various locations throughout Arizona. 
EPA's assessment indicates that a state-wide or regional approach to 
controlling this source category could result in significant emissions 
reductions. Given the dispersed nature of these engines, many of which 
may fall into the area source category discussed above, it is not 
practical for EPA to control these sources. Therefore, EPA proposes to 
find that it is not reasonable to require additional controls on this 
particular source at this time. This source category should be given 
serious consideration for future planning periods.
f. Tucson Electric Power Sundt Station (Units 1-3)
    Costs of Compliance: TEP Sundt has three natural gas-fired boilers 
rated at approximately 1,220 MMBTU/hr each. EPA's analysis indicates 
that the most cost-effective control would be ultra-low NOX 
burners (ULNB). This retrofit would reduce emissions from Unit 1 by 46 
tpy at a cost of $8,300/ton. It would reduce emissions from Unit 2 by 
55 tpy at a cost of $7,000/ton. The retrofit would reduce emissions 
from Unit 3 by 90 tpy at a cost of $4,400/ton. As shown in Table 47, 
modeling indicates that these controls would provide a 0.40 dv 
visibility benefit at the most improved Class I area.
    Time Necessary for Compliance: The Institute of Clean Air Companies 
estimates that 6 to 8 months would be required to install these kinds 
of controls.\153\
---------------------------------------------------------------------------

    \153\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
ultra-low-NOX burners may reduce the thermodynamic 
efficiency of the boilers and require an increase in fuel consumption.
    Remaining Useful Life: EPA assumes that the boilers would continue 
operating for 20 years and fully amortize the cost of controls.
    Proposed RP Determination: EPA proposes to find that it is not 
reasonable to require additional controls on this facility at this 
time. As noted above, ULNB has cost-effectiveness values for Sundt 
Units 1-3 in the range of $4,000 to 7,000 per ton. These costs are 
relatively high in light of the anticipated visibility benefits of the 
controls. However, this decision should be revisited in future planning 
periods, particularly if these units operate at a higher capacity 
factor in the future.
    Degree of Improvement in Visibility: Modeling indicates that 
installation of ULNB on all three units would provide a 0.40 dv 
visibility benefit at the most improved Class I area, Saguaro National 
Park, as shown in Table 47. Note that all of these results assume that 
SNCR has been applied to Sundt Unit 4, consistent with EPA's previous 
BART determination for that unit. The visibility cost-effectiveness 
values are based on an annualized cost of $1.2 million per year, based 
on the analysis by UNC, contractor to EPA.\154\
---------------------------------------------------------------------------

    \154\ Technical Analysis for Arizona and Hawaii Regional Haze 
FIPs: Task 9: Five-Factor RP Analyses for TEP Springerville, APS 
Cholla, TEP Sundt, CalPortland Cement and Phoenix Cement Plants, 
Contract No. EP-D-07-102, Work Assignment 5-12; Prepared for EPA 
Region 9 by University of North Carolina at Chapel Hill, ICF 
International, and Andover Technology Partners; October 3, 2012, 
Table 20.

 Table 47--Sundt Unit 1, 2 and 3: Visibility Impact and Improvement From
                              NOX Controls
------------------------------------------------------------------------
                                               Visibility    Visibility
                                                impact       improvement
                                   Distance  -------------- from control
          Class I area               (km)       Base case  -------------
                                                (SNCR on
                                                 Unit 4)        ULNB
------------------------------------------------------------------------
Chiricahua NM..................          144          0.43          0.08
Chiricahua WA..................          141          0.51          0.07
Galiuro WA.....................           64          1.10          0.22
Gila WA........................          232          0.17          0.02
Mazatzal WA....................          203          0.19          0.02
Mount Baldy WA.................          232          0.15          0.02
Pine Mountain WA...............          247          0.15          0.01
Saguaro NP.....................           17          3.40          0.40
Sierra Ancha WA................          178          0.19          0.02
Superstition WA................          137          0.32          0.04
Cumulative (sum)...............  ...........          6.6           0.9
Maximum........................  ...........          3.40          0.40
 CIAs >= 0.5 dv.......  ...........          3             0
Million $/dv (cumul. dv).......  ...........  ............         $1.3
Million $/dv (max. dv).........  ...........  ............         $2.9
------------------------------------------------------------------------


[[Page 9359]]

g. Ina Road Sewage Plant
    Costs of Compliance: This site has seven 1,000 hp natural gas-fired 
internal combustion engines. EPA's analysis indicates that the most 
cost-effective control is non-selective catalytic reduction (NSCR). 
Installation of this control would reduce emissions by 1,029 tpy at a 
cost of $210/ton.\155\
---------------------------------------------------------------------------

    \155\ See spreadsheet ``Non EGU--RP--Ch5.xlsx'' in the docket.
---------------------------------------------------------------------------

    Time Necessary for Compliance: The Institute of Clean Air Companies 
estimates that 8 to 14 weeks would be required to install these kinds 
of controls.\156\
---------------------------------------------------------------------------

    \156\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: The 
control measure may decrease the thermodynamic efficiency of the 
engines and increase fuel usage.
    Remaining Useful Life: EPA assumes that the engines would continue 
operating for 20 years and fully amortize the cost of controls.
    Proposed RP Determination: EPA proposes to find that it is not 
reasonable to require additional controls on this facility at this 
time. Natural gas engines similar to those at the Ina Road Sewage Plant 
are found in many locations throughout Arizona. EPA's assessment 
indicates that a state-wide or regional approach to controlling this 
source category could result in significant emissions reductions. Given 
the dispersed nature of these engines, many of which may fall into the 
area source category discussed above, it is not practical for EPA to 
control these sources. Therefore, EPA proposes to find that it is not 
reasonable to require additional controls on this particular source at 
this time. This source category should be given serious consideration 
for future planning periods, as it would be more appropriately 
controlled by the State.
h. Tucson Electric Power Springerville Plant
    Costs of Compliance: TEP Springerville Plant Units 1 and 2 are 
4,700 MMBtu/hr tangential coal-fired boilers, which currently employ 
LNB with OFA for NOX control. EPA identified two feasible 
additional controls: SNCR and SCR. The estimated emission reductions 
and costs for these two options are summarized in Tables 48 and 49.

                           Table 48--TEP Springerville 1 and 2: NOX Emission Estimates
----------------------------------------------------------------------------------------------------------------
                                                                   NOX emissions                     Emission
                                                 ------------------------------------------------    reduction
                 Control option                                                                  ---------------
                                                     lb/MMBtu          lb/hr            tpy             tpy
----------------------------------------------------------------------------------------------------------------
Springerville 1:
    Baseline (LNB+OFA)..........................            0.18             769           2,189
    SNCR........................................            0.13             538            1532             657
    SCR.........................................            0.05             212             605           1,584
Springerville 2:
    Baseline (LNB+OFA)..........................            0.19             798           2,448
    SNCR........................................            0.13             559            1714             734
    SCR.........................................            0.05             210             644           1,804
----------------------------------------------------------------------------------------------------------------


                                             Table 49--TEP Springerville 1 and 2: NOX Control Cost Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Total capital    Annualized      Annual O&M     Total annual     Cost-effectiveness  ($/ton)
                                                               cost        capital cost        costs           cost      -------------------------------
                     Control option                      ----------------------------------------------------------------
                                                                 $             $/yr            $/yr            $/yr             Ave            Incr
--------------------------------------------------------------------------------------------------------------------------------------------------------
Springerville 1:
    Baseline (LNB+OFA)
    SNCR................................................      $8,496,000        $903,914      $1,933,059      $2,836,973          $4,320
    SCR.................................................      71,796,257       7,638,614       3,181,809      10,820,423           6,829          $8,606
Springerville 2:
    Baseline (LNB+OFA)
    SNCR................................................       8,496,000         903,914       2,141,291       3,045,205           4,146
    SCR.................................................      71,402,351       7,596,705       3,379,514      10,976,219           6,085           7,416
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Time Necessary for Compliance: Given the estimate from the 
Institute of Clean Air Companies \157\ that approximately a year is 
required to install SNCR and the estimate of three years for installing 
SNCR on a cement kiln discussed previously in this notice. EPA 
estimates that SNCR could be installed in less than three years. In our 
previous Arizona FIP action, EPA estimated that 5 years would be 
required to install SCR on coal-fired boilers.\158\ That estimate also 
holds for this source.
---------------------------------------------------------------------------

    \157\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
    \158\ See 77 FR 42834 at 42865 for more details.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: SCR 
and SNCR can result in additional ammonia emissions. There is also 
increased truck traffic bringing the reagent on site. SCR will also 
slightly reduce the efficiency of the plant, resulting in increased 
fuel usage.
    Remaining Useful Life: EPA assumes that this plant would continue 
operating for 20 years and fully amortize the cost of controls.
    Degree of Improvement in Visibility: As shown in Table 50, CALPUFF 
modeling indicates that SNCR at Units 1 and 2 would provide a 0.18 dv 
visibility benefit at the most affected Class I area and a cumulative 
0.8 dv benefit across all affected areas. SCR would provide a 0.41 dv 
benefit at the most affected Class I area and

[[Page 9360]]

cumulative 1.7 dv across all affected areas.

            Table 50--Springerville Units 1 & 2: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                      Impact         Improvement from control
                  Class I area                    Distance  (km) -----------------------------------------------
                                                                     Base case     SNC  (ctrl-1)   SCR  (ctrl-2)
----------------------------------------------------------------------------------------------------------------
Bandelier NM....................................             298            1.08            0.07            0.13
Chiricahua NM...................................             253            0.85            0.07            0.14
Chiricahua WA...................................             264            0.88            0.00            0.01
Galiuro WA......................................             211            0.95            0.03            0.08
Gila WA.........................................             111            4.39            0.18            0.41
Grand Canyon NP.................................             302            0.79            0.07            0.07
Mazatzal WA.....................................             209            0.86            0.01            0.01
Mount Baldy WA..................................              51            3.63            0.13            0.32
Petrified Forest NP.............................              79            2.46            0.06            0.09
Pine Mountain WA................................             236            0.67            0.02            0.06
Saguaro NP......................................             263            0.57            0.01            0.04
San Pedro Parks WA..............................             281            1.53            0.05            0.23
Sierra Ancha WA.................................             165            1.01            0.02            0.05
Superstition WA.................................             194            0.52            0.03            0.06
Sycamore Canyon WA..............................             263            0.65            0.02            0.04
Cumulative (sum)................................  ..............           20.8             0.8             1.7
Maximum.........................................  ..............            4.39            0.18            0.41
 CIAs >= 0.5 dv........................  ..............           15               0               0
                                                 ---------------------------------------------------------------
Million $/dv (cumul. dv)........................  ..............  ..............           $7.3           $12.6
Million $/dv (max. dv)..........................  ..............  ..............          $32.2           $53.4
----------------------------------------------------------------------------------------------------------------

    Proposed RP Determination: EPA proposes to determine that it is not 
reasonable to require additional controls at Springerville Units 1 and 
2 at this time. While the cost per ton for SNCR may be reasonable, the 
projected visibility benefits are relatively small (0.18 dv at the most 
affected area). The projected visibility benefits of SCR are larger 
(0.41 dv at the most affected area), but we do not consider them 
sufficient to warrant the relatively high cost of controls for purposes 
of RP in this planning period. However, these units should be 
considered for additional NOX controls in future planning 
periods.
i. El Paso Natural Gas Williams Compressor Station
    Costs of Compliance: This site consists of five 2,500 hp engines, 
one 3,400 hp engine, and one 32,200 hp gas turbine. EPA's analysis 
indicates that air/fuel ratio controllers are the most cost-effective 
controls for the five 2,500 hp engines and would reduce emissions by 
288 tpy at a cost of $547/ton. Our analysis indicates that an air/fuel 
ratio controller is also the most cost-effective control for the 3,400 
hp engine and would reduce emissions from that engine by 131 tpy at a 
cost of $444/ton. Our analysis further indicates that water injection 
would be the most cost-effective control for the gas turbine and would 
reduce emissions from that engine by 505 tpy at a cost of $854/
ton.\159\
---------------------------------------------------------------------------

    \159\ See spreadsheet ``Non EGU--RP--Ch5.xlsx'' in the docket.
---------------------------------------------------------------------------

    Time Necessary for Compliance: The Institute of Clean Air Companies 
estimates that 8 to 14 weeks would be required to install these kinds 
of controls.\160\
---------------------------------------------------------------------------

    \160\ Typical Installation Timelines for NOX 
Emissions Control Technologies on Industrial Sources, Institute of 
Clean Air Companies, December 4, 2006.
---------------------------------------------------------------------------

    Energy and Non-Air Quality Environmental Impacts of Compliance: 
These controls may increase fuel usage by reducing the thermal 
efficiency of the engines.
    Remaining Useful Life: EPA assumes that the engines would continue 
operating for 20 years and fully amortize the cost of controls.
    Proposed RP Determination: EPA proposes to find that it is not 
reasonable to require additional controls on this facility at this 
time. Natural gas engines similar to those comprising the Williams 
Compressor Station are found in various locations throughout Arizona. 
EPA's assessment indicates that a state-wide or regional approach to 
controlling this source could result in significant emissions 
reductions. Given the dispersed nature of these engines, many of which 
may fall into the area source category discussed above, it is not 
practical for EPA to control these sources. Therefore, EPA proposes to 
find that it is not reasonable to require additional controls on this 
particular source at this time. This source category should be given 
serious consideration for future planning periods, as it would be more 
appropriately controlled by the State.

