# Approval and Promulgation of Implementation Plans; States of Minnesota and Michigan; Regional Haze Federal Implementation Plan > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2012-19789 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** August 15, 2012 - **Citation:** 77 FR 49308 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 52 [EPA-R05-OAR-2010-0954; EPA-R05-OAR-2010-0037; FRL-9709-8] Approval and Promulgation of Implementation Plans; States of Minnesota and Michigan; Regional Haze Federal Implementation Plan AGENCY: Environmental Protection Agency. ACTION: Proposed rule. SUMMARY: The Environmental Protection Agency (EPA) is proposing a Federal Implementation Plan (FIP) to address the requirement for best available retrofit technology (BART) for taconite plants in Minnesota and Michigan. BART is a requirement of EPA's regional haze rule which has not been satisfied by Minnesota or Michigan for its subject taconite plants. EPA developed this proposal in response to an inadequate BART determination by Michigan for its one subject taconite source. On June 12, 2012, EPA approved revisions to the Minnesota State Implementation Plan (SIP) addressing regional haze but also, on that date, announced that in response to comments it was deferring action on emission limitations that Minnesota intended to represent BART for its taconite facilities. EPA is proposing to determine that the FIP satisfies requirements of the Clean Air Act (CAA or “the Act”) that require states, or EPA in promulgating a FIP, to establish BART for applicable sources. DATES: Comments must be received on or before September 28, 2012. Public Hearing. EPA will hold a public hearing to solicit comments on its proposal to establish emission limits for taconite plants in Minnesota and Michigan, to satisfy requirements for best available retrofit technology for these facilities. This hearing will be held on Wednesday, August 29, 2012, 10 a.m. to 2 p.m., Office of Minnesota Pollution Control Agency, 520 Lafayette Road, St. Paul, MN, Citizens Board Hearing Room. Information on this hearing is also available at http://www.epa.gov/region5/mnhaze. ADDRESSES: Submit your comments, identified by Docket ID Nos. EPA-R05-OAR-2010-0954 and EPA-R05-OAR-2010-0037, by one of the following methods: 1. www.regulations.gov: Follow the on-line instructions for submitting comments. 2. Email: aburano.douglas@epa.gov. 3. Fax: (312) 408-2279. 4. Mail: Douglas Aburano, Chief, Attainment Planning and Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604. 5. Hand Delivery: Douglas Aburano, Chief, Attainment Planning and Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, Illinois 60604. Such deliveries are only accepted during the Regional Office normal hours of operation, and special arrangements should be made for deliveries of boxed information. The Regional Office official hours of business are Monday through Friday, 8:30 a.m. to 4:30 p.m., excluding Federal holidays. Instructions: Direct your comments to Docket ID Nos. EPA-R05-OAR-2010-0954 and EPA-R05-OAR-2010-0037. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or email. The 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 www.regulations.gov your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional instructions on submitting comments, go to Section I of the SUPPLEMENTARY INFORMATION section of this document. Docket: All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the Environmental Protection Agency, Region 5, Air and Radiation Division, 77 West Jackson Boulevard, Chicago, Illinois 60604. This facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal holidays. We recommend that you telephone Steven Rosenthal at (312) 886-6052 before visiting the Region 5 office. FOR FURTHER INFORMATION CONTACT: Steven Rosenthal, Environmental Engineer, Attainment Planning & Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604, (312) 886-6052, rosenthal.steven@epa.gov. SUPPLEMENTARY INFORMATION: Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA. This supplementary information section is arranged as follows: I. What should I consider as I prepare my comments for EPA? II. What action is EPA taking today? III. Background IV. Requirements for a Regional Haze FIP V. EPA's BART Analysis of Michigan and Minnesota's Taconite Facilities VI. Proposed Action VII. Statutory and Executive Order Reviews I. What should I consider as I prepare my comments for EPA? When submitting comments, remember to: 1. Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register date, and page number). 2. Follow directions—The EPA may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number. 3. Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes. 4. Describe any assumptions and provide any technical information and/or data that you used. 5. If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced. 6. Provide specific examples to illustrate your concerns, and suggest alternatives. 7. Explain your views as clearly as possible, avoiding the use of profanity or personal threats. 8. Make sure to submit your comments by the comment period deadline identified. II. What action is EPA taking today? EPA is proposing a FIP that establishes BART emission limitations for the taconite plants in Minnesota and Michigan that are subject to the Regional Haze Rule. III. Background A. Regional Haze Regional haze is visibility impairment that is produced by a multitude of sources and activities which are located across a broad geographic area and emit fine particulates (PM 2.5 ) ( e.g., sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and soil dust), and their precursors ( e.g., sulfur dioxide (SO 2 ), nitrogen oxides (NO X )). Fine particle precursors react in the atmosphere to form PM 2.5 , which impairs visibility by scattering and absorbing light. Visibility impairment reduces the clarity, color, and visible distance that one can see. PM 2.5 can also cause serious health effects and mortality in humans and contributes to environmental effects such as acid deposition and eutrophication. Data from the existing visibility monitoring network, the “Interagency Monitoring of Protected Visual Environments” (IMPROVE) monitoring network, show that visibility impairment caused by air pollution occurs virtually all the time at most national park and wilderness areas. The average visual range 1 in many Class I areas ( i.e., NPs and memorial parks, WA, and international parks meeting certain size criteria) in the western United States is 100-150 kilometers, or about one-half to two-thirds of the visual range that would exist without anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average visual range is less than 30 kilometers, or about one-fifth of the visual range that would exist under estimated natural conditions. 64 FR 35715 (July 1, 1999). 1 Visual range is the greatest distance, in kilometers or miles, at which a dark object can be viewed against the sky. B. Requirements of the CAA and EPA's Regional Haze Rule In section 169A of the 1977 Amendments to the CAA, Congress created a program for protecting visibility in the nation's national parks and wilderness areas. This section of the CAA establishes as a national goal the “prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I Federal areas 2 which impairment results from manmade air pollution.” On December 2, 1980, EPA promulgated regulations to address visibility impairment in Class I areas that is “reasonably attributable” to a single source or small group of sources, i.e., “reasonably attributable visibility impairment.” (45 FR 80084, December 2, 1980). These regulations represented the first phase in addressing visibility impairment. EPA deferred action on regional haze that emanates from a variety of sources until monitoring, modeling and scientific knowledge about the relationships between pollutants and visibility impairment were improved. 2 Areas designated as mandatory Class I Federal areas consist of national parks exceeding 6000 acres, wilderness areas and national memorial parks exceeding 5000 acres, and all international parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a). In accordance with section 169A of the CAA, EPA, in consultation with the Department of Interior, promulgated a list of 156 areas where visibility is identified as an important value. 44 FR 69122 (November 30, 1979). The extent of a mandatory Class I area includes subsequent changes in boundaries, such as park expansions. 