B. Reasonable Progress Analysis of Area Sources for NOX and SO2

1. Identification of Area Sources for NOX and 
SO2.
    The initial step in our area source RP analysis was the 
identification of specific SO2 and NOX area 
source categories to evaluate for potential controls. To that end, we 
examined data from the 2008 National Emissions Inventory (NEI) to 
determine the most significant area sources of SO2 and 
NOX. This analysis is described in the TSD, and the results 
are summarized in Tables 51 and 52. As discussed in the TSD, there are 
significant uncertainties in the area source emissions inventory for 
Arizona. In spite of the uncertainty, it is evident that the primary 
area source categories of most concern are Industrial and Commercial 
Boilers and Internal Combustion Engines burning distillate fuel oil. A 
third category, Residential Natural Gas Combustion, also comprises a 
significant portion of NOX emissions. EPA has therefore 
identified these categories as ``potentially affected sources.'' EPA 
proposes to find that the remaining source categories comprise too 
small of a percentage contribution to

[[Page 9361]]

overall emissions to justify consideration for additional controls in 
this initial planning period.

                              Table 51--Significant Area Sources of NOX in Arizona
----------------------------------------------------------------------------------------------------------------
                                                                                    Portion of
                                                    Source        Tons per year     total area      Cumulative
                 Source type                    classification        (2008)          source        portion (%)
                                                     code                          emissions (%)
----------------------------------------------------------------------------------------------------------------
Industrial Boilers and Internal Combustion           2102004000          2,300              29.3            29.3
 Engines (burning distillate fuel oil).......
Residential Natural Gas Combustion...........        2104006000          1,645.7            20.2            49.5
Industrial Natural Gas Combustion............        2102006000            765.4             9.4            58.8
Open Burning, Land Clearing Debris...........  ................            727.0             8.9            67.7
----------------------------------------------------------------------------------------------------------------


                              Table 52--Significant Area Sources of SO2 in Arizona
----------------------------------------------------------------------------------------------------------------
                                                                                    Portion of
                                                     Source        Tons per year    total area      Cumulative
                  Source type                    classification       (2008)          source        portion (%)
                                                      code                         emissions (%)
----------------------------------------------------------------------------------------------------------------
Industrial Boilers and Internal Combustion            2102004000          1652.1            65.3            65.3
 Engines (burning distillate fuel oil)........
Commercial and Institutional Boilers and              2103004000           483.5            19.1            84.5
 Internal Combustion Engines (burning
 distillate fuel oil).........................
Industrial processes not elsewhere classified.        2399000000           110.4             4.4            88.8
----------------------------------------------------------------------------------------------------------------

 2. Analysis of Significant Area Source Categories
    a. Approach to Area Source Analysis
    In conducting an RP analysis for area source, EPA encountered 
significant limitations on the availability and accuracy of data 
concerning the relevant source categories. For purposes of emission 
inventory development, an area source is not a single facility, but a 
category of polluting sources known to exist within a certain 
geographic area (such as a county), whose actual number, age, and 
design is not known. The emissions from area sources are usually 
estimated based on a ``top-down'' method, where a surrogate piece of 
information, such as the number of people living in a county or the 
gallons of diesel fuel sold there in a given year, is used to estimate 
emissions. Each of the source categories analyzed has an emissions 
estimate derived from Federal, state, or local databases of fuel 
consumption. In the aggregate, these numbers are sufficiently accurate 
for most analyses. However, they do not provide adequate detail for EPA 
to precisely estimate the actual costs and benefits of controlling the 
existing population of sources.
    Given these limitations in available data, EPA's analyses of area 
sources are limited in scope. For each category we have developed 
ranges for the estimated cost of compliance and general information 
about each of the other factors, based largely on data from three 
sources: the WRAP Four-Factor Analysis report, \161\ EPA's Control 
Strategy Tool, and the documentation for EPA's AirControlNet tool.\162\ 
The WRAP report lists several possible NOX and 
SO2 controls for industrial boilers and internal combustion 
engines, depending on their size and pre-existing controls. The WRAP 
report also addresses the other mandatory factors for an RP analysis. 
The Control Strategy Tool is EPA's most current tool for assessing the 
cost-effectiveness of control strategies for various source categories. 
EPA used this tool to confirm that the cost estimates in the WRAP 
report are still reasonable.\163\ We also consulted the AirControlNet 
documentation report that contains the most current data on the cost-
effectiveness of NOX controls for residential natural gas 
combustion. Finally, while we lacked sufficient data to conduct 
visibility modeling for particular categories of area sources, we have 
analyzed the overall contribution of area sources to nitrate and 
sulfate-caused visibility impairment in Arizona's Class I areas in 
order to estimate the potential benefits of controls. The results of 
this analysis are provided below, following the results of the four-
factor analyses for all of the source categories.
---------------------------------------------------------------------------

    \161\ ``Supplementary Information for Four Factor Analyses by 
WRAP States,'' EC/R Incorporated, corrected version, April 20, 2010.
    \162\ ``AirControlNet, Version 4.1,'' May 2006, E.H. Pechan and 
Associates.
    \163\ See spreadsheet titled ``AZ FIP Cost Analysis--for Greg 
Nudd Rg 9--2013-08-13.xls''.
---------------------------------------------------------------------------

b. RP Analysis of Industrial, Commercial, and Institutional Boilers 
Burning Distillate Fuel Oil
    Cost of Compliance: The estimated cost-effectiveness values for 
NOX control options are:
     LNB: $400-7,000/ton;
     LNB/OFA: $400-7,000/ton;
     SNCR: $400-6,900/ton;
     SCR: $1,000-8,000/ton.
    The estimated cost-effectiveness values for SO2 control 
options for this category are:
     DSI: $5,000-11,000/ton;
     Wet FGD: $6,000-13,000/ton.
    Time Necessary for Compliance: Installation of the control devices, 
in most cases, should take no more than 2-3 years. The only possible 
exception may be for installation of SCR, which may take as long as 5 
years.
    Energy and Non-Air Quality Environmental Impacts of Compliance: LNB 
may reduce combustion efficiency and slightly increase fuel 
consumption; SNCR and SCR would require some electricity use and 
environmental impacts from ammonia slip and transport and storage of 
the reagent. Wet FGD requires large quantities of water and requires 
disposal of wet ash.
    Remaining Useful Life: It is reasonable to assume that the units 
would remain in use long enough to fully recover the costs of controls.

[[Page 9362]]

c. RP Analysis of Industrial, Commercial, and Institutional Internal 
Combustion Engines Burning Distillate Fuel Oil
    Costs of Compliance: We estimate the following cost-effectiveness 
values for NOX control options:
     Ignition timing retard: $1,000-2,200/ton;
     Exhaust Gas Recirculation: $780-2,000/ton;
     SCR: $3,000-7,700/ton;
     Replacement with Tier 4 engines: $900-2,400/ton.

We did not identify any technically feasible options for SO2 
control other than lower sulfur fuel.
    Time Necessary for Compliance: Installation of the control devices, 
in most cases, should take no more than 2-3 years. The only possible 
exception may be for installation of SCR, which may take as long as 5 
years.
    Energy and Non-Air Quality Environmental Impacts of Compliance: SCR 
would require some electricity use and there may also be environmental 
impacts from ammonia slip and transport and storage of the reagent. The 
other options would not have negative energy or non-air quality 
environmental impacts.
    Remaining Useful Life: It is reasonable to assume that the units 
would remain in use long enough to fully recover the costs of controls.
d. RP Analysis of Residential Natural Gas Combustion
    Costs of Compliance: We estimate the following cost-effectiveness 
values for NOX control options:
     Replace space heaters with Low NOX equivalent: 
$1,600/ton;
     Replace water heaters with Low NOX equivalent: 
$1,230/ton.\164\

    \164\ Both estimates from AirControlNet Manual p. III-90 and are 
in 1990 dollars.
---------------------------------------------------------------------------

SO2 controls are not needed for this category due to low 
sulfur content of pipeline natural gas.
    Time Necessary for Compliance: Installation of the new devices, in 
most cases, should take no more than 2-3 years.
    Energy and Non-Air Quality Environmental Impacts of Compliance: We 
did not identify any energy or non-air quality environmental impacts.
    Remaining Useful Life: This factor is not applicable for a unit 
replacement.
    Visibility Significance of Area Sources: As explained above, we do 
not have sufficient information to assess the likely visibility 
benefits of requiring controls on particular categories of area 
sources. However, in order to estimate the total potential visibility 
benefits that might result from controlling NOX and 
SO2 emissions from area sources, we have analyzed the 
overall contribution of area sources to nitrate- or sulfate-caused 
visibility impairment in Arizona's Class I areas. The relative 
contribution can be estimated by reviewing the results of the 
Particulate Source Apportionment Technology (PSAT) modeling conducted 
by the WRAP. This method and our evaluation of it are described in the 
WRAP TSD prepared by EPA.\165\ Tables 53 and 54 below compare the 
contribution of Arizona area sources to visibility impairment in 
Arizona's Class I areas with the contributions from point and mobile 
sources.\166\ Table 53 shows the relative contribution of these Arizona 
source categories to the 2018 predicted total nitrate impairment at the 
Class I areas. Table 54 shows the same data for 2018 predicted total 
sulfate impairment. Nitrate and sulfate comprise a subset of the total 
visibility impairment at these Class I areas. To calculate the source 
category's total contribution to visibility impairment, one would have 
to account for the other pollutants (such as coarse mass, black carbon, 
etc.). EPA has not made that calculation here, as we are looking 
specifically at nitrate and sulfate impairment for this RP analysis.
---------------------------------------------------------------------------

    \165\ ``Technical Support Document for Technical Products 
Prepared by the Western Regional Air Partnership (WRAP) in Support 
of Western Regional Haze Plans,'' February 28, 2011.
    \166\ See http://vista.cira.colostate.edu/tss/Results/HazePlanning.aspx, select ``Emissions and Source Apportionment'' and 
the 2018 Base Case (base 18b) emissions scenario.

   Table 53--2018 Projected Nitrate Impairment: Comparison of Arizona
                            Source Categories
------------------------------------------------------------------------
                                             Arizona   Arizona
                                              area      point    Arizona
               Class I area                  sources   sources   mobile
                                               (%)       (%)     sources
------------------------------------------------------------------------
CHIR1.....................................       0.7       5.1       5.1
GRCA2.....................................       2.9       7.4      18.3
IKBA1.....................................       4.1      12.3      23.6
BALD1.....................................       0.8      18.1       8.7
PEFO1.....................................       1.7      26.7      14.2
SAGU1.....................................       5.2      19.3      27.5
SAWE1.....................................       4.3      18.4      23.5
SIAN1.....................................       4.1       5.0      20.7
TONT1.....................................       5.4      12.7      30.2
SYCA1.....................................       2.7      14.0      19.3
------------------------------------------------------------------------


   Table 54--2018 Projected Sulfate Impairment: Comparison of Arizona
                            Source Categories
------------------------------------------------------------------------
                                             Arizona   Arizona   Arizona
               Class I area                   area      point    mobile
                                             sources   sources   sources
------------------------------------------------------------------------
CHIR1.....................................       0.4       4.7       0.5
GRCA2.....................................       0.4       4.3       1.0
IKBA1.....................................       1.0       6.7       1.2
BALD1.....................................       0.7      11.3       0.7
PEFO1.....................................       0.7      19.6       0.9
SAGU1.....................................       2.1      10.2       1.7
SAWE1.....................................       1.7       9.6       1.4
SIAN1.....................................       0.8       7.8       1.1
TONT1.....................................       1.3       7.8       2.8
SYCA1.....................................       1.0       3.5       0.8
------------------------------------------------------------------------

    As indicated in Tables 53 and 54, area sources in Arizona currently 
comprise a relatively small portion of the visibility impairment due to 
nitrate and sulfate, so the potential visibility benefits of 
NOX or SO2 controls on these sources would be 
relatively small at this point in time. However, the relative 
contribution of area sources to visibility impairment at Arizona's 
Class I areas may increase over time, as additional point source and 
mobile source controls are implemented. Therefore, additional analysis 
of these sources will be necessary in future planning periods.
f. Proposed RP Determination for Area Sources
    EPA proposes to find that it is not reasonable to require 
additional controls on area sources of NOX and 
SO2 at this time. There are significant uncertainties about 
the costs and potential benefits of such rules at this time. 
Furthermore, the visibility benefits due to area source controls are 
likely to be much smaller than the significant reductions in 
SO2 and NOX emissions from point sources achieved 
during this planning period. We also note that no other Regional Haze 
SIP or FIP has imposed controls on such sources primarily to ensure 
reasonable progress.\167\ EPA will work with the State and the relevant 
regional planning organizations to improve our understanding of the 
nature of these area source emissions, the costs and methods of 
controlling them, and their impact on visibility at Class I areas. 
Based on the results of these efforts,

[[Page 9363]]

these source categories should be carefully considered in future 
Regional Haze SIPs.
---------------------------------------------------------------------------

    \167\ The Colorado Regional Haze SIP includes rules limiting 
emissions from certain Reciprocating Internal Combustion Engines. 77 
FR 18052, 18089. However these rules are part of a State regulation 
intended to control ozone rather than regional haze. Colorado Air 
Quality Control Commission, Regulation Number 7, 5 CCR 1001-9, 
Control of Ozone via Ozone Precursors, Section XVII, Statewide 
Control for Oil and Gas Operations and Natural Gas-Fired 
Reciprocating Internal Combustion Engines, subsection E.3.a, 
(Regional Haze SIP) Rich Burn Reciprocating Internal Combustion 
Engines.
---------------------------------------------------------------------------

C. Reasonable Progress Goals

    We are proposing reasonable progress goals (RPGs) that are 
consistent with the combination of control measures included in the 
Arizona RH SIP measures that we previously approved; \168\ the partial 
RH FIP that we promulgated on December 5, 2012; \169\ and the partial 
RH FIP we are proposing today. In total, these final and proposed 
controls to meet the BART and RP requirements will result in higher 
emissions reductions and commensurate visibility improvements beyond 
what was in the State's plan. As a result, we expect that the 
visibility levels at Arizona Class I areas will be substantially better 
than predicted in the WRAP modeling that served as the basis for the 
State's RPGs. In addition, our final BART FIP for the Four Corners 
Power Plant on the Navajo Nation is expected to result in tens of 
thousands of tons per year of additional NOX reductions that 
will benefit some of Arizona's Class I areas. Likewise, our proposed 
BART FIP for the Navajo Generating Station, if finalized, will result 
in substantial visibility benefit for Class I areas.
---------------------------------------------------------------------------

    \168\ 77 FR 72512, 78 FR 46142.
    \169\ 77 FR 72512.
---------------------------------------------------------------------------

    While we would prefer to quantify these proposed RPGs for each of 
Arizona's 12 Class I areas based on the new state and federal plans, we 
lack sufficient time and resources to conduct the type of regional-
scale modeling required to develop such numerical RPGs.\170\ 
Nonetheless, we anticipate that the additional controls required in 
EPA's Regional Haze FIPs will result in an increase in visibility 
improvement during the 20 percent worst days and the 20 percent best 
days in all of Arizona's Class 1 Areas.
---------------------------------------------------------------------------

    \170\ The regional-scale modeling that formed the basis for 
Arizona's RPGs was developed by the WRAP's Regional Modeling Center 
over the course of several years with input from numerous sources.
---------------------------------------------------------------------------

D. Meeting the Uniform Rate of Progress

    As explained in our proposed and final rules on the Arizona RH SIP, 
the State set RPGs that provide for slower rates of improvement in 
visibility than the URP for each of the State's twelve Class I 
areas.\171\ Given the variety and location of the sources contributing 
to visibility impairment in Arizona, EPA considers it unlikely that all 
of Arizona's Class I areas will meet the URP during this planning 
period, even with the additional controls required in EPA's Regional 
Haze FIPs. Therefore, EPA must demonstrate that it is not reasonable to 
provide for rates of progress consistent with the URP for this planning 
period, based upon the four RP factors.\172\ Given that this 
demonstration must be based on the same four factors as the initial RP 
analysis, EPA proposes to find that the extensive reasonable progress 
analysis underlying our actions on the Arizona SIP, and the reasonable 
progress analysis found in this proposal are sufficient to make this 
demonstration. In particular, for the reasons explained in our proposed 
and final rules on the Arizona RH SIP, we have approved Arizona's 
determinations that it is not reasonable to require additional controls 
to address organic carbon, elemental carbon, coarse mass and fine soil 
during this planning period.\173\ We also approved the State's decision 
not to require additional controls on non-BART point sources of 
SO2.\174\ Moreover, based on the analyses set out in the 
preceding sections of this document, we are now proposing to find that 
it is not reasonable to require additional controls on most point 
sources of NOX or area sources of NOX and 
SO2 during this planning period. However, we are proposing 
to require additional NOX controls on two cement kilns. 
Based on all of these analyses, we propose to find that it is not 
reasonable for any of Arizona's Class I areas to meet the URP during 
this planning period.
---------------------------------------------------------------------------

    \171\ See 77 FR 75728, 78 FR 29298 and 78 FR 46160.
    \172\ 40 CFR 51.308(d)(1)(ii).
    \173\ See 77 FR 75728 for a discussion on sources of organic 
carbon and elemental carbon (fires), and 78 FR 29297-29299 for a 
discussion of coarse mass and fine soil.
    \174\ See 78 FR 46172.
---------------------------------------------------------------------------

VII. EPA's Proposed Long-Term Strategy Supplement

    In our final rule on the Arizona RH SIP published on July 30, 2013, 
we disapproved portions of the State's LTS related to three RHR 
requirements. These requirements were for measures needed to achieve 
emission reductions for out-of-state Class I areas, emissions 
limitations and schedules for compliance to achieve the reasonable 
progress goals, and enforceability of emissions limitations and control 
measures.\175\ These RHR requirements are found in 40 CFR 
51.308(d)(3)(ii), (v)(C) and (v)(F). We now are obligated to address 
these requirements through a FIP under CAA section 110(c). In this 
section, we describe each of these requirements, our rationale for 
disapproving these elements in the Arizona RH SIP, and propose how to 
address these requirements in our FIP.
---------------------------------------------------------------------------

    \175\ See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)).
---------------------------------------------------------------------------

A. Emission Reductions for Out-of-State Class I Areas

    Under the RHR, where a state has participated in a regional 
planning process, the state's LTS must include all measures needed to 
achieve that state's apportionment of emission reduction obligations 
agreed upon through that process.\176\ Arizona participated in a 
regional planning process through the WRAP and incorporated the WRAP-
developed visibility modeling into the Arizona RH SIP. However, the 
Arizona RH SIP did not include all measures needed to achieve the 
State's apportionment of emission reductions that were included in the 
WRAP modeling. In particular, Arizona's BART determinations lacked the 
necessary compliance schedules and requirements for operation and 
maintenance of control equipment and monitoring, recordkeeping and 
reporting to ensure that the assumed reductions at Arizona's BART 
sources are achieved. Therefore, we disapproved this element of the 
Arizona RH SIP.
---------------------------------------------------------------------------

    \176\ 40 CFR 51.308(d)(3)(ii).
---------------------------------------------------------------------------

B. Emissions Limitations and Schedules for Compliance To Achieve RPGs

    One of the factors a state must consider in developing its LTS is 
emissions limitations and schedules for compliance to achieve the 
State's RPGs for its own Class I areas.\177\ As explained in the 
preceding section, the Arizona RH SIP did not contain any enforceable 
emission limitations or schedules for compliance to achieve the State's 
RPGs. Therefore, we found that the Arizona RH SIP did not meet this 
requirement.
---------------------------------------------------------------------------

    \177\ 40 CFR 51.308(d)(3)(v)(C).
---------------------------------------------------------------------------

C. Enforceability of Emissions Limitations and Control Measures

    Another factor a state must consider in developing its LTS is the 
enforceability of emissions limitations and control measures.\178\ As 
explained in the preceding sections, Arizona's BART determinations lack 
provisions to ensure their enforceability. Therefore, we disapproved 
the Arizona RH SIP with respect to this requirement.
---------------------------------------------------------------------------

    \178\ 40 CFR 51.308(d)(3)(v)(F).
---------------------------------------------------------------------------

D. Proposed Partial LTS FIP

    The primary flaw in Arizona's LTS is the lack of enforceable 
emission limitations for BART controls. We propose to remedy this 
deficiency by promulgating BART emission limitations and compliance 
schedules as

[[Page 9364]]

well as monitoring, recordkeeping and reporting requirements, to ensure 
the enforceability of these limits.
1. Enforceability Requirements for Arizona and EPA's Phase 1 BART 
Determinations
    As part of our final rule published on December 5, 2012, regarding 
BART for Apache Generating Station, Cholla Power Plant and Coronado 
Generating Station, we promulgated compliance deadlines and 
requirements for equipment maintenance and operation including 
monitoring, recordkeeping and reporting, to ensure the enforceability 
of both Arizona's and EPA's BART determinations.
2. Enforceability Requirements for EPA's Proposed Phase 3 BART and RP 
Determinations
    As described above, today, we are proposing to promulgate similar 
requirements for the remaining subject-to-BART sources and pollutants 
in Arizona. We are also proposing emission limitations and compliance 
requirements for two RP sources: the Phoenix Cement Clarkdale Plant and 
the CalPortland Rillito Plant.
3. Enforceability Requirements for Arizona's Phase 2 BART 
Determinations
    The final element of our proposed LTS consists of enforceable 
emission limitations and associated requirements for PM10 at 
the Hayden and Miami Copper Smelters. While we previously approved the 
State's determination that existing controls constitute BART for 
PM10 at each of these facilities, the Arizona RH SIP lacked 
any emission limitation or associated requirements to ensure the 
enforceability of these determinations, as required under the CAA and 
EPA's regulations.\179\ Therefore, we are proposing to promulgate such 
limits and associated compliance requirements for these BART 
determinations, as necessary to ensure their enforceability.
---------------------------------------------------------------------------

    \179\ See CAA section 110(a)(2)(F) and 40 CFR 51.212(c), 
51.308(d)(3)(v)(C) and (F).
---------------------------------------------------------------------------

a. Hayden Smelter PM10
    In its BART analysis for PM10, ASARCO relied on the 
particulate limits established in National Emission Standard for 
Hazardous Air Pollutants (NESHAP) Subpart QQQ, Primary Copper Smelting 
at 40 CFR 63.1444(d)(5) and (6).\180\ These limits and associated 
monitoring requirements formed the basis for ASARCO's BART 
determination, which ADEQ incorporated in its Regional Haze SIP.\181\ 
We are now proposing to incorporate these requirements into the FIP. In 
particular, we propose to set a limit of 6.2 mg/dscm non-sulfuric acid 
particulate matter from the primary capture system, and a limit of 23 
mg/dscm particulate matter from the secondary capture system, as 
measured using the test methods specified in 40 CFR 63.1450(b). We 
propose to require demonstration of compliance with these limits 
through the applicable procedures in 40 CFR 63.1451 and 1453.
---------------------------------------------------------------------------

    \180\ Letter from Eric Hiser, Counsel for ASARCO, to Balaji 
Vaidyanathan, ADEQ dated March 20, 2013, page 5.
    \181\ Arizona RH SIP Supplement (May 3, 2013), Appendix D, page 
23, and Section XII.
---------------------------------------------------------------------------

b. Miami Smelter PM10
    In the Arizona Regional Haze SIP, ADEQ determined that the NESHAP 
for Primary Copper Smelting constitutes BART for PM emissions from the 
Miami Smelter. Because the FMMI smelter is a major source of Hazardous 
Air Pollutants (HAPs), and therefore subject to the requirements of the 
NESHAP, these requirements are already incorporated into the facility's 
Title V permit.\182\ We propose to find that these existing, federally 
enforceable requirements are sufficient to ensure the enforceability of 
ADEQ's PM10 BART determination for the Miami Smelter.
---------------------------------------------------------------------------

    \182\ ADEQ Air Quality Class I Permit Number 53592 issued 
November 26, 2012, attachment B.
---------------------------------------------------------------------------

VIII. EPA's Proposal for Interstate Transport

    We propose that a combination of SIP and FIP measures will satisfy 
the FIP obligation for the visibility requirement of CAA section 
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, 
and 2006 PM2.5 NAAQS. As discussed in section II.B 
(``Overview of Proposed Actions; Interstate Transport of Pollutants 
that affect Visibility'') of this proposed rule, EPA disapproved 
Arizona's 2007 and 2009 Transport SIPs as well as its Regional Haze SIP 
for the interstate transport visibility protection requirement of CAA 
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 
PM2.5, and 2006 PM2.5 NAAQS. As noted in our 
proposed SIP action,\183\ we interpret the visibility requirement of 
section 110(a)(D)(i)(II) as requiring states to include in their SIPs 
either measures to prohibit emissions that would interfere with 
attaining RPGs of Class I areas in other states, or a demonstration 
that emissions from the state's sources and activities will not have 
the prohibited impacts under the existing SIP. Arizona's 2007 and 2009 
Transport SIP revisions indicated that the interstate transport 
visibility requirement should be assessed in conjunction with the 
Arizona RH SIP, but did not specify which parts of the RH SIP should be 
considered as meeting the visibility requirement of section 
110(a)(2)(D)(i)(II). Therefore we have considered the Arizona RH SIP as 
a whole in assessing whether Arizona has met this visibility 
requirement.
---------------------------------------------------------------------------