42 U.S.C. 7472(a). Although states and tribes may designate as Class I additional areas which they consider to have visibility as an important value, the requirements of the visibility program set forth in section 169A of the CAA apply only to “mandatory Class I Federal areas.” Each mandatory Class I Federal area is the responsibility of a “Federal Land Manager.” 42 U.S.C. 7602(i). When we use the term “Class I area” in this action, we mean a “mandatory Class I Federal area.” Congress added section 169B to the CAA in 1990 to address regional haze issues. EPA promulgated a rule to address regional haze on July 1, 1999. (64 FR 35714, July 1, 1999), codified at 40 CFR part 51, subpart P. The Regional Haze Rule revised the existing visibility regulations to integrate into the regulation provisions addressing regional haze impairment and established a comprehensive visibility protection program for Class I areas. The requirements for regional haze, found at 40 CFR 51.308 and 51.309, are included in EPA's visibility protection regulations at 40 CFR 51.300-309. Some of the main elements of the regional haze requirements are summarized in this section of this preamble. The requirement to submit a regional haze SIP applies to all 50 states, the District of Columbia and the Virgin Islands. 3 40 CFR 51.308(b) requires states to submit the first implementation plan addressing regional haze visibility impairment no later than December 17, 2007. 4 3 Albuquerque/Bernalillo County in New Mexico must also submit a regional haze SIP to completely satisfy the requirements of section 110(a)(2)(D) of the CAA for the entire State of New Mexico under the New Mexico Air Quality Control Act (section 74-2-4). 4 EPA's regional haze regulations require subsequent updates to the regional haze SIPs. 40 CFR 51.308(g)-(i). Few states submitted a Regional Haze SIP prior to the December 17, 2007 deadline, and on January 15, 2009, EPA found that 37 states, including Michigan and Minnesota, had failed to submit SIPs addressing the regional haze requirements. (74 FR 2392, January 15, 2009). Once EPA has found that a state has failed to make a required submission, EPA is required to promulgate a FIP within two years unless the state submits a SIP and the Agency approves it within the two year period. CAA § 110(c)(1). C. Roles of Agencies in Addressing Regional Haze Successful implementation of the regional haze program will require long-term regional coordination among states, tribal governments and various federal agencies. As noted above, pollution affecting the air quality in Class I areas can be transported over long distances, even hundreds of kilometers. Therefore, to effectively address the problem of visibility impairment in Class I areas, states, or the EPA when implementing a FIP, need to develop strategies in coordination with one another, taking into account the effect of emissions from one jurisdiction on the air quality in another. Because the pollutants that lead to regional haze can originate from sources located across broad geographic areas, EPA has encouraged the states and tribes across the United States to address visibility impairment from a regional perspective. Five regional planning organizations (RPOs) were developed to address regional haze and related issues. The RPOs first evaluated technical information to better understand how their states and tribes impact Class I areas across the country, and then pursued the development of regional strategies to reduce emissions of particulate matter (PM) and other pollutants leading to regional haze. IV. Requirements for a Regional Haze FIP The following is a summary of the requirements of the Regional Haze Rule. See 40 CFR 51.308 for further detail regarding the requirements of the rule. A. The CAA and the Regional Haze Rule Regional haze FIPs must assure Reasonable Progress towards the national goal of achieving natural visibility conditions in Class I areas. Section 169A of the CAA and EPA's implementing regulations require states, or EPA when implementing a FIP, to establish long-term strategies for making Reasonable Progress toward meeting this goal. The FIP must also give specific attention to certain stationary sources that were in existence on August 7, 1977, but were not in operation before August 7, 1962, and require these sources, where appropriate, to install BART controls for the purpose of eliminating or reducing visibility impairment. The specific regional haze FIP requirements are discussed in further detail below. B. EPA's Authority To Promulgate a FIP Under section 110(c) of the Act, whenever we find that a State has failed to make a required submission we are required to promulgate a FIP. Specifically, 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 [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 the Michigan and Minnesota failed to adequately establish BART limits for its subject taconite ore processing facilities we are required to promulgate a FIP. C. Best Available Retrofit Technology (BART) Section 169A of the CAA directs states, or EPA if implementing a FIP, to evaluate the use of retrofit controls at certain larger, often uncontrolled, older stationary sources in order to address visibility impacts from these sources. Specifically, section 169A(b)(2)(A) of the CAA requires EPA to implement a FIP to contain such measures as may be necessary to make Reasonable Progress toward the natural visibility goal, including a requirement that certain categories of existing major stationary sources 5 built between 1962 and 1977 procure, install, and operate the “Best Available Retrofit Technology” as determined by EPA. Under the Regional Haze Rule, EPA is directed to conduct BART determinations for such “BART-eligible” sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. 5 The set of “major stationary sources” potentially subject to BART is listed in CAA section 169A(g)(7), and includes “taconite ore processing facilities.” On July 6, 2005, EPA published the Guidelines for BART Determinations Under the Regional Haze Rule at appendix Y to 40 CFR part 51 (hereinafter referred to as the “BART Guidelines”) to assist states, or EPA if implementing a FIP, in determining which of their sources should be subject to the BART requirements and in determining appropriate emission limits for each applicable source. (70 FR 39104, July 6, 2005). In making a BART determination for a fossil fuel-fired electric generating plant with a total generating capacity in excess of 750 megawatts (MW), EPA must use the approach set forth in the BART Guidelines. EPA is encouraged, but not required, to follow the BART Guidelines in making BART determinations for other types of sources. Regardless of source size or type, EPA must meet the requirements of the CAA and our regulations for selection of BART, and EPA's BART analysis and determination must be reasonable in light of the overarching purpose of the regional haze program. The process of establishing BART emission limitations can be logically broken down into three steps: First, EPA identifies those sources which meet the definition of “BART-eligible sources” set forth in 40 CFR 51.301; 6 second, EPA determines which of such sources “emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area” (a source which fits this description is “subject to BART”); and third, for each source subject to BART, EPA then identifies the best available type and level of control for reducing emissions. 6 BART-eligible sources are those sources that have the potential to emit 250 tons or more of a visibility-impairing air pollutant, were not in operation prior to August 7, 1962, but were in existence on August 7, 1977, and whose operations fall within one or more of 26 specifically listed source categories. 40 CFR 51.301. States, or EPA if implementing a FIP, must address all visibility-impairing pollutants emitted by a source in the BART determination process. The most significant visibility impairing pollutants are SO 2 , NO X , and PM. A regional haze FIP must include source-specific BART emission limits and compliance schedules for each source subject to BART. Once EPA has made its BART determination, the BART controls must be installed and in operation as expeditiously as practicable, but no later than five years after the date of the final FIP. CAA section 169(g)(4) and 40 CFR 51.308(e)(1)(iv). In addition to what is required by the Regional Haze Rule, general SIP, or FIP, requirements mandate that the SIP, or FIP, must also include all regulatory requirements related to monitoring, recordkeeping, and reporting for the BART controls on the source. See CAA section 110(a). V. EPA's BART Analysis of Michigan and Minnesota's Taconite Facilities A. Sources Subject to BART EPA agrees with Michigan and Minnesota with respect to the taconite facilities that the States determined to be subject to BART. These determinations are included in Minnesota's December 2009 Regional Haze Plan and Michigan's November 2010 Regional Haze Plan. EPA also agrees with the States' determination that BART for direct PM is satisfied by the taconite maximum achievable control technology (MACT) rule. See, National Emission Standards for Hazardous Air Pollutants: Taconite Iron Ore Processing, 40 CFR part 63, subpart RRRRR. The primary sources that have been specifically identified as being subject to BART and requiring an analysis to establish BART are the taconite pelletizing, or indurating, furnaces identified in Table V-A.1. While they mean the same thing, we have chosen to refer to these furnaces as indurating furnaces or pelletizing furnaces in a manner consistent with how they are referred to by the States. Table V-A.1—List of Taconite Facilities State Company Unit Minnesota U.S. Steel, Minntac Grate-Kiln Lines 3-7. Minnesota Northshore Mining Company Straight-Grate Furnaces 11 and 12. Minnesota United Taconite Grate-Kiln Lines 1 and 2. Minnesota ArcelorMittal Steel 1 Straight-Grate. Minnesota Hibbing Taconite Straight-Grate Lines 1-3. Minnesota U.S. Steel, Keetac 1 Grate-Kiln. Michigan Tilden Mining Grate-Kiln Line 1. The U.S. taconite iron ore industry uses two types of pelletizing machines or processes: Straight-grate and grate-kiln. A significant difference is that straight-grate kilns do not burn coal and they therefore have a much lower potential for emitting SO 2. In the straight-grate kiln, a continuous bed of agglomerated green pellets is carried through different temperature zones with upward draft or downward draft blown through the pellets on the metal grate. Pellet residence time inside the machine is about 40 minutes. Fuel combustion chambers supply hot flue gas to a zone in the middle portion of the machine (combustion zone). (In order to make fully fluxed pellets, auxiliary burners need to be added to the preheating zone.) Fired pellets are cooled on the remaining portion of the machine. To protect the metal grate and other parts of the machine, about 20 percent of the cooled, fired pellets are used to make a hearth layer at the bottom and two sides of the pellet bed. For the straight-grate kiln, used process gas consists of exhaust gas from the updraft drying zone and exhaust gas closer to the firing zone. The former can be called “hood exhaust” and the latter “windbox exhaust.” For many straight-grate kilns, both hood exhaust and windbox exhaust are directed to one common header. The common exhaust header has one “hot side” inlet to receive windbox exhaust and one “cold side” inlet to receive hood exhaust. From the common exhaust header, the exhaust gas is vented through four parallel stacks, which are outfitted with air pollution control equipment. For some older machines, two separate common headers are used to vent hood exhaust and windbox exhaust. The hood exhaust header vents through three stacks, and the wind exhaust (often referred to as “waste gas”) header vents through two stacks. Gases are passed numerous times through the pellet bed in order to heat and cool the pellets as they pass along a large grate. “Windbox exhaust” gases are derived from the down draft and preheat zones, but are passed through multiclone dust collectors before entering the wet scrubber/exhaust system. “Hood exhaust” gases from the updraft drying zone originate from the second cooling zone and pass directly into the wet scrubber/exhaust system. Windbox and hood exhaust gases partially mix in a common header before being vented to the atmosphere through a series of four stacks. The grate-kiln system actually consists of a traveling grate, a rotary kiln, and an annular cooler. Pellet residence time inside the system is about 55 minutes (less than 10 minutes in the grate, about 20 minutes in the kiln, and about 30 minutes in the cooler). The grate-kiln system does not need a hearth layer for the grate, which handles only drying and preheating. The rotary kiln does not need a hearth layer, either, because it is lined with refractory material. One waste gas stack, or two side-by-side waste gas stacks, is used for the grate-kiln system. Combustion gases for heating the pellets are directed up a large rotating kiln and then down through the pellet bed in the preheat zone. The gases are then used for initial heating and drying of the green pellet feed. Gases used for cooling the hot pellets are also used to dry and heat the pellets. Depending on the operation, the waste gases are passed through one or more scrubbers and vented through one or more separate stacks. It is very common to use intermediate cyclones to clean the gas stream in the straight grate and grate-kiln pelletizers, as it is ducted to various locations in the grate. The cyclones protect the blades of gas movers (fans) and recover good materials (particles of high iron content). Inclined plates are also used along with periodic water wash to remove “solid spills” under the grate to recover the iron units. These measures also help reduce dust loading near the waste gas stack, even though they are not considered air pollution control equipment. B. BART Five-Factor Determinations and Proposed FIP Emission Limits for NO X and SO 2 EPA proposes to find that BART for NO X for indurating furnaces is low NO X burners for both straight-grate and grate-kilns. The feasibility of using low NO X burners on grate-kilns is based on an October 26, 2011 “Summary Report for USS On NO X reduction for Kilns #6 and 7” by S. Londerville, which documents a baseline of 4 pounds per million British Thermal Units (lbs/MMBtu) when burning gas; the December 1, 2011 “U.S. Steel Minntac Line 6 Low NO X Main Burner Final Report & Facility NO X Management,” which states that there has been neither an increase in fuel consumption nor degradation of pellet quality with the use of a low NO X burner; and continuous emission monitoring system (CEMS) data from U.S. Steel Minntac Line 6. These data support a limit of 1.2 lbs/MMBtu on a 30-day rolling average. Also, cost-calculations for Minntac's Line 6 result in cost-effectiveness values of $441/ton of NO X reduced when burning coal and gas and $210/ton of NO X reduced when burning gas. In a July 2, 2012, conversation with U.S. Steel and COEN, EPA discussed the potential for any negative issues associated with the use of Minntac's low NO X burners. During this conversation it was stated that although there was initially an increase in fuel use, that increase has been eliminated so there is not an increase in MMBtu/ton of NO X emitted. There is also no increase in combustion related emissions, such as carbon monoxide or volatile organic compounds, and there is no reason for SO 2 emissions to increase through use of a low NO X burner. There is a small (less than 1 MW/hr) increase in electricity use and no increase in water use. U.S. Steel was certain that there was absolutely no product/pellet degradation. Some of their pellets are shipped to other (non-U.S. Steel) customers and some are shipped a long distance so there can be no slip ( e.g. pellet degradation) in quality. The July 2, 2012 conversation also included discussion of installation schedules during which it was stated that engineering for adding additional burners would be expected to take about 6 months, although engineering could be combined for installation of more than one burner. Installation of new low NO X burners would need to be timed with line outages, which typically occur about 6 months apart, and could take about a year. The feasibility of low NO X burners on straight-grate kilns is documented in a September 19, 2011 summary of findings presented to the Minnesota Pollution Control Board titled “Results of Testing at 1/4 -Scale of LE Low NO X Burner Prototype for Straight-Grate Pelletizing Furnaces” by Fives North American Combustion, Inc. (Fives) for Essar (formerly Minnesota) Steel (Essar), and in presentations made at the April 17 and 18, 2012 Society for Mining, Metallurgy and Exploration meeting in Duluth, Minnesota. These presentations were “Reducing NO X from Pelletizing Furnaces,” by Fives and “Environmental Benefits for the Adaptation of Commonly Used Low-NO X Burner Technology to a Straight-Grate Natural Gas Fired Taconite Indurating Furnace,” by Lori L. Stegink, from Barr Engineering and Kevin Kangas from Essar. These presentations revealed that Essar and Fives first examined the applicability of numerous traditional methods for reducing NO X from combustion as well as post-treatment methods for NO X removal. This was followed by successful bench-scale testing of Fives low NO X LE burners to achieve NO X reductions greater than 70 percent in a straight-grate pelletizing furnace. Therefore Essar and Fives proceeded with a joint $2 million investment in a test rig to simulate a straight-grate pelletizing furnace. In the 1/4 -scale test rig, the cross sectional area scaling was very representative of actual furnace geometry, as were the energy inputs and flows. This testing demonstrated a 90 percent reduction in NO X emissions and a rate of 0.25 lbs. NO X /MMBtu at an estimated cost-effectiveness of $370/ton. Based on the results of this test program, it was concluded that NO X emissions in the actual furnace should be consistent with those measured in the 1/4 scale test conditions. Subsequent conversations with representatives of Essar and Fives indicated that an increase in fuel use and emissions from other pollutants is not anticipated and that the type of furnace that Essar will be using is the most difficult design for NO X control. Based on the range of cost-effectiveness values provided, a conservative value of $500/ton will be used as the cost-effectiveness value for low NO X burners. EPA proposes to determine that BART for SO 2 for straight-grate kilns is existing controls because these furnaces do not burn coal. EPA also proposes to find that BART for SO 2 is existing controls at Keetac and Minntac because the cost-effectiveness of additional controls is excessive due to the amount of coal fired, the sulfur content of the coal used there and their existing controls. For Tilden Line 1 and United Taconite's Lines 1 and 2, EPA is proposing to determine that a dry flue-gas desulfurization (FGD) system (for United Taconite's Lines 1 and 2), and either a wet or dry FGD system at Tilden, with an emission rate of 5 parts per million by volume (ppmv) of SO 2 , or a 95 percent emission reduction requirement, on a 30-day rolling average, has been determined to be BART for SO 2. The cost-effectiveness of these controls has been determined based upon EPA's Air Pollution Control Cost Manual, information provided in Tilden's and United Taconite's BART determinations, information on existing operating costs supplied by United Taconite and a summary of information provided on capital and operating costs as well as the SO 2 emission rate provided by FGD manufacturers. Also, there is no indication that the useful life of any of these facilities is less than 20 years. BART analyses conducted for each of the subject facilities are presented below. EPA will carefully consider any comments that disagree with any of its facts or conclusions. It should be noted, however, that more weight will be provided to fact-based comments such as test results or vendor quotes and less to unsubstantiated engineering estimates or opinions. Please note that in the following analyses, unless otherwise specified, information related to the technical and economic feasibility of various controls was provided in Minnesota's December 30, 2009 Regional Haze SIP submission and reflects information provided in the company specific BART analyses. The same is also true for Michigan and Tilden. 1. U.S. Steel Minntac U.S. Steel Minnesota Ore Operations (Minntac) operates five grate-kiln indurating furnaces which are identified in table V-B.1 below. Table V-B.1 Minntac Emission Units Emission unit name EU No. 7 Control equipment and stack numbers Line 3 Indurating Furnace EU225 CE146/SV103 Line 4 Indurating Furnace EU261 CE103/SV118 Line 5 Indurating Furnace EU282 CE113/SV127 Line 6 Indurating Furnace EU315 CE126/SV144 Line 7 Indurating Furnace EU334 CE136/SV151 a. NO X BART Analysis 7 The MPCA organizes conditions and illustrates associations in its permits using the Emission Unit (EU), Control Equipment (CE), and Stack/Vent (SV) numbers. Step 1: Identify all Available Retrofit Control Technologies The following NO X retrofit control technologies have been identified as being available for indurating furnaces: • External Flue Gas Recirculation, • Low NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction (SCR). Step 2: Eliminate Technically Infeasible Options Minntac eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. Minntac eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. Minntac noted in their analysis that the facility has already implemented several energy efficiency projects and that it will continue to evaluate and implement energy efficiency projects. Minntac eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and Minntac believes that this option is not mandated by EPA. Also, U.S. Steel documented the infeasibility of SCR controls. Two SCR vendors declined to bid on NO X reduction testing at Minntac. EPA agrees that SCR controls are infeasible for indurating furnaces. The remaining technologies, considered by Minntac to be technically feasible, include: • Low NO X burners, • Low NO X burners + Ported kilns (Lines 4 and 5), and • Ported kilns (Lines 3, 4, and 5—kilns on lines 6 and 7 are already ported). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies The following tables illustrate the assumed control efficiencies and the projected NO X emission reductions projected by Minntac with the technically feasible control technologies. Table V-B.2—Pellet Furnace Projected NO X Emission Reductions [TPY] NO X Control technology Assumed control efficiency (percent) Line 3 Line 4 Line 5 Line 6 Line 7 None (Baseline) 1,345 1,812 1,820 1,776 1,928 Low NO X burners + Ported kilns 15 na 249 273 na na Low NO X burners 10 na 181 182 na 193 Ported kilns 5 67 91 91 na na Step 4: Evaluate Impacts and Document the Results Minntac's estimates of the annualized pollution control cost of operating the various control technologies are shown in the following table. Table V-B.3—Pellet Furnace Projected NO X Control Cost [$/Ton] NO X Control technology Line 3 Line 4 Line 5 Line 6 Line 7 Low NO X burners + Ported kilns na $5,844 $5,974 na na Low NO X Burners na 768 765 na $588 Ported kilns $5,076 5,209 5,186 na na Step 5: Evaluate Visibility Impacts See Section V.C. Step 6: Propose BART EPA is proposing a limit of 1.20 lbs/MMBtu on a 30-day rolling average for all lines to be achieved as follows: 1 year after the effective date of this rule for line 6, 2 years after the effective date for Line 7, 3 years after the effective date for Line 4, 4 years after the effective date for Line 5 and 4 years, and 11 months after the effective date for Line 3. b. SO 2 BART Analysis Lines 3, 4, and 5 can burn natural gas, wood and fuel oil, but natural gas and wood are used most frequently. Since these fuels are low in sulfur, the primary source of sulfur in these furnaces is the iron ore used to form the pellets. Additional sulfur may be present in the additives used in the pellets. In addition to natural gas, wood, and fuel oil, coal is used in Lines 6 and 7. The lines are controlled by wet scrubbers designed to remove PM. Since collateral SO 2 reductions occur within the existing wet scrubbers, they are considered low efficiency SO 2 scrubbers. Minntac estimates that these existing scrubbers remove 15 to 30 percent of the SO 2 in the exhaust gas from these lines. Step 1: Identify all Available Retrofit Control Technologies Minntac identified the following SO 2 retrofit control technologies: 8 8 See September 8, 2006 BART analysis submitted to MPCA by U.S. Steel, http://www.pca.state.mn.us/index.php/view-document.html?gid=2228 . • Wet Walled Electrostatic Precipitator (WWESP), • Wet Scrubbing (High and Low Efficiency), • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption, • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Eliminate Technically Infeasible Options Minntac eliminated Dry Sorbent Injection, Spray Dryer Absorption, Alternative Fuels, and Coal Drying from consideration due to technical infeasibility. With Dry Sorbent Injection and Spray Dryer Absorption, the high moisture content of the exhaust would lead to saturation of the baghouse filter cake and plugging of the filters and the dust collection system. To