    \183\ 77 FR 75704 at 75709.
---------------------------------------------------------------------------

    As a result of the partial disapprovals of the Arizona RH SIP, we 
found that the Arizona SIP did not contain adequate provisions to 
prohibit emissions that may interfere with SIP measures required of 
other states to protect visibility. Therefore, we disapproved Arizona's 
submittals with respect to the interstate transport visibility 
requirement for the 1997 8-hour ozone, 1997 PM2.5, and 2006 
PM2.5 NAAQS, which triggered the obligation for EPA to 
promulgate a FIP under CAA section 110(c)(1). We anticipated that this 
FIP obligation could be satisfied by a combination of the State's 
measures that we previously approved and EPA's promulgation of FIPs for 
the disapproved elements of the Arizona RH SIP.\184\
---------------------------------------------------------------------------

    \184\ 77 FR 75704 at 75736.
---------------------------------------------------------------------------

    We propose to find that the combination of elements in the 
applicable RH SIPs and FIPs will contain adequate provisions to 
prohibit emissions from Arizona that would interfere with SIP measures 
required of other states to protect visibility. These elements are the 
Arizona RH SIP measures that we previously approved;\185\ the partial 
RH FIP that we promulgated on December 5, 2012;\186\ and the partial RH 
FIP we are proposing today. As explained in the LTS section, the 
combination of all of these measures will ensure that the applicable 
implementation plan (i.e., the combination of SIP and FIP measures) 
will include all of the measures needed to achieve Arizona's allotment 
of emission reductions agreed upon through the WRAP process. We propose 
that this combination of SIP and FIP measures will satisfy the FIP 
obligation for the visibility requirement of CAA section 
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5, 
and 2006 PM2.5 NAAQS.
---------------------------------------------------------------------------

    \185\ 77 FR 72512, 78 FR 46142.
    \186\ 77 FR 72512.
---------------------------------------------------------------------------

IX. Summary of EPA's Proposed Actions

A. Regional Haze

    EPA is proposing a FIP to address the remaining portions of the 
Arizona's RH SIP that we disapproved on July 30, 2013, which includes 
requirements for Best Available Retrofit Technology, Reasonable 
Progress, and the Long-term

[[Page 9365]]

Strategy. We are proposing more stringent emission limits on six 
sources that impact visibility in 17 Class I areas inside and outside 
the State. We welcome comments on all of our proposals and indicate 
specific issues or areas where feedback would be particularly useful. 
Our proposal includes compliance dates and specific requirements for 
monitoring, recordkeeping, reporting and equipment operation and 
maintenance for all of the units covered by this action as described in 
Part 52 attached to this notice. Today's proposed FIP, once finalized, 
along with previously approved SIPs and a finalized FIP, will 
constitute Arizona's regional haze program for the first planning 
period that ends in 2018.

B. Interstate Visibility Transport

    We propose that the interstate transport visibility requirement of 
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 
PM2.5, and 2006 PM2.5 NAAQS is satisfied by a 
combination of SIP and FIP elements. These elements are the Arizona RH 
SIP measures that we previously approved; the partial RH FIP that we 
promulgated on December 5, 2012; and the partial RH FIP we are 
proposing today.

X. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) 
and is therefore not subject to review under Executive Orders 12866 and 
13563 (76 FR 3821, January 21, 2011). The proposed FIP applies to only 
six facilities. It is therefore not a rule of general applicability.

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Under the Paperwork Reduction Act, a ``collection of 
information'' is defined as a requirement for ``answers to * * * 
identical reporting or recordkeeping requirements imposed on ten or 
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP 
applies to just six facilities, the Paperwork Reduction Act does not 
apply. See 5 CFR 1320(c). Burden means the total time, effort, or 
financial resources expended by persons to generate, maintain, retain, 
or disclose or provide information to or for a Federal agency. This 
includes the time needed to review instructions; develop, acquire, 
install, and utilize technology and systems for the purposes of 
collecting, validating, and verifying information, processing and 
maintaining information, and disclosing and providing information; 
adjust the existing ways to comply with any previously applicable 
instructions and requirements; train personnel to be able to respond to 
a collection of information; search data sources; complete and review 
the collection of information; and transmit or otherwise disclose the 
information. An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid Office of Management and Budget (OMB) control number. 
The OMB control numbers for our regulations in 40 CFR are listed in 40 
CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions. For purposes 
of assessing the impacts of today's proposed rule on small entities, 
small entity is defined as: (1) A small business as defined by the 
Small Business Administration's (SBA) regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for 
profit enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of this proposed action on 
small entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
None of the facilities subject to this proposed rule is owned by a 
small entity.\187\ We continue to be interested in the potential 
impacts of the proposed rule on small entities and welcome comments on 
issues related to such impacts.
---------------------------------------------------------------------------

    \187\ See Regulatory Flexibility Act Screening Analysis for 
Proposed Arizona Regional Haze Federal Implementation Plan (EPA-R09-
OAR-2013-0588).
---------------------------------------------------------------------------

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more 
(adjusted for inflation) in any 1 year. Before promulgating an EPA rule 
for which a written statement is needed, section 205 of UMRA generally 
requires EPA to identify and consider a reasonable number of regulatory 
alternatives and adopt the least costly, most cost-effective, or least 
burdensome alternative that achieves the objectives of the rule. The 
provisions of section 205 of UMRA do not apply when they are 
inconsistent with applicable law. Moreover, section 205 of UMRA allows 
EPA to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before EPA establishes any regulatory requirements that 
may significantly or uniquely affect small governments, including 
Tribal governments, it must have developed under section 203 of UMRA a 
small government agency plan. The plan must provide for notifying 
potentially affected small governments, enabling officials of affected 
small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    Under Title II of UMRA, EPA has determined that this proposed rule 
does not contain a Federal mandate that may result in expenditures that 
exceed the inflation-adjusted UMRA threshold of $100 million by State, 
local, or Tribal governments or the private sector in any 1 year. In 
addition, this proposed rule does not contain a significant Federal 
intergovernmental mandate as described by section 203 of UMRA nor does 
it contain any regulatory requirements that might significantly or 
uniquely affect small governments.\188\
---------------------------------------------------------------------------

    \188\ See ``Summary of EPA BART Cost Estimates'' in the docket.

---------------------------------------------------------------------------

[[Page 9366]]

E. Executive Order 13132: Federalism

    Executive Order 13132 Federalism (64 FR 43255, August 10, 1999) 
revokes and replaces Executive Orders 12612 (Federalism) and 12875 
(Enhancing the Intergovernmental Partnership). Executive Order 13132 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by State and local officials in the development of 
regulatory policies that have federalism implications.'' ``Policies 
that have federalism implications'' is defined in the Executive Order 
to include regulations that have ``substantial direct effects on the 
States, on the relationship between the national government and the 
States, or on the distribution of power and responsibilities among the 
various levels of government.'' Under Executive Order 13132, EPA may 
not issue a regulation that has federalism implications, that imposes 
substantial direct compliance costs, and that is not required by 
statute, unless the Federal government provides the funds necessary to 
pay the direct compliance costs incurred by State and local 
governments, or EPA consults with State and local officials early in 
the process of developing the proposed regulation. EPA also may not 
issue a regulation that has federalism implications and that preempts 
State law unless the Agency consults with State and local officials 
early in the process of developing the proposed regulation.
    This rule will not have substantial direct effects on the states, 
on the relationship between the national government and the states, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132. In this 
action, EPA is fulfilling our statutory duty under CAA Section 110(c) 
to promulgate a partial Regional Haze FIP. Thus, Executive Order 13132 
does not apply to this action. In the spirit of Executive Order 13132, 
and consistent with EPA policy to promote communications between EPA 
and State and local governments, EPA specifically solicits comment on 
this proposed rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Subject to the Executive Order 13175 (65 FR 67249, November 9, 
2000) EPA may not issue a regulation that has tribal implications, that 
imposes substantial direct compliance costs, and that is not required 
by statute, unless the Federal government provides the funds necessary 
to pay the direct compliance costs incurred by tribal governments, or 
EPA consults with tribal officials early in the process of developing 
the proposed regulation and develops a tribal summary impact statement.
    EPA has concluded that this action, if finalized, will have tribal 
implications, because it will impose substantial direct compliance 
costs on tribal governments, and the Federal government will not 
provide the funds necessary to pay those costs. PCC is a division of 
Salt River Pima Maricopa Indian Community (SRPMIC or the Community) and 
profits from the Phoenix Cement Clarkdale Plant are used to provide 
government services to SRPMIC's members. Therefore, EPA is providing 
the following tribal summary impact statement as required by section 
5(b).
    EPA consulted with tribal officials early in the process of 
developing this regulation to permit them to have meaningful and timely 
input into its development. In November 2012, we shared our initial 
analyses with SRPMIC and PCC to ensure that the tribe had an early 
opportunity to provide feedback on potential controls at the Clarkdale 
Plant. PCC submitted comments on this initial analysis as part of the 
rulemaking on the Arizona Regional Haze SIP and we revised our initial 
analysis based on these comments. On November 6, 2013, the EPA Region 9 
Regional Administrator met with the President and other representatives 
of SRPMIC to discuss the potential impacts of the FIP on SRPMIC. 
Following this meeting, staff from EPA, SPRMIC and PCC shared further 
information regarding the Plant and potential impacts of the FIP on 
SRPMIC.\189\
---------------------------------------------------------------------------

    \189\ See Memorandum to Docket: Summary of Communications and 
Consultation between EPA, PCC and SRPMIC (January 27, 2014).
---------------------------------------------------------------------------

    During these consultations, SRPMIC expressed its concern regarding 
the potential financial impacts of any new controls that might be 
required at the Clarkdale Plant. In particular, SRPMIC requested that 
EPA provide PCC with an extended compliance schedule for any controls 
in order to enable PCC and SRPMIC to plan for such controls in their 
long-term budgets and thus mitigate the potential impacts to the 
Community.\190\ However, SRPMIC provided only limited information 
documenting the potential for such impacts and claimed all such 
information as CBI.
    As explained above, EPA is proposing to determine that it is 
reasonable to require installation of SNCR at Kiln 4 at the Clarkdale 
Plant by December 31, 2018. EPA is also seeking comment on the 
possibility of establishing an annual cap on NOX emissions 
from Kiln 4 in lieu of a lb/ton emission limit. An annual cap would 
allow SRPMIC to delay installation of controls until the Plant's 
production returns to pre-recession levels and would thus help to 
address the Community's concerns about the budgetary impacts of control 
requirements. EPA specifically solicits additional comment on this 
proposed rule from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) Is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. EPA interprets EO 13045 as 
applying only to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the EO 
has the potential to influence the regulation. This action is not 
subject to EO 13045 because it implements specific standards 
established by Congress in statutes. However, to the extent this 
proposed rule will limit emissions of NOX, SO2 
and PM, the rule will have a beneficial effect on children's health by 
reducing air pollution.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act 
(NTTAA) of 1995 requires Federal agencies to evaluate existing 
technical standards when developing a new regulation. To comply with 
NTTAA, EPA must consider and use ``voluntary consensus standards'' 
(VCS) if available and applicable when developing programs and policies 
unless doing so would be inconsistent with applicable law or otherwise 
impractical. EPA believes that VCS are inapplicable to this action. 
Today's action does not

[[Page 9367]]

require the public to perform activities conducive to the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    We have determined that this proposed rule, if finalized, will not 
have disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse human health or 
environmental effects on any population, including any minority or low-
income population. This proposed federal rule limits emissions of 
NOX and SO2 from six facilities in Arizona.

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by 
reference, Intergovernmental relations, Nitrogen oxides, Sulfur 
dioxide, Particulate matter, Reporting and recordkeeping requirements, 
Visibility, Volatile organic compounds.

    Authority: 42 U.S.C. 7401 et seq.

    Dated: January 27, 2014.
Jared Blumenfeld,
Regional Administrator, Region 9.

    Part 52, chapter I, title 40 of the Code of Federal Regulations is 
proposed to be amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart D--Arizona

0
2. Amend Sec.  52.145 by adding paragraphs (i), (j), (k), (l) and (m) 
to read as follow:


Sec.  52.145  Visibility protection.

* * * * *
    (i) Source-specific federal implementation plan for regional haze 
at Nelson Lime Plant--(1) Applicability. This paragraph (i) applies to 
the owner/operator of the lime kilns designated as Kiln 1 and Kiln 2 at 
the Nelson Lime Plant located in Yavapai County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (i)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (i):
    Ammonia injection shall include any of the following: anhydrous 
ammonia, aqueous ammonia or urea injection.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of NOX emissions, SO2 emissions, diluent, 
or stack gas volumetric flow rate.
    Kiln 1 means rotary kiln 1, as identified in paragraph (i)(1) of 
this section.
    Kiln 2 means rotary kiln 2, as identified in paragraph (i)(1) of 
this section.
    Kiln operating day means a 24-hour period between 12 midnight and 
the following midnight during which the kiln operates.
    Lime product means the product of the lime kiln calcination process 
including calcitic lime, dolomitic lime, and dead-burned dolomite.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises a kiln identified in paragraph (i)(1) of this section.
    SO2 means sulfur dioxide.
    Unit means any of the kilns identified in paragraph (i)(1) of this 
section.
    (3) Emission limitations. The owner/operator of each kiln 
identified in paragraph (i)(1) of this section shall not emit or cause 
to be emitted pollutants in excess of the following limitations, in 
pounds of pollutant per ton of lime product (lb/ton), from any kiln. 
Each emission limit shall be based on a rolling 30 kiln-operating day 
basis.

------------------------------------------------------------------------
                                             Pollutant emission limit
                 Kiln ID                 -------------------------------
                                                NOX             SO2
------------------------------------------------------------------------
Kiln 1..................................            3.80            9.32
Kiln 2..................................            2.61            9.73
------------------------------------------------------------------------

    (4) Compliance dates. (i) The owner/operator of each unit shall 
comply with the NOX emissions limitations and other 
NOX-related requirements of this paragraph (i) no later than 
(three years after date of publication of the final rule in the Federal 
Register).
    (ii) The owner/operator of each unit shall comply with the 
SO2 emissions limitations and other SO2-related 
requirements of this paragraph (i) no later than (six months after date 
of publication of the final rule in the Federal Register).
    (5) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance dates specified in paragraph 
(i)(4) of this section, the owner/operator of Kiln 1 and 2 shall 
maintain, calibrate, and operate a CEMS, in full compliance with the 
requirements found at 40 CFR 60.13 and 40 CFR Part 60, Appendices B and 
F, to accurately measure the mass emission rate of NOX and 
SO2, in pounds per hour, from Kiln 1 and 2. The CEMS shall 
be used by the owner/operator to determine compliance with the emission 
limitations in paragraph (i)(3) of this section, in combination with 
data on actual lime production. The owner/operator must operate the 
monitoring system and collect data at all required intervals at all 
times that an affected unit is operating, except for periods of 
monitoring system malfunctions, repairs associated with monitoring 
system malfunctions, and required monitoring system quality assurance 
or quality control activities (including, as applicable, calibration 
checks and required zero and span adjustments).
    (ii) Ammonia consumption monitoring. Upon and after the completion 
of installation of ammonia injection on a unit, the owner or operator 
shall install, and thereafter maintain and operate, instrumentation to 
continuously monitor and record levels of ammonia consumption for that 
unit.
    (iii) Compliance determination for NOX. Compliance with the 
NOX emission limit described in paragraph (i)(3) of this 
section shall be determined based on a rolling 30 kiln-operating day 
basis. The 30-day rolling NOX emission rate for each kiln 
shall be calculated for each kiln operating day in accordance with the 
following procedure: Step one, sum the hourly pounds of NOX 
emitted for the current kiln operating day and the preceding twenty-
nine (29) kiln operating days, to calculate the total pounds of 
NOX emitted over the most recent thirty (30) kiln operating 
day period for that kiln; Step two, sum the total lime product, in 
tons, produced during the current kiln operating day and the preceding 
twenty-nine (29) kiln operating days, to calculate the total lime 
product produced over the most

[[Page 9368]]

recent thirty (30) kiln operating day period for that kiln; Step three, 
divide the total amount of NOX calculated from Step one by 
the total lime product calculated from Step two to calculate the 30-day 
rolling NOX emission rate for that kiln. Each 30-day rolling 
NOX emission rate shall include all emissions and all lime 
product that occur during all periods within any kiln operating day, 
including emissions from startup, shutdown and malfunction.
    (iv) Compliance determination for SO2. Compliance with the 
SO2 emission limit described in paragraph (i)(3) of this 
section shall be determined based on a rolling 30 kiln-operating day 
basis. The 30-day rolling SO2 emission rate for each kiln 
shall be calculated for each kiln operating day in accordance with the 
following procedure: Step one, sum the hourly pounds of SO2 
emitted for the current kiln operating day and the preceding twenty-
nine (29) kiln operating days, to calculate the total pounds of 
SO2 emitted over the most recent thirty (30) kiln operating 
day period for that kiln; Step two, sum the total lime product, in 
tons, produced during the current kiln operating day and the preceding 
twenty-nine (29) kiln operating days, to calculate the total lime 
product produced over the most recent thirty (30) kiln operating day 
period for that kiln; Step three, divide the total amount of 
SO2 calculated from Step one by the total lime product 
calculated from Step two to calculate the 30-day rolling SO2 
emission rate for that kiln. Each 30-day rolling SO2 
emission rate shall include all emissions and all lime product that 
occur during all periods within any kiln operating day, including 
emissions from startup, shutdown and malfunction.
    (6) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) All records of lime production.
    (iii) Daily 30-day rolling emission rates of NOX and 
SO2, when applicable, calculated in accordance with 
paragraphs (i)(5)(iii) and (iv) of this section.
    (iv) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (v) Records of ammonia consumption, as recorded by the 
instrumentation required in paragraph (i)(5)(ii) of this section.
    (vi) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, CEMS and clinker 
production measurement devices.
    (vii) Any other records required by 40 CFR part 60, Subpart F, or 
40 CFR part 60, Appendix F, Procedure 1.
    (7) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date(s) in paragraph (i)(4) of this section and 
at least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
30-day rolling emission rates for NOX and SO2.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX and SO2 limits. Excess emissions means 
emissions that exceed the emissions limits specified in paragraph 
(i)(3) of this section. The reports shall include the magnitude, 
date(s), and duration of each period of excess emissions, specific 
identification of each period of excess emissions that occurs during 
startups, shutdowns, and malfunctions of the unit, the nature and cause 
of any malfunction (if known), and the corrective action taken or 
preventative measures adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the semiannual report.
    (8) Notifications. (i) The owner/operator shall notify EPA of 
commencement of construction of any equipment which is being 
constructed to comply with the NOX emission limits in 
paragraph (i)(3) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (9) Equipment operations. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the kiln.
    (ii) After completion of installation of ammonia injection on a 
unit, the owner or operator shall inject sufficient ammonia to achieve 
compliance with NOX emission limits from paragraph (i)(3) 
for that unit while preventing excessive ammonia emissions.
    (10) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (11) Affirmative defense for malfunctions. The following provisions 
of the Arizona Administrative Code are incorporated by reference and 
made part of this Federal implementation plan:
    (i) R-18-2-101, paragraph 65;
    (ii) R18-2-310, sections (A), (B), (D) and (E) only; and
    (iii) R18-2-310.01.
    (j) Source-specific federal implementation plan for regional haze 
at H. Wilson Sundt Generating Station--(1) Applicability. This 
paragraph (j) applies to the owner and operator of the electricity 
generating unit (EGU) designated as Unit I4 at the H. Wilson

[[Page 9369]]

Sundt Generating Station located in Tucson, Pima County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (j)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (j):
    Ammonia injection shall include any of the following: anhydrous 
ammonia, aqueous ammonia or urea injection.
    Boiler operating day means a 24-hour period between 12 midnight and 
the following midnight during which any fuel is combusted at any time 
in the unit.
    Continuous emission monitoring system or CEMS means the equipment 
required by 40 CFR Part 75 and this paragraph (j).
    MMBtu means one million British thermal units.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the EGU identified in paragraph (j)(1) of this section.
    Pipeline natural gas means a naturally occurring fluid mixture of 
hydrocarbons as defined in 40 CFR 72.2.
    PM means total filterable particulate matter.
    PM10 means total particulate matter less than 10 microns 
in diameter.
    SO2 means sulfur dioxide.
    Unit means the EGU identified paragraph (j)(1) of this section.
    (3) Emission limitations. The owner/operator of the unit shall not 
emit or cause to be emitted pollutants in excess of the following 
limitations, in pounds of pollutant per million british thermal units 
(lb/MMBtu), from the subject unit.

------------------------------------------------------------------------
                                                      Pollutant emission
                      Pollutant                              limit
------------------------------------------------------------------------
NOX.................................................                0.36
PM..................................................               0.030
SO2.................................................                0.23
------------------------------------------------------------------------

    (4) Alternative emission limitations. The owner/operator of the 
unit may choose to comply with the following limitations in lieu of the 
emission limitations listed in paragraph (j)(3).
    (i) The owner/operator of the unit shall combust only pipeline 
natural gas in the subject unit.
    (ii) The owner/operator of the unit shall not emit or cause to be 
emitted pollutants in excess of the following limitations, in pounds of 
pollutant per million british thermal units (lb/MMBtu), from the 
subject unit.

------------------------------------------------------------------------
                                                      Pollutant emission
                      Pollutant                              limit
------------------------------------------------------------------------
NOX.................................................                0.25
PM10................................................               0.010
SO2.................................................             0.00064
------------------------------------------------------------------------

    (5) Compliance dates. (i) The owner/operator of the unit subject to 
this paragraph shall comply with the NOX and SO2 
emissions limitations of paragraph (j)(3) of this section no later than 
(three years after date of publication of the final rule in the Federal 
Register).
    (ii) The owner/operator of the unit subject to this paragraph shall 
comply with the PM emissions limitations of paragraph (j)(3) of this 
section no later than April 16, 2015.
    (6) Alternative compliance dates. If the owner/operator chooses to 
comply with the emission limits of paragraph (j)(4) of this section in 
lieu of paragraph (j)(3) of this section, the owner/operator of the 
unit shall comply with the NOX, SO2 and 
PM10 emissions limitations of paragraph (j)(4) no later than 
December 31, 2017.
    (7) Compliance determination--(i) Continuous emission monitoring 
system. (A) At all times after the compliance date specified in 
paragraph (j)(5)(i) of this section, the owner/operator of the unit 
shall maintain, calibrate, and operate a CEMS, in full compliance with 
the requirements found at 40 CFR Part 75, to accurately measure 
SO2, NOX, diluent, and stack gas volumetric flow 
rate from the unit. All valid CEMS hourly data shall be used to 
determine compliance with the emission limitations for NOX 
and SO2 in paragraph (j)(3) of this section. When the CEMS 
is out-of-control as defined by Part 75, that CEMs data shall be 
treated as missing data and not used to calculate the emission average. 
Each required CEMS must obtain valid data for at least 90 percent of 
the unit operating hours, on an annual basis.
    (B) The owner/operator of the unit shall comply with the quality 
assurance procedures for CEMS found in 40 CFR Part 75. In addition to 
these Part 75 requirements, relative accuracy test audits shall be 
calculated for both the NOX and SO2 pounds per 
hour measurement and the heat input measurement. The CEMs monitoring 
data shall not be bias adjusted. Calculations of relative accuracy for 
lb/hr of NOX, SO2 and heat input shall be 
performed each time the Part 75 CEMS undergo relative accuracy testing.
    (ii) Ammonia consumption monitoring. Upon and after the completion 
of installation of ammonia injection on the unit, the owner or operator 
shall install, and thereafter maintain and operate, instrumentation to 
continuously monitor and record levels of ammonia consumption for that 
unit.
    (iii) Compliance determination for NOX. Compliance with 
the NOX emission limit described in paragraph (j)(3) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The 30-day rolling NOX emission rate for the unit 
shall be calculated for each boiler operating day in accordance with 
the following procedure: Step one, sum the hourly pounds of 
NOX emitted for the current boiler operating day and the 
preceding twenty-nine (29) boiler operating days, to calculate the 
total pounds of NOX emitted over the most recent thirty (30) 
boiler operating day period for that unit; Step two, sum the total heat 
input, in millions of BTU, during the current boiler operating day and 
the preceding twenty-nine (29) boiler operating days, to calculate the 
total heat input over the most recent thirty (30) boiler operating day 
period for that unit; Step three, divide the total amount of 
NOX calculated from Step one by the total heat input 
calculated from Step two to calculate the 30-day rolling NOX 
emission rate, in pounds per million BTU for that unit. Each 30-day 
rolling NOX emission rate shall include all emissions and 
all heat input that occur during all periods within any boiler 
operating day, including emissions from startup, shutdown and 
malfunction. If a valid NOX pounds per hour or heat input is 
not available for any hour for the unit, that heat input and 
NOX pounds per hour shall not be used in the calculation of 
the 30-day rolling emission rate.
    (iv) Compliance determination for SO2. Compliance with 
the SO2 emission limit described in paragraph (j)(3) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The 30-day rolling SO2 emission rate for the unit 
shall be calculated for each boiler operating day in accordance with 
the following procedure: Step one, sum the hourly pounds of 
SO2 emitted for the current boiler operating day and the 
preceding twenty-nine (29) boiler operating days, to calculate the 
total pounds of SO2 emitted over the most recent thirty (30) 
boiler operating day period for that unit; Step two, sum the total heat 
input, in millions of BTU, during the current boiler operating day and 
the preceding twenty-nine (29) boiler operating days, to calculate the 
total heat input over the most recent thirty (30) boiler operating day 
period for that unit; Step three, divide the total amount of 
SO2 calculated from Step one by the total heat input 
calculated from