achieve a reduction of SO 2 emissions through alternative fuel usage, the source must switch from a high sulfur fuel to a lower sulfur fuel. Lines 3, 4, and 5 are burning natural gas and wood, both of which are low in sulfur. Lines 7 and 8 are allowed to burn coal. Due to the uncertainty of alternative fuel costs, the potential of replacing one visibility impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, Minntac did not evaluate this option further. Coal drying requires a source of excess heat or low pressure steam. This heat source is not available at the Minntac facility so coal drying was found to be technically infeasible. In addition, Minntac has already implemented Energy Efficiency Projects. The company indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company did not evaluate this option any further. Minntac evaluated the possibility of improving the SO 2 removal efficiency of the existing scrubbers through the additions of caustic, lime, or limestone in the scrubber water to raise the pH. The existing scrubbers on lines 3-7 currently operate at a neutral pH. The scrubbers, piping, pumps, and water tanks were not designed to operate at a higher pH so corrosion of the system would be a concern. Also, the additions and increased SO 2 removal would create additional solids and sulfates in the scrubber discharged to the tailings basin. This would require substantial and expensive treatment to maintain an acceptable water quality which could be discharged through the existing National Pollutant Discharge Elimination System permit. The new scrubber on Line 3 is a recirculating scrubber which operates at a pH that is typically less than 7. The scrubber was operated temporarily at a higher pH, but plugging and other operational problems resulted. Based on these concerns, Minntac found the improvement of SO 2 removal efficiency of the existing scrubbers to be impractical and did not further consider this option. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Minntac estimated the control efficiency of WWESPs to be approximately 80 percent. A secondary wet scrubber was estimated to control roughly 60 percent of the SO 2 remaining after the existing scrubber. The following tables illustrate the SO 2 emission reductions projected by Minntac with the technically feasible control technologies. Table V-B.4—Annual SO 2 Emissions [TPY] Line 3 Line 4 Line 5 Line 6 Line 7 Total Baseline SO 2 Emissions 329.4 447.5 447.5 544.8 544.8 2314 Table V-B.5—Projected SO 2 Emission Reductions [TPY] SO 2 Control technology Line 3 Line 4 Line 5 Line 6 Line 7 Total WWESP 263.5 358.0 358.0 435.9 435.9 1851.3 Secondary Wet Scrubber 197.6 268.5 268.5 326.9 326.9 1388.4 Step 4: Evaluate Impacts and Document the Results Cost of Control Minntac estimated the annualized pollution control cost of installing and operating WWESPs on Lines 3, 4, and 5 to be between $20,000 and $24,000 per ton of SO 2 removed. The cost of installing and operating a secondary wet scrubber on these lines was estimated to be between $14,000 and $16,000 per ton of SO 2 removed. The annualized pollution control cost of installing and operating WWESPs on Lines 6 and 7 was estimated to be approximately $18,000 per ton of SO 2 removed. The cost of installing and operating a secondary wet scrubber on these lines was estimated to be between approximately $12,000 per ton of SO 2 removed. Energy and Non-Air Quality Environmental Impacts There are no energy or non-air quality impacts because, as discussed above and in the Step 6 discussion, no additional controls were determined to be required. Step 5: Evaluate Visibility Impacts Additional SO 2 controls for Minntac are not reasonably cost effective, so visibility impacts were not modeled for additional SO 2 controls. Step 6: Propose BART Although we do not agree that the Minnesota Pollution Control Agency (MPCA) and Minntac have adequately documented the infeasibility of all of the SO 2 controls described above, we agree that additional SO 2 controls are not economically reasonable and are, therefore, not necessary for BART. EPA is proposing to determine that BART is existing controls. Based on CEM data provided by Minntac for 2010, 2011, and part of 2012, EPA is proposing the following limits: 71.3 lb SO 2 /hr for Line 3, 56.1 lb SO 2 /hr for Line 4, 67.9 lb SO 2 /hr for Line 5, 64.5 lb SO 2 /hr for Line 6, and 67.1 lb SO 2 /hr for Line 7. These limits are measured on a 30-day rolling average and compliance is required within 30 days after the effective date of this rule. c. Non-Furnace BART Analysis Minntac also operates four heating boilers that are subject to a full BART analysis. The facility's two Step I Heating Boilers (#1 and #2) are each rated at 104 MMBtu/hr and the two Step III Heating Boilers (#4 and #5) are rated at 153 MMBtu/hr. Each boiler is capable of burning natural gas and fuel oil. Step 1: Identification of Available Retrofit Control Technologies The following NO X retrofit control technologies have been identified as being available for the heating boilers: • External Flue Gas Recirculation, • Low-NO X Burners, • LNB with Overfire Air (LNB/OFA), • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Alternate Fuels, • Low Temperature Oxidation, • Selective Catalytic Reduction, • Regenerative SCR, and • Selective Non-Catalytic Reduction. Step 2: Eliminate Technically Infeasible Options Minntac eliminated External Flue Gas Recirculation from consideration since it was technically infeasible for the boilers based on Minntac staff judgment that the existing fireboxes for the boilers would be unable to accommodate longer flame length to avoid flame impingement. Minntac eliminated energy efficiency projects due to the difficulty of assigning a general potential emission reduction for this category, but stated that Minntac will continue to evaluate and implement energy efficiency projects. Minntac eliminated alternative fuels because the environmental and economic benefits of such a change are uncertain, the limited fuel options available, and the fact that natural gas is the typical fuel burned in the boilers. Minntac stated that it would continue to evaluate and implement alternative fuel usage as feasible. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the assumed control efficiencies and the projected NO X emission reductions projected by Minntac with the technically feasible control technologies. Table V-B.6—Heating Boiler Projected NO X Emission Reductions [TPY] NO X Control technology Control efficiency Boilers #1, #2, #4, #5 Emissions Cost None (Baseline) 13.8-14.8 56.7 Low Temperature Oxidation 90% 12.4-13.3 5.7 $23,668-$27,713 SCR 80% 11.0-11.8 11.3 $50,632-$60,211 LNB/Flue gas recirculation 75% 10.4-11.1 14.2 $15,558-$20,299 Regenerative SCR 70% 9.7-10.4 17.0 $22,879-$30,710 LNB/Overfire Air 67% 9.2-9.9 18.7 $14,282-$18,634 Low NO X Burner 50% 6.9-7.4 28.3 $6,653-$8,646 Selective Non-Catalytic Reduction 50% 6.9-7.4 28.3 $42,037-$51,494 Step 4: Evaluate Impacts and Document the Results The NO X emissions generated by the four heating boilers at the Minntac facility total 56.7 TPY. The most cost efficient control is low NO X burners at $6,653 to $8,646 per ton, which would yield a 28.4 TPY reduction. Step 5: Evaluate Visibility Impacts Additional NO X controls are not required because they are not reasonably cost-effective. Therefore there are no resulting visibility impacts. Step 6: Propose BART Given that the control options result in modest reductions in NO X emissions on a TPY basis, that modest reduction would need to provide a strong visibility improvement or be trivial in cost to justify a BART limit indicative of additional control. That is not the case for the Minntac heating boilers. Minntac's current Title V permit (13700005—002) does not include NO X emission limits for the heating boilers. Thus, EPA is not proposing a NO X emission limit for the Minntac heating boilers. EPA is proposing to determine that the existing operational requirements, including fuels (natural gas with fuel oil as back up) and compliance requirements in the existing permits are NO X BART for the Minntac heating boilers. 