[[Page 9370]]

Step two to calculate the 30-day rolling SO2 emission rate, 
in pounds per million BTU for that unit. Each 30-day rolling 
SO2 emission rate shall include all emissions and all heat 
input that occur during all periods within any boiler operating day, 
including emissions from startup, shutdown and malfunction. If a valid 
SO2 pounds per hour or heat input is not available for any 
hour for the unit, that heat input and SO2 pounds per hour 
shall not be used in the calculation of the 30-day rolling emission 
rate.
    (v) Compliance determination for PM. Compliance with the PM 
emission limit described in paragraph (j)(3) shall be determined from 
annual performance stack tests. Within sixty (60) days either preceding 
or following the compliance deadline specified in paragraph (j)(5)(ii) 
of this section, and on at least an annual basis thereafter, the owner/
operator of the unit shall conduct a stack test on the unit to measure 
PM using EPA Method 5, in 40 CFR part 60, Appendix A. Each test shall 
consist of three runs, with each run at least 120 minutes in duration 
and each run collecting a minimum sample of 60 dry standard cubic feet. 
Results shall be reported in lb/MMBtu using the calculation in 40 CFR 
Part 60 Appendix A, Method 19.
    (8) Alternative compliance determination. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, this paragraph may be used in lieu of paragraph (j)(7) of this 
section to demonstrate compliance with the emission limits in paragraph 
(j)(4).
    (i) Continuous emission monitoring system. (A) At all times after 
the compliance date specified in paragraph (j)(6) of this section, the 
owner/operator of the unit shall maintain, calibrate, and operate a 
CEMS, in full compliance with the requirements found at 40 CFR part 75, 
to accurately measure NOX, diluent, and stack gas volumetric 
flow rate from the unit. All valid CEMS hourly data shall be used to 
determine compliance with the emission limitations for NOX 
in paragraph (j)(4) of this section. When the CEMS is out-of-control as 
defined by Part 75, that CEMS data shall be treated as missing data and 
not used to calculate the emission average. Each required CEMS must 
obtain valid data for at least 90 percent of the unit operating hours, 
on an annual basis.
    (B) The owner/operator of the unit shall comply with the quality 
assurance procedures for CEMS found in 40 CFR part 75. In addition to 
these part 75 requirements, relative accuracy test audits shall be 
calculated for both the NOX pounds per hour measurement and 
the heat input measurement. The CEMS monitoring data shall not be bias 
adjusted. Calculations of relative accuracy for lb/hr of NOX 
and heat input shall be performed each time the Part 75 CEMS undergo 
relative accuracy testing.
    (ii) Compliance determination for NOX. Compliance with the 
NOX emission limit described in paragraph (j)(4) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The 30-day rolling NOX emission rate for the unit 
shall be calculated for each boiler operating day in accordance with 
the following procedure: Step one, sum the hourly pounds of 
NOX emitted for the current boiler operating day and the 
preceding twenty-nine (29) boiler operating days, to calculate the 
total pounds of NOX emitted over the most recent thirty (30) 
boiler operating day period for that unit; Step two, sum the total heat 
input, in millions of BTU, during the current boiler operating day and 
the preceding twenty-nine (29) boiler operating days, to calculate the 
total heat input over the most recent thirty (30) boiler operating day 
period for that unit; Step three, divide the total amount of 
NOX calculated from Step one by the total heat input 
calculated from Step two to calculate the 30-day rolling NOX 
emission rate, in pounds per million BTU for that unit. Each 30-day 
rolling NOX emission rate shall include all emissions and 
all heat input that occur during all periods within any boiler 
operating day, including emissions from startup and shutdown. If a 
valid NOX pounds per hour or heat input is not available for 
any hour for the unit, that heat input and NOX pounds per 
hour shall not be used in the calculation of the 30-day rolling 
emission rate.
    (iii) Compliance determination for SO2. Compliance with the 
SO2 emission limit for the unit shall be determined from 
fuel sulfur documentation demonstrating the use of pipeline natural 
gas.
    (iv) Compliance determination for PM10. Compliance with the 
PM10 emission limit for the unit shall be determined from 
performance stack tests. Within sixty (60) days following the 
compliance deadline specified in paragraph (j)(6) of this section, and 
at the request of the Regional Administrator thereafter, the owner/
operator of the unit shall conduct a stack test on the unit to measure 
PM10 using EPA Method 201A and Method 202, per 40 CFR part 
51, Appendix M. Each test shall consist of three runs, with each run at 
least 120 minutes in duration and each run collecting a minimum sample 
of 60 dry standard cubic feet. Results shall be reported in lb/MMBtu 
using the calculation in 40 CFR part 60 Appendix A, Method 19.
    (9) Recordkeeping. The owner or operator shall maintain the 
following records for at least five years:
    (i) CEMS data measuring NOX in lb/hr, SO2 in 
lb/hr, and heat input rate per hour.
    (ii) Daily 30-day rolling emission rates of NOX and 
SO2 calculated in accordance with paragraphs (j)(7)(iii) and 
(iv) of this section.
    (iii) Records of the relative accuracy test for NOX lb/
hr and SO2 lb/hr measurement, and hourly heat input 
measurement.
    (iv) Records of quality assurance and quality control activities 
for emissions systems including, but not limited to, any records 
required by 40 CFR part 75.
    (v) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (vi) Any other records required by 40 CFR part 75.
    (vii) Records of ammonia consumption for the unit, as recorded by 
the instrumentation required in paragraph (j)(7)(ii) of this section.
    (viii) All PM stack test results.
    (10) Alternative recordkeeping requirements. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, the owner/operator shall maintain the records listed in this 
paragraph in lieu of the records contained in paragraph (j)(9) of this 
section. The owner or operator shall maintain the following records for 
at least five years:
    (i) CEMS data measuring NOX in lb/hr and heat input rate 
per hour.
    (ii) Daily 30-day rolling emission rates of NOX 
calculated in accordance with paragraph (j)(8)(ii) of this section.
    (iii) Records of the relative accuracy test for NOX lb/
hr measurement and hourly heat input measurement.
    (iv) Records of quality assurance and quality control activities 
for emissions systems including, but not limited to, any records 
required by 40 CFR part 75.
    (v) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (vi) Any other records required by 40 CFR part 75.
    (vii) Records sufficient to demonstrate that the fuel for the unit 
is pipeline natural gas.
    (viii) All PM10 stack test results.
    (11) Notifications. (i) By July 31, 2015, the owner/operator shall 
notify the Regional Administrator by letter whether it will comply with 
the emission limits in paragraph (j)(3) of this section or whether it 
will comply

[[Page 9371]]

with the emission limits in paragraph (j)(4) of this section.
    (ii) The owner/operator shall notify EPA of commencement of 
construction of any equipment which is being constructed to comply with 
either the NOX or SO2 emission limits in 
paragraph (j)(3) of this section.
    (iii) The owner/operator shall submit semiannual progress reports 
on construction of any such equipment.
    (iv) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (12) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date(s) in paragraph (j)(5) of this section and 
at least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
30-day rolling emission rates for NOX and SO2.
    (ii) The owner/operator shall submit excess emission reports for 
NOX and SO2 limits. Excess emissions means 
emissions that exceed the emissions limits specified in paragraph 
(j)(3) of this section. Excess emission reports shall include the 
magnitude, date(s), and duration of each period of excess emissions, 
specific identification of each period of excess emissions that occurs 
during startups, shutdowns, and malfunctions of the unit, the nature 
and cause of any malfunction (if known), and the corrective action 
taken or preventative measures adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall submit the results of any relative 
accuracy test audits performed during the two preceding calendar 
quarters.
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the semiannual report.
    (vi) The owner/operator shall submit results of any PM stack tests 
conducted for demonstrating compliance with the PM limit specified in 
paragraph (j)(3).
    (13) Alternative reporting requirements. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, the owner/operator shall submit the reports listed in this 
paragraph in lieu of the reports contained in paragraph (j)(12) of this 
section. All reports required under this paragraph shall be submitted 
by the owner/operator to the Director, Enforcement Division (Mail Code 
ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne 
Street, San Francisco, California 94105-3901. All reports required 
under this paragraph shall be submitted within 30 days after the 
applicable compliance date(s) in paragraph (j)(6) of this section and 
at least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
30-day rolling emission rates for NOX.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX limits. Excess emissions means emissions that exceed the 
emissions limits specified in paragraph (j)(4) of this section. The 
reports shall include the magnitude, date(s), and duration of each 
period of excess emissions, specific identification of each 
period of excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall submit the results of any relative 
accuracy test audits performed during the two preceding calendar 
quarters.
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the semiannual report.
    (vi) The owner/operator shall submit results of any PM10 
stack tests conducted for demonstrating compliance with the 
PM10 limit specified in paragraph (j)(4) of this section.
    (14) Equipment operations. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (ii) After completion of installation of ammonia injection on a 
unit, the owner or operator shall inject sufficient ammonia to achieve 
compliance with NOX emission limits contained in paragraph 
(j)(3) of this section for that unit while preventing excessive ammonia 
emissions.
    (15) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (16) Affirmative defense for malfunctions. The following provisions 
of the Arizona Administrative Code are incorporated by reference and 
made part of this federal implementation plan:
    (i) R-18-2-101, paragraph 65;
    (ii) R18-2-310, sections (A), (B), (D) and (E) only; and
    (iii) R18-2-310.01.
    (k) Source-specific federal implementation plan for regional haze 
at Clarkdale Cement Plant and Rillito Cement Plant--(1) Applicability. 
This

[[Page 9372]]

paragraph (k) applies to each owner/operator of the following cement 
kilns in the state of Arizona: Kiln 4 located at the cement plant in 
Clarkdale, Arizona, and Kiln 4 located at the cement plant in Rillito, 
Arizona.
    (2) Definitions. Terms not defined in this paragraph (k)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (k):
    Ammonia injection shall include any of the following: Anhydrous 
ammonia, aqueous ammonia or urea injection.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of NOX emissions, diluent, or stack gas volumetric 
flow rate.
    Kiln operating day means a 24-hour period between 12 midnight and 
the following midnight during which the kiln operates.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises a cement kiln identified in paragraph (k)(1) of this 
section.
    Unit means a cement kiln identified in paragraph (k)(1) of this 
section.
    (3) Emissions limitations. The owner/operator of each unit 
identified in paragraph (k)(1) of this section shall not emit or cause 
to be emitted NOX in excess of the following limitations, in 
pounds per ton of clinker produced, based on a rolling 30-kiln 
operating day basis.

------------------------------------------------------------------------
                                                           NOX emission
                      Cement Kiln                           limitation
------------------------------------------------------------------------
Clarkdale Plant, Kiln 4................................             2.12
Rillito Plant, Kiln 4..................................             2.67
------------------------------------------------------------------------

    (4) Compliance date. The owner/operator of each unit identified in 
paragraph (k)(i) of this section shall comply with the NOX 
emissions limitations and other NOX-related requirements of 
this paragraph (k) no later than (three years after date of publication 
of the final rule in the Federal Register).
    (5) Compliance determination--(i) Continuous emission monitoring 
system. (A) At all times after the compliance date specified in 
paragraph (k)(4) of this section, the owner/operator of the unit at the 
Clarkdale Plant shall maintain, calibrate, and operate a CEMS, in full 
compliance with the requirements found at 40 CFR 60.63(f) and (g), to 
accurately measure concentration by volume of NOX, diluent, 
and stack gas volumetric flow rate from the in-line/raw mill stack, as 
well as the stack gas volumetric flow rate from the coal mill stack. 
The CEMS shall be used by the owner/operator to determine compliance 
with the emission limitation in paragraph (k)(3) of this section, in 
combination with data on actual clinker production. The owner/operator 
must operate the monitoring system and collect data at all required 
intervals at all times the affected unit is operating, except for 
periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions, and required monitoring system quality 
assurance or quality control activities (including, as applicable, 
calibration checks and required zero and span adjustments).
    (B) At all times after the compliance date specified in paragraph 
(k)(4) of this section, the owner/operator of the unit at the Rillito 
Plant shall maintain, calibrate, and operate a CEMS, in full compliance 
with the requirements found at 40 CFR 60.63(f) and (g), to accurately 
measure concentration by volume of NOX, diluent, and stack 
gas volumetric flow rate from the unit. The CEMS shall be used by the 
owner/operator to determine compliance with the emission limitation in 
paragraph (k)(3) of this section, in combination with data on actual 
clinker production. The owner/operator must operate the monitoring 
system and collect data at all required intervals at all times the 
affected unit is operating, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments).
    (ii) Methods. (A) The owner/operator of each unit shall record the 
daily clinker production rates.
    (B)(1) The owner/operator of each unit shall calculate and record 
the 30-kiln operating day average emission rate of NOX, in 
lb/ton of clinker produced, as the total of all hourly emissions data 
for the cement kiln in the preceding 30-kiln operating days, divided by 
the total tons of clinker produced in that kiln during the same 30-day 
operating period, using the following equation:
[GRAPHIC] [TIFF OMITTED] TP18FE14.000

Where:

ED = 30 kiln operating day average emission rate of 
NOX, lb/ton of clinker;
Ci = Concentration of NOX for hour i, ppm;
Qi = volumetric flow rate of effluent gas for hour i, 
where Ci and Qi are on the same basis (either 
wet or dry), scf/hr;
Pi = total kiln clinker produced during production hour 
i, ton/hr;
k = conversion factor, 1.194 x 10-7 for NOX; 
and.
n = number of kiln operating hours over 30 kiln operating days, n = 
1 to 720.

    (2) For each kiln operating hour for which the owner/operator does 
not have at least one valid 15-minute CEMS data value, the owner/
operator must use the average emissions rate (lb/hr) from the most 
recent previous hour for which valid data are available. Hourly clinker 
production shall be determined by the owner/operator in accordance with 
the requirements found at 40 CFR 60.63(b).
    (C) At the end of each kiln operating day, the owner/operator shall 
calculate and record a new 30-day rolling average emission rate in lb/
ton clinker from the arithmetic average of all valid hourly emission 
rates for the current kiln operating day and the previous 29 successive 
kiln operating days.
    (D) Upon and after the completion of installation of ammonia 
injection on a unit, the owner/operator shall install, and thereafter 
maintain and operate, instrumentation to continuously monitor and 
record levels of ammonia consumption that unit.
    (6) Recordkeeping. The owner/operator of each unit shall maintain 
the following records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) All records of clinker production.
    (iii) Daily 30-day rolling emission rates of NOX, 
calculated in accordance with paragraph (k)(5)(ii) of this section.
    (iv) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (v) Records of ammonia consumption, as recorded by the 
instrumentation required in paragraph (k)(5)(ii)(D) of this section.
    (vi) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, CEMS and clinker 
production measurement devices.
    (vii) Any other records required by 40 CFR part 60, Subpart F, or 
40 CFR part 60, Appendix F, Procedure 1.
    (7) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mailcode ENF-

[[Page 9373]]

2-1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne 
Street, San Francisco, California 94105-3901. All reports required 
under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (k)(4) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
30-day rolling emission rates for NOX.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX limits. Excess emissions means emissions that exceed the 
emissions limits specified in paragraph (k)(3) of this section. The 
reports shall include the magnitude, date(s), and duration of each 
period of excess emissions, specific identification of each period of 
excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the reports required by 
paragraph (k)(7)(ii) of this section.
    (8) Notifications. (i) The owner/operator shall submit notification 
of commencement of construction of any equipment which is being 
constructed to comply with the NOX emission limits in 
paragraph (k)(3) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (9) Equipment operation. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (ii) After completion of installation of ammonia injection on a 
unit, the owner or operator shall inject sufficient ammonia to achieve 
compliance with NOX emission limits from paragraph (k)(3) 
for that unit while preventing excessive ammonia emissions.
    (10) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (11) Affirmative defense for malfunctions. The following provisions 
of the Arizona Administrative Code are incorporated by reference and 
made part of this Federal implementation plan:
    (i) R-18-2-101, paragraph 65;
    (ii) R18-2-310, sections (A), (B), (D) and (E) only; and
    (iii) R18-2-310.01.
    (l) Source-specific federal implementation plan for regional haze 
at Hayden Copper Smelter--(1) Applicability. This paragraph (l) applies 
to each owner/operator of each batch copper converter and anode 
furnaces 1 and 2 at the copper smelting plant located 
in Hayden, Gila County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (l)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (l):
    Anode furnace means a furnace in which molten blister copper is 
refined through introduction of a reducing agent such as natural gas.
    Batch copper converter means a Pierce-Smith converter or Hoboken 
converter in which copper matte is oxidized to form blister copper by a 
process that is performed in discrete batches using a sequence of 
charging, blowing, skimming, and pouring.
    Blister copper means an impure form of copper, typically between 98 
and 99 percent pure copper that is the output of the converters.
    Calendar day means a 24 hour period that begins and ends at 
midnight, local standard time.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of SO2 emissions, other pollutant emissions, diluent, 
or stack gas volumetric flow rate.
    Copper matte means a material predominately composed of copper and 
iron sulfides produced by smelting copper ore concentrates.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the equipment identified in paragraph (l)(1) of this 
section.
    SO2 means sulfur dioxide.
    (3) Emission capture. (i) The owner/operator of the batch copper 
converters identified in paragraph (l)(1) of this section must operate 
a capture system that has been designed to maximize collection of 
process off gases vented from each converter. At all times when one or 
more converters are blowing, you must operate the capture system 
consistent with a written operation and maintenance plan that has been 
prepared according to the requirements in 40 CFR 63.1447(b) and 
approved by EPA within 180 days of the compliance date in paragraph 
(l)(5) of this section. The capture system must include a primary 
capture system as described in 40 CFR 63.1444(d)(2) and a secondary 
hood as described in 40 CFR 63.1444(d)(2). (ii) The operation of the 
batch copper converters and secondary hood shall be optimized to 
capture the maximum amount of process off gases vented from each 
converter at all times.
    (4) Emission limitations and work practice standards. (i) 
SO2 emissions collected by the capture system required by 
paragraph (l)(3) of this section must be controlled by one or more 
control devices and reduced by at least 99.81

[[Page 9374]]

percent, based on a 30-day rolling average.
    (ii) The owner/operator must not cause or allow to be discharged to 
the atmosphere from any primary capture system required by paragraph 
(l)(3) off-gas that contains nonsulfuric acid particulate matter in 
excess of 6.2 mg/dscm as measured using the test methods specified in 
40 CFR 63.1450(b).
    (iii) The owner/operator must not cause or allow to be discharged 
to the atmosphere from any secondary capture system required by 
paragraph (l)(3) of this section off-gas that contains particulate 
matter in excess of 23 mg/dscm as measured using the test methods 
specified in 40 CFR 63.1450(a).
    (iv) Total NOX emissions from anode furnaces 1 
and 2 and the batch copper converters shall not exceed 40 tons 
per 12-continuous month period.
    (v) Anode furnaces 1 and 2 shall only be charged 
with blister copper or higher purity copper.
    (5) Compliance dates. The owner/operator of each batch copper 
converter identified in paragraph (l)(1) of this section shall comply 
with the emissions limitations and other requirements of this section 
no later than (three years after date of publication of the final rule 
in the Federal Register).
    (6) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance date specified in paragraph 
(e) of this section, the owner/operator of each batch copper converter 
identified in paragraph (l)(1) of this section shall maintain, 
calibrate, and operate a CEMS, in full compliance with the requirements 
found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to 
accurately measure the mass emission rate in pounds per hour of 
SO2 emissions entering each control device used to control 
emissions from the converters, and venting from the converters to the 
atmosphere after passing through a control device or an uncontrolled 
bypass stack. The CEMS shall be used by the owner/operator to determine 
compliance with the emission limitation in paragraph (l)(4) of this 
plan. The owner/operator must operate the monitoring system and collect 
data at all required intervals at all times that an affected unit is 
operating, except for periods of monitoring system malfunctions, 
repairs associated with monitoring system malfunctions, and required 
monitoring system quality assurance or quality control activities 
(including, as applicable, calibration checks and required zero and 
span adjustments).
    (ii) Compliance determination for SO2. The 30-day rolling 
SO2 emission control efficiency for the converters shall be 
calculated for each calendar day in accordance with the following 
procedure: Step one, sum the hourly pounds of SO2 vented to 
each uncontrolled bypass stack and to each control device used to 
control emissions from the converters for the current calendar day and 
the preceding twenty-nine (29) calendar days, to calculate the total 
pounds of pre-control SO2 emissions over the most recent 
thirty (30) calendar day period; Step two, sum the hourly pounds of 
SO2 vented to each uncontrolled bypass stack and emitted 
from the release point of each control device used to control emissions 
from the converters for the current calendar day and the preceding 
twenty-nine (29) calendar days, to calculate the total pounds of post-
control SO2 emissions over the most recent thirty (30) 
calendar day period; Step three, divide the total amount of post-
control SO2 emissions calculated from Step two by the total 
amount of pre-control SO2 emissions calculated from Step 
one, subtract the resulting quotient from one, and multiply the 
difference by 100 percent to calculate the 30-day rolling 
SO2 emission control efficiency as a percentage.
    (iii) Compliance determination for nonsulfuric acid particulate 
matter. Compliance with the emission limit for nonsulfuric acid 
particulate matter in paragraph (l)(4)(ii) of this section shall be 
demonstrated by the procedures in 40 CFR 63.1451(b) and 40 CFR 
63.1453(a)(2).
    (iv) Compliance determination for particulate matter. Compliance 
with the emission limit for particulate matter in paragraph (l)(4)(iii) 
of this section shall be demonstrated by the procedures in 40 CFR 
63.1451(a) and 40 CFR 63.1453(a)(1).
    (v) Compliance determination for NOX. Compliance with the emission 
limit for NOX in paragraph (l)(4)(iv) of this section shall 
be demonstrated by monitoring natural gas consumption in each of the 
units identified in paragraph (l)(1) of this section for each calendar 
day. At the end of each calendar month, the owner/operator shall 
calculate 12-consecutive month NOX emissions by multiplying 
the daily natural gas consumption rates for each unit by an approved 
emission factor and adding the sums for all units over the previous 12-
consecutive month period.
    (7) Alternative compliance determination for sulfuric acid plants. 
If the owner/operator uses one or more double contact acid plants to 
control SO2 from the batch copper converters identified in 
paragraph (l)(1) of this section, this paragraph may be used to 
demonstrate compliance with the emission limit in paragraph (l)(4)(i) 
of this section.
    (i) Continuous emission monitoring system. At all times after the 
compliance date specified in paragraph (l)(5) of this section, the 
owner/operator of each batch copper converter identified in paragraph 
(l)(1) of this section shall maintain, calibrate, and operate a CEMS, 
in full compliance with the requirements found at 40 CFR 60.13 and 40 
CFR part 60, Appendices B and F, to accurately measure the mass 
emission rate in pounds per hour of SO2 emissions venting 
from the converters to the atmosphere after passing through a control 
device or an uncontrolled bypass stack. The CEMS shall be used by the 
owner/operator to determine compliance with the emission limitation in 
paragraph (l)(4) of this section. The owner/operator must operate the 
monitoring system and collect data at all required intervals at all 
times that an affected unit is operating, except for periods of 
monitoring system malfunctions, repairs associated with monitoring 
system malfunctions, and required monitoring system quality assurance 
or quality control activities (including, as applicable, calibration 
checks and required zero and span adjustments).
    (ii) Daily sulfuric acid production monitoring. At all times after 
the compliance date specified in paragraph (l)(5) of this section, the 
owner/operator of each batch copper converter subject to this section 
shall monitor and maintain records of sulfuric acid production for each 
calendar day.
    (iii) Compliance determination for SO2. The 30-day rolling 
SO2 emission rate for the converters shall be calculated for 
each calendar day in accordance with the following procedure: Step one, 
sum the hourly pounds of SO2 vented to each uncontrolled 
bypass stack and emitted from the release point of each double contact 
acid plant used to control emissions from the converters for the 
current calendar day and the preceding twenty-nine (29) calendar days, 
to calculate the total pounds of SO2 emissions over the most 
recent thirty (30) calendar day period; Step two, sum the total 
sulfuric acid production in tons of pure sulfuric acid for the current 
calendar day and the preceding twenty-nine (29) calendar days, to 
calculate the total tons of sulfuric acid production over the most 
recent thirty (30) calendar day period; Step three, divide the total 
amount of SO2 emissions calculated from Step one by the 
total tons of sulfuric acid production calculated from Step one to 
calculate the 30-day rolling

[[Page 9375]]

SO2 emission rate in lbs-SO2 per ton of sulfuric 
acid. An emission rate of 4.06 or lower shall be deemed to be in 
compliance with the emission limit in paragraph (i)(4) of this section.
    (8) Capture system monitoring. For each operating limit established 
under the capture system operation and maintenance plan required by 
paragraph (l)(4) of this section, the owner/operator must install, 
operate, and maintain an appropriate monitoring device according to the 
requirements in 40 CFR 63.1452(a)(1) though (6) to measure and record 
the operating limit value or setting at all times the required capture 
system is operating. Dampers that are manually set and remain in the 
same position at all times the capture system is operating are exempted 
from these monitoring requirements.
    (9) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (iii) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (iv) Any other records required by 40 CFR part 60, Subpart F, or 40 
CFR part 60, Appendix F, Procedure 1.
    (v) Records of all monitoring required by paragraph (l)(8) of this 
section.
    (vi) Records of daily sulfuric acid production in tons per day of 
pure sulfuric acid if the owner/operator chooses to use the alternative 
compliance determination method in paragraph (l)(7) of this section.
    (vii) Records of daily natural gas consumption in each units 
identified in paragraph (l)(1) and all calculations performed to 
demonstrate compliance with the limit in paragraph (l)(4)(iv).
    (10) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (l)(5) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall promptly submit excess emissions 
reports for the SO2 limit. Excess emissions means emissions 
that exceed the emissions limit specified in paragraph (d) of this 
section. The reports shall include the magnitude, date(s), and duration 
of each period of excess emissions, specific identification of each 
period of excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted. For the purpose of this paragraph, promptly shall mean within 
30 days after the end of the month in which the excess emissions were 
discovered.
    (ii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments. The owner/
operator shall submit reports semiannually.
    (iii) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (iv) When no excess emissions have occurred or the CEMS has not 
been inoperative, repaired, or adjusted during the reporting period, 
the owner/operator shall state such information in the semiannual 
report.
    (v) When performance testing is required to determine compliance 
with an emission limit in paragraph (l)(4) of this section, the owner/
operator shall submit test reports as specified in 40 CFR part 63, 
subpart A.
    (11) Notifications. (i) The owner/operator shall notify EPA of 
commencement of construction of any equipment which is being 
constructed to comply with the capture or emission limits in paragraph 
(l)(3) or (4) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (12) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (13) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (14) Affirmative defense for malfunctions. The following provisions 
of the Arizona Administrative Code are incorporated by reference and 
made part of this Federal implementation plan:
    (i) R-18-2-101, paragraph 65;
    (ii) R18-2-310, sections (A), (B), (D) and (E) only; and
    (iii) R18-2-310.01.
    (m) Source-specific federal implementation plan for regional haze 
at Miami Copper Smelter--(1) Applicability. This paragraph (m) applies 
to each owner/operator of each batch copper converter and the electric 
furnace at the copper smelting plant located in Hayden, Gila County, 
Arizona.
    (2) Definitions. Terms not defined in this paragraph (m)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (m):
    Batch copper converter means a Pierce-Smith converter or Hoboken 
converter in which copper matte is oxidized to form blister copper by a 
process that is performed in discrete batches using a sequence of 
charging, blowing, skimming, and pouring.
    Calendar day means a 24 hour period that begins and ends at 
midnight, local standard time.

[[Page 9376]]

    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of SO2 emissions, other pollutant emissions, diluent, 
or stack gas volumetric flow rate.
    Copper matte means a material predominately composed of copper and 
iron sulfides produced by smelting copper ore concentrates.
    Electric furnace means a furnace in which copper matte and slag are 
heated by electrical resistance without the mechanical introduction of 
air or oxygen.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the equipment identified in paragraph (m)(1) of this 
section.
    Slag means the waste material consisting primarily of iron sulfides 
separated from copper matte during the smelting and refining of copper 
ore concentrates.
    SO2 means sulfur dioxide.
    (3) Emission capture. (i)The owner/operator of the batch copper 
converters identified in paragraph (m)(1) of this section must operate 
a capture system that has been designed to maximize collection of 
process off gases vented from each converter. At all times when one or 
more converters are blowing, you must operate the capture system 
consistent with a written operation and maintenance plan that has been 
prepared according to the requirements in 40 CFR 63.1447(b) and 
approved by EPA within 180 days of the compliance date in paragraph 
(m)(5) of this section. The capture system must include a primary 
capture system as described in 40 CFR 63.1444(d)(3) and a secondary 
hood as described in 40 CFR 63.1444(d)(2). (ii) The operation of the 
batch copper converters and secondary hood shall be optimized to 
capture the maximum amount of process off gases vented from each 
converter at all times.
    (4) Emission limitations and work practice standards. (i) 
SO2 emissions collected by the capture system required by 
paragraph (m)(3) of this section must be controlled by one or more 
control devices and reduced by at least 99.7 percent, based on a 30-day 
rolling average.
    (ii) Total NOX emissions the electric furnace and the 
batch copper converters shall not exceed 40 tons per 12-continuous 
month period.
    (iii) The owner/operator shall not actively aerate the electric 
furnace.
    (5) Compliance dates. The owner/operator of each batch copper 
converter identified in paragraph (m)(1) of this section shall comply 
with the emissions limitations and other requirements of this section 
no later than (three years after date of publication of the final rule 
in the Federal Register).
    (6) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance date specified in paragraph 
(e) of this section, the owner/operator of each batch copper converter 
identified in paragraph (m)(1) of this section shall maintain, 
calibrate, and operate a CEMS, in full compliance with the requirements 
found at 40 CFR 60.13 and 40 CFR part 60, Appendices B and F, to 
accurately measure the mass emission rate in pounds per hour of 
SO2 emissions entering each control device used to control 
emissions from the converters, and venting from the converters to the 
atmosphere after passing through a control device or an uncontrolled 
bypass stack. The CEMS shall be used by the owner/operator to determine 
compliance with the emission limitation in paragraph (m)(4) of this 
section. The owner/operator must operate the monitoring system and 
collect data at all required intervals at all times that an affected 
unit is operating, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments).
    (ii) Compliance determination for SO2. The 30-day rolling 
SO2 emission control efficiency for the converters shall be 
calculated for each calendar day in accordance with the following 
procedure: Step one, sum the hourly pounds of SO2 vented to 
each uncontrolled bypass stack and to each control device used to 
control emissions from the converters for the current calendar day and 
the preceding twenty-nine (29) calendar days, to calculate the total 
pounds of pre-control SO2 emissions over the most recent 
thirty (30) calendar day period; Step two, sum the hourly pounds of 
SO2 vented to each uncontrolled bypass stack and emitted 
from the release point of each control device used to control emissions 
from the converters for the current calendar day and the preceding 
twenty-nine (29) calendar days, to calculate the total pounds of post-
control SO2 emissions over the most recent thirty (30) 
calendar day period; Step three, divide the total amount of post-
control SO2 emissions calculated from Step two by the total 
amount of pre-control SO2 emissions calculated from Step 
one, subtract the resulting quotient from one, and multiply the 
difference by 100 percent to calculate the 30-day rolling 
SO2 emission control efficiency as a percentage.
    (iii) Compliance determination for NOX. Compliance with the 
emission limit for NOX in paragraph (m)(4)(ii) of this 
section shall be demonstrated by monitoring natural gas consumption in 
each of the units identified in paragraph (m)(1) of this section for 
each calendar day. At the end of each calendar month, the owner/
operator shall calculate monthly and 12-consecutive month 
NOX emissions by multiplying the daily natural gas 
consumption rates for each unit by an approved emission factor and 
adding the sums for all units over the previous 12-consecutive month 
period.
    (7) Alternative compliance determination for sulfuric acid plants. 
If the owner/operator uses one or more double contact acid plants to 
control SO2 from the batch copper converters identified in 
paragraph (m)(1) of this section, this paragraph may be used to 
demonstrate compliance with the emission limit in paragraph (m)(4)(i) 
of this section.
    (i) Continuous emission monitoring system. At all times after the 
compliance date specified in paragraph (m)(5) of this section, the 
owner/operator of each batch copper converter identified in paragraph 
(m)(1) of this section shall maintain, calibrate, and operate a CEMS, 
in full compliance with the requirements found at 40 CFR 60.13 and 40 
CFR part 60, Appendices B and F, to accurately measure the mass 
emission rate in pounds per hour of SO2 emissions venting 
from the converters to the atmosphere after passing through a control 
device or an uncontrolled bypass stack. The CEMS shall be used by the 
owner/operator to determine compliance with the emission limitation in 
paragraph (m)(4) of this section. The owner/operator must operate the 
monitoring system and collect data at all required intervals at all 
times that an affected unit is operating, except for periods of 
monitoring system malfunctions, repairs associated with monitoring 
system malfunctions, and required monitoring system quality assurance 
or quality control activities (including, as applicable, calibration 
checks and required zero and span adjustments).
    (ii) Daily sulfuric acid production monitoring. At all times after 
the compliance date specified in paragraph (m)(5) of this section, the 
owner/operator of each batch copper converter subject to this section 
shall monitor and

[[Page 9377]]

maintain records of sulfuric acid production for each calendar day.
    (iii) Compliance determination for SO2. The 30-day rolling 
SO2 emission rate for the converters shall be calculated for 
each calendar day in accordance with the following procedure: Step one, 
sum the hourly pounds of SO2 vented to each uncontrolled 
bypass stack and emitted from the release point of each double contact 
acid plant used to control emissions from the converters for the 
current calendar day and the preceding twenty-nine (29) calendar days, 
to calculate the total pounds of SO2 emissions over the most 
recent thirty (30) calendar day period; Step two, sum the total 
sulfuric acid production in tons of pure sulfuric acid for the current 
calendar day and the preceding twenty-nine (29) calendar days, to 
calculate the total tons of sulfuric acid production over the most 
recent thirty (30) calendar day period; Step three, divide the total 
amount of SO2 emissions calculated from Step one by the 
total tons of sulfuric acid production calculated from Step one to 
calculate the 30-day rolling SO2 emission rate in lbs-
SO2 per ton of sulfuric acid. An emission rate of 4.06 or 
lower shall be deemed to be in compliance with the emission limit in 
paragraph (i)(4) of this section.
    (8) Capture system monitoring. For each operating limit established 
under the capture system operation and maintenance plan required by 
paragraph (m)(4) of this section, the owner/operator must install, 
operate, and maintain an appropriate monitoring device according to the 
requirements in 40 CFR 63.1452(a)(1) though (6) to measure and record 
the operating limit value or setting at all times the required capture 
system is operating. Dampers that are manually set and remain in the 
same position at all times the capture system is operating are exempted 
from these monitoring requirements.
    (9) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (iii) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (iv) Any other records required by 40 CFR part 60, Subpart F, or 40 
CFR part 60, Appendix F, Procedure 1.
    (v) Records of all monitoring required by paragraph (m)(8) of this 
section.
    (vi) Records of daily sulfuric acid production in tons per day of 
pure sulfuric acid if the owner/operator chooses to use the alternative 
compliance determination method in paragraph (m)(7) of this section.
    (vii) Records of daily natural gas consumption in each units 
identified in paragraph (m)(1) and all calculations performed to 
demonstrate compliance with the limit in paragraph (m)(4)(iv).
    (10) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (m)(5) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall promptly submit excess emissions 
reports for the SO2 limit. Excess emissions means emissions 
that exceed the emissions limit specified in paragraph (d) of this 
section. The reports shall include the magnitude, date(s), and duration 
of each period of excess emissions, specific identification of each 
period of excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted. For the purpose of this paragraph, promptly shall mean within 
30 days after the end of the month in which the excess emissions were 
discovered.
    (ii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments. The owner/
operator shall submit reports semiannually.
    (iii) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (iv) When no excess emissions have occurred or the CEMS has not 
been inoperative, repaired, or adjusted during the reporting period, 
the owner/operator shall state such information in the semiannual 
report.
    (v) When performance testing is required to determine compliance 
with an emission limit in paragraph (m)(4) of this section, the owner/
operator shall submit test reports as specified in 40 CFR part 63, 
subpart A.
    (11) Notifications. (i) The owner/operator shall notify EPA of 
commencement of construction of any equipment which is being 
constructed to comply with the capture or emission limits in paragraph 
(m)(3) or (4) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (12) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (13) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.

[[Page 9378]]

    (14) Affirmative defense for malfunctions. The following provisions 
of the Arizona Administrative Code are incorporated by reference and 
made part of this federal implementation plan:
    (i) R-18-2-101, paragraph 65;
    (ii) R18-2-310, sections (A), (B), (D) and (E) only; and
    (iii) R18-2-310.01.

[FR Doc. 2014-02714 Filed 2-14-14; 8:45 am]
BILLING CODE 6560-50-P