2. Northshore Mining Northshore operates two straight-grate indurating furnaces which are identified in Table V-B.7 below. Table V-B.7—Northshore Emission Units Emission unit name EU No. Control equipment and stack numbers Indurating Furnace #11—Hood Exhaust EU100 CE101/SV101, CE102/SV102, CE103/SV103. Indurating Furnace #11—Waste Gas EU104 CE104/SV104, CE105/SV105. Indurating Furnace #12—Hood Exhaust EU110 CE111/SV111, E112/SV112, CE113/SV113. Indurating Furnace #12—Waste Gas EU114 CE114/SV114, CE115/SV115. a. NO X BART Analysis Step 1: Identify All Available Retrofit Control Technologies The following NO X retrofit control technologies have been identified as being available for indurating furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction. Step 2: Eliminate Technically Infeasible Options Northshore eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. Northshore eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. The company has already implemented several energy efficiency projects and will continue to evaluate and implement energy efficiency projects. Northshore's use of straight grate indurating furnaces makes the use of Ported Kilns infeasible, since they can be used only at grate-kiln furnaces. Northshore eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and Northshore believes that this option is not mandated by EPA. In addition, Northshore's furnace is currently incapable of handling solid fuels. Also, U.S. Steel documented the infeasibility of SCR controls. (see section V.B.1.a., above). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies The following table illustrates the NO X emission baseline for Northshore and the reductions achievable using low NO X burners. Table V-B.8—Projected Annual NO X Emission Reduction [TPY] NO X Control Assumed control Furnace 11 Hood exhaust Waste gas Furnace 12 Hood exhaust Waste gas None (Baseline) 112.4 273.7 109.9 267.7 Low NO X Burners 70% 79 192 77 187 Step 4: Evaluate Impacts and Document Results Cost of Control Table V-B.9—Pellet Furnace Projected NO X Control [Cost per ton of pollutant removed] NO X Control Technology Furnace 11 (hood) Furnace 11 (waste) Furnace 12 (hood) Furnace 12 (waste) Low NO X Burners $500 $500 $500 $500 Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART EPA is proposing a limit of 1.2 lbs/MMBtu on a 30-day rolling average for all lines to be achieved as follows: 1 year and 6 months after the effective date for Line 11 and 2 years and 6 months after the effective date for Line 12. b. SO 2 BART Analysis Although the indurating furnaces can burn both natural gas and fuel oil, natural gas is the primary fuel. Since natural gas is low in sulfur, the primary source of SO 2 emissions is from trace amounts of sulfur in the iron concentrate and binding agents. Sulfur is also present in distillate fuel oil. Both lines are controlled by wet-walled electrostatic precipitators using caustic reagent. Step 1: Identify All Available Retrofit Control Technologies Northshore identified the following SO 2 retrofit control technologies: 9 9 See BART analysis submitted to MPCA by Northshore Mining Company in September 2006, http://www.pca.state.mn.us/index.php/view-document.html?gid=2225 . • Wet-Walled Electrostatic Precipitator, • Wet Scrubbing (High and Low Efficiency), • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption, • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Eliminate Technically Infeasible Options Northshore eliminated Dry Sorbent Injection, Spray Dryer Absorption, Alternative Fuels, and Coal Drying from consideration due to technical infeasibility. With Dry Sorbent Injection and Spray Dryer Absorption, the high moisture content of the exhaust would lead to saturation of the baghouse filter cake and plugging of the filters and the dust collection system. Alternative Fuels were eliminated because Northshore is prohibited from burning solid fuels. Coal Drying is technically infeasible because Northshore does not burn coal. Northshore indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details. Since no particular project has been envisioned, the company did not evaluate this option any further. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Northshore estimated the control efficiency of a secondary WWESP to be approximately 80 percent. A secondary wet scrubber was estimated to control roughly 60 percent of the SO 2 remaining after the existing scrubber. The following tables illustrate the SO 2 emission reductions projected by Northshore with the technically feasible control technologies. Table V-B.10—Annual SO 2 Emissions [TPY] Furnace 11 Hood exhaust Waste gas Furnace 12 Hood exhaust Waste gas Total Baseline SO 2 Emissions 28.6 9.5 26.3 8.8 73.2 Table V-B.11—Projected SO 2 Emission Reductions [TPY] SO 2 control technology Furnace 11 Hood exhaust Waste gas Furnace 12 Hood exhaust Waste gas Total WWESP 22.9 7.6 21.0 7.0 58.5 Secondary Wet Scrubber 17.2 6.7 15.8 5.3 45.0 Step 4: Evaluate Impacts and Document the Results Cost of Control Northshore estimated the annualized pollution control cost of installing and operating secondary WWESPs ranged from roughly $180,000 to $540,000 per ton of SO 2 removed. The cost of installing and operating a secondary wet scrubber was estimated to be between $140,000 and $420,000 per ton of SO 2 removed. Energy and Non-air Quality Environmental Impacts Because the cost of additional SO 2 controls for Northshore does not meet a reasonable definition of cost-effective technology, no further evaluation of these alternatives was conducted. Step 5: Evaluate Visibility Impacts Additional SO 2 controls for Northshore are not reasonably cost effective, so visibility impacts were not modeled for additional SO 2 controls. Step 6: Propose BART Although we do not agree that MPCA and Northshore have adequately documented the infeasibility of all of the SO 2 controls described above, we agree that, because Northshore is burning natural gas and fuel oil, additional SO 2 controls are not economically reasonable and are, therefore, not necessary for BART. EPA is proposing to determine that BART is existing controls. In its regional haze submittal, MPCA also concluded that BART was existing controls and set a limit of 0.0651 lb SO 2 /long ton of pellets fired (finished) measured on a 30-day rolling average. Northshore provided 2011 performance testing data which showed an average production rate of 250 long ton of pellets fired (finished)/hr for Furnace 11 and 263 long ton of pellets fired (finished)/hr for Furnace 12. Based on these production rates and MPCA's limit, EPA is proposing the following limits: 16.3 lb SO 2 /hr for Furnace 11 and 17.1 lb SO 2 /hr for Furnace 12, measured on a 30-day rolling average. These limits do not apply when the subject emissions unit is burning fuel oil. In addition, EPA is proposing to require that the emissions from SV101, SV102, SV103, SV104, SV105, SV111, SV112, SV113, SV114, and SV115 for Furnaces 11 and 12 be subject to an 80.0 percent emission reduction requirement. Compliance is to be achieved with these limits within 6 months after the effective date of this rule. c. Non-Furnace BART Analysis Northshore also operates two process boilers that are subject to BART. Both process boilers were installed in 1965 and are rated at 79 MMBtu/hr. The boilers are capable of burning fuel oil and natural gas. Step 1: Identification of Available Retrofit Control Technologies The following NO X retrofit control technologies have been identified as being available for the process boilers: • External Flue Gas Recirculation, • Low-NO X Burners, • Overfire Air, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Alternate Fuels, • Non-Selective Catalytic Reduction, • Selective Catalytic Reduction, • Regenerative SCR, and • Selective Non-Catalytic Reduction. Step 2: Elimination of Technically Infeasible Options Northshore found External Flue Gas Recirculation to be technically infeasible and eliminated it from further consideration because Northshore's process boilers lack the capability needed to controlled combustion conditions at the boiler tip. Overfire air was eliminated due to the small size of Northshore's process boilers and the number of burners. Northshore eliminated energy efficiency projects due to the difficulty of assigning a general potential emission reduction for this category. However, it has already implemented energy efficiency projects and it will continue to evaluate and implement energy efficiency projects. Northshore also rejected alternate fuels, as the process boilers burn distillate fuel oil and natural gas only. As those fuels have low nitrogen content, even a fuel alternative with no nitrogen content would provide little benefit. Northshore also believes that this option is not mandated by EPA and furthermore, Northshore's boilers are incapable of handling solid fuels. Northshore identified low-NO X burners, induced flue gas recirculation burners, selective catalytic reduction, and selective non-catalytic reduction as the only technically feasible alternative from the list above. These technologies were then evaluative for cost-effectiveness. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the NO X emission reductions projected by Northshore with the technically feasible technologies. Table V-B.12—Projected Annual NO X Emission Reductions [TPY] NO X Control technology Control efficiency (percent) Emissions Cost None (Baseline) 41.2 Selective Catalytic Reduction 90 4.1 $30,160 Low-NO X Burners w/Induced Flue Gas Recirculation 75 10.3 10,675 Low-NO X Burners 50 20.6 723 Selective Non-Catalytic Reduction 50 20.6 12,126 Step 4: Evaluate Impacts and Document Results The NO X emissions generated by the two process boilers are of modest size, totaling 41.2 TPY. The most cost efficient control is low NO X burners at $723 per ton, which would produce a 20.6 TPY emission reduction for each unit. Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART Low NO X burners will reduce emissions from the process boilers at a modest cost, estimated at $723 per ton by Northshore. This control will reduce 20.6 TPY of NO X emissions from each process boiler unit. Although the total 41.2 ton annual reduction is modest, the low cost of adding the control, on a per ton and total cost bases, makes it reasonable. Thus, EPA is proposing a NO X emission limit of 0.085 lb/MMBtu on a 30-say rolling average for Northshore Mining's Process Boiler #1 and Process Boiler #2. Compliance is to be achieved with this limit within 5 years after the effective date of this rule. This represents the BART emission limit when low NO X burners are added to each boiler unit. 3. United Taconite United Taconite operates two grate-kilns which are identified in Table V-B.13 below. Table V-B.13—United Taconite Emission Units Emission unit name EU No. Control equipment and stack numbers Line 1 Pellet Induration EU40 SV046 Line 2 Pellet Induration EU42 SV048, SV049 a. NO X BART Analysis Step 1: Identify All Available Retrofit Control Technologies United Taconite identified the following NO X retrofit control technologies as being available for indurating furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction. Step 2: Eliminate Technically Infeasible Options United Taconite eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. United Taconite eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. The company has already implemented several energy efficiency projects and it will continue to evaluate and implement energy efficiency projects. United Taconite eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and United Taconite believes that this option is not mandated by EPA. Also, U.S. Steel documented the infeasibility of SCR controls. (see section V.B.1.a., above). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Table V-B.14 illustrates the NO X emission baseline for United Taconite and the reductions achievable using low NO X burners. Table V-B.14—Projected Annual NO X Emission Reductions [TPY] NO X Control Assumed control Line 1 Line 2 None (Baseline) 1643 3687 Low NO X Burners 70% 1150 2581 Step 4: Evaluate Impacts and Document Results Table V-B.15—Pellet Furnace Projected NO X NO X Control Line 1 Line 2 Low NO X Burners $500 $500 Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART A limit of 1.2 lbs/MMBtu on a 30-day rolling average for all lines to be achieved as follows: 1 year and 6 months after the effective date for Line 2 and 2 years and 6 months after the effective date for Line 1. b. SO 2 BART Analysis Step 1: Identify All Available Retrofit Control Technologies In its BART analysis, United Taconite identified the following SO 2 reduction technologies as generally available to pellet furnaces: • Wet scrubbing (high efficiency), • Wet scrubbing (low efficiency), • Wet walled electrostatic precipitator (WWESP), • Dry sorbent injection, • Spray dryer absorption, • Alternative Fuels, and • Energy efficiency projects. Step 2: Eliminate Technically Infeasible Options United Taconite eliminated dry sorbent injection and spray dryer absorption as technically infeasible technologies. United Taconite identified the use of alternative fuels and energy efficiency projects as technically feasible, but did not evaluate the costs associated with these options. United Taconite justified its failure to evaluate the costs associated with the use of alternative fuels and with energy efficiency projects stating that a BART analysis does not require analysis of such options. The company noted EPA's intent “for facilities to consider alternate fuels as an option, not to direct fuel choice” as its rationale for failing to conduct the cost analyses. EPA disagrees with United Taconite's assessment of the feasibility of Flue-gas desulfurization, which will be discussed more fully elsewhere. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies and Step 4: Evaluate Impacts and Document Results Table V-B.16—Sulfur Dioxide Removal Alternatives for United Taconite Line 2 Control technology Uncontrolled SO 2 emissions rate (lb/MMBtu) Existing SO 2 removal efficiency (percent) Additional control (BART analysis App A) (percent) lb/ MMBtu SO 2 Max hourly emission rate (total) (lb/hr) Tons SO 2 emitted Tons SO 2 removed Total annualized cost $/Ton SO 2 removed Existing Scrubber 5.32 25 N/A 3.99 1037 3,900 WWESP 5.32 25 80 0.80 207 780 3,120 $20,291,473 $6,504 Polishing Scrubber 5.32 25 60 1.60 415 1,560 2,340 9,166,715 3,917 Replacement Scrubber 5.32 N/A 60 2.13 553 2,080 1,820 7,107,434 3,905 Fuel Blend Changes 2.26 25 N/A 1.70 442 1,660 2,240 1,341,482 599 Fuel Blending + Polishing Scrubber 2.26 25 60 0.68 176 663 3,237 9,650,715 2,981 Table V-B.16 above identified alternatives for controlling SO 2 and their associated emissions rate, which MPCA determined were all cost-effective. At the time this table was prepared by MPCA, Line 1 was not equipped to burn coal. Line 1 can now burn coal and so presumably the above table, or something similar, would also apply to Line 1. Table V-B.17—Projected Annual SO 2 Emission Reductions and Resulting Cost-Effectiveness SO 2 Control Assumed control Line 1 Line 2 Dry FGD Reductions 90% 1164 2475 Cost-Effectiveness $2,000-$3,000 per ton $2,000-$3,000 per ton. EPA has determined that dry FGD scrubbers are feasible for United Taconite's two indurating furnaces. Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART EPA is proposing a limit of 5 ppmv or a 95 percent reduction requirement, on a 30-day rolling average, to be achieved within 2 years after the effective date of this rule for Line 2 and 4 years after the effective date of this rule for Line 1. 4. ArcelorMittal ArcelorMittal Minorca Mine Inc. operates one straight grate indurating furnace which is identified in Table V-B.18 below. Table V-B.18 ArcelorMittal Emission Units Emission unit name EU No. Control equipment and stack numbers Indurating Furnace EU026 CE014/SV014, CE015/SV015, CE016/SV016, CE017/SV017. a. NO X BART Analysis Step 1: Identify All Available Retrofit Control Technologies ArcelorMittal identified the following NO X retrofit control technologies as being available for indurating furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, Alternate Fuels, and • Selective Catalytic Reduction. Step 2: Eliminate Technically Infeasible Options ArcelorMittal eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. ArcelorMittal eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. ArcelorMittal noted in its analysis that the facility has already implemented several energy efficiency projects and that it will continue to evaluate and implement energy efficiency projects. Ported Kilns were eliminated by ArcelorMittal because they are applicable only to grate kiln furnaces not to the straight grate indurating furnaces that ArcelorMittal employs. ArcelorMittal eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and ArcelorMittal believes that this option is not mandated by EPA. Also, ArcelorMittal's permit currently limits its fuels to natural gas and fuel oil. Also, U.S. Steel documented the infeasibility of SCR controls above. (See section V.B.1.a., above). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Table V-B.19 illustrates the NO X emission reductions from use of Low NO X burners. Table V-B.19—Projected Annual NO X Emission Reductions [TPY] NO X Control technology Assumed control efficiency Total None (Baseline) 6 3639 Low NO X Burners 70% 2547 Step 4: Evaluate Impacts and Document Results The annualized pollution control cost of installing and operating low NO X burners is in Table V-B.20 below. Table V-B.20—Pellet Furnace Projected NO X Control Cost-Effectiveness NO X Controls Indurating furnace Low NO X Burners $500/ton. Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART EPA is proposing a limit of 1.2 lbs/MMBtu on a 30-day rolling average to be achieved within 1 year and 6 months after the effective date of this rule for its indurating furnace. b. SO 2 BART Analysis Although the indurating furnaces can burn both natural gas and fuel oil, natural gas is the primary fuel. Since natural gas is low in sulfur, the primary source of sulfur at this furnace is the iron ore used to form the pellets. Additional sulfur may be present in the additives used in the pellets. Furnace emissions are controlled by four wet scrubbers. The wet scrubbers are designed to remove PM and would be considered high efficiency PM wet scrubbers. Since collateral SO 2 reductions occur within the existing wet scrubbers, they are considered low efficiency SO 2 scrubbers. ArcelorMittal estimates that these existing scrubbers remove 15 to 30 percent of the SO 2 in the exhaust gas. Step 1: Identify all Available Retrofit Control Technologies ArcelorMittal identified the following SO 2 retrofit control technologies 10 : 10 See September 8, 2006 BART analysis submitted to MPCA by Mittal Steel USA—Minorca Mine, http://www.pca.state.mn.us/index.php/view-document.html?gid=2224. • Wet Walled Electrostatic Precipitator (WWESP), • Wet Scrubbing (High and Low Efficiency), • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption (SDA), • Energy Efficiency Projects, and • Alternate Fuels. Step 2: Eliminate Technically Infeasible Options ArcelorMittal eliminated Dry Sorbent Injection, Spray Dryer Absorption, Alternative Fuels, and Coal Drying from consideration because they were technically infeasible. With Dry Sorbent Injection and Spray Dryer Absorption, the high moisture content of the exhaust would lead to saturation of the baghouse filter cake and plugging of the filters and the dust collection system. Alternative Fuels were eliminated because ArcelorMittal is prohibited from burning solids fuels and natural gas is a low-sulfur fuel. ArcelorMittal indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company did not evaluate this option any further. ArcelorMittal evaluated the possibility of improving the SO 2 removal efficiency of the existing scrubbers through the addition of caustic, lime, or limestone in the scrubber water to raise the pH. ArcelorMittal found this option to be impractical for several reasons. The scrubber currently operates at a neutral pH and the scrubbers, piping, pumps and water tanks were not designed to operate at a higher pH so corrosion of the system would be a concern. Also, the addition of caustic, lime, or limestone to increase SO 2 removal would create additional solids in the scrubber recirculation system which would require an increased blowdown rate and therefore an increased make-up water rate. Because the water balance at the facility is at maximum usage, additional make-up water is not available. Based on these concerns, ArcelorMittal did not further consider this option. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies ArcelorMittal estimated the control efficiency of WWESPs to be approximately 80 percent. A secondary wet scrubber was estimated to control roughly 60 percent of the SO 2 remaining after the existing scrubber. The following tables illustrate the SO 2 emission reductions projected by ArcelorMittal with the technically feasible control technologies. Table V-B.21—Annual SO 2 Emissions [TPY] Total Baseline SO 2 Emissions 179.2 Table V-B.22—Projected SO 2 Emission Reductions [TPY] SO 2 Control technology Total WWESP 143.2 Secondary Wet Scrubber 107.6 Step 4: Evaluate Impacts and Document the Results Cost of Control ArcelorMittal estimated the annualized pollution control cost of installing and operating WWESPs to be about $116,000 per ton of SO 2 removed. The cost of installing and operating a secondary wet scrubber was estimated to be approximately $83,000 per ton of SO 2 removed. Energy and Non-air Quality Environmental Impacts Because the cost of additional SO 2 controls for ArcelorMittal does not meet a reasonable definition of cost effective technology, no further evaluation of these alternatives was conducted. Step 5: Evaluate Visibility Impacts Additional SO 2 controls for ArcelorMittal are not reasonably cost effective, so visibility impacts were not modeled for additional SO 2 controls. Step 6: Propose BART Although we do not agree that MPCA and ArcelorMittal have adequately documented the infeasibility of all of the SO 2 controls described above, we agree that, because ArcelorMittal is burning natural gas, additional SO 2 controls are not economically reasonable and are, therefore, not necessary for BART. EPA is proposing to determine that BART is existing controls. ArcelorMittal provided the results of emissions testing that was performed on the stacks associated with the furnace. Based on these test results, EPA is proposing a limit of 23.0 lb SO 2 /hr, measured on a 30-day rolling average. This limit does not apply when the subject unit is burning fuel oil. Compliance is required within 30 days of the effective date of this rule. 5. Hibbing Taconite Hibbing operates three straight grate indurating furnaces which are identified in Table V-B.23 below. Table V-B.23—Hibbing Emission Units Emission unit name EU No. Control equipment and stack numbers Line 1 Pelletizing furnace EU020 CE022/SV021, CE023/SV022, CE024/SV023, CE025/SV024. Line 2 Pelletizing furnace EU021 CE027/SV025, CE028/SV026, CE029/SV027, CE030/SV028. Line 3 Pelletizing furnace EU022 CE032/SV029, CE033/SV030, CE034/SV031, CE035/SV032. a. NO X BART Analysis Step 1: Identify All Available Retrofit Control Technologies Hibbing identified the following NO X retrofit control technologies as available and applicable to pellet furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction with Reheat. Step 2: Eliminate Technically Infeasible Options Hibbing eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. Hibbing eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. Hibbing noted in their Analysis that the facility has already implemented several energy efficiency projects and that it will continue to evaluate and implement energy efficiency projects. Ported Kilns were eliminated by Hibbing because they are applicable only to grate kiln furnaces not to the straight grate indurating furnaces that Hibbing employs. Hibbing eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and Hibbing believes that this option is not mandated by U.S. EPA. Also, Hibbing's permit currently limits its fuels to natural gas, fuel oil, and used oil. Also, U.S. Steel documented the infeasibility of SCR controls. (see section V.B.1.a., above). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Table V-B.24 illustrates the NO X emission reductions resulting from use of low NO X burners. Table V-B.24—Projected Annual NO X Emission Reductions [TPY] NO X Control technology Assumed control efficiency Line 1 Line 2 Line 3 None (Baseline) 2,143.5 2,143.5 2,247.1 Low NO X Burners 70% 1,748 1,500 1,573 Step 4: Evaluate Impacts and Document Results The annualized pollution control cost of installing and operating low NO X burners is in Table V-B.25 below. Table V-B.25—Pellet Furnace Projected NO X Control Cost [cost per ton of pollutant removed] NO X Control Technology Line 1 Line 2 Line 3 Low NO X Burners $500 $500 $500 Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART EPA is proposing a limit of 1.2 lbs/MMBtu on a 30-day rolling average for all lines to be achieved as follows: 1 year and 6 months after the effective date for Line 1, 2 years and 6 months after the effective date for Line 3 and 3 years and 6 months for Line 2. b. SO 2 BART analysis Hibbing operates three straight grate indurating furnaces which are identified in table V-B.26 below. Table V-B.26—Hibbing SO 2 Emission Units Emission unit name EU No. Control equipment and stack numbers Line 1 Pelletizing Furnace EU020 CE022/SV021, CE023/SV022, CE024/SV023, CE025/SV024. Line 2 Pelletizing Furnace EU021 CE027/SV025, CE028/SV026, CE029/SV027, CE030/SV028. Line 3 Pelletizing Furnace EU022 CE032/SV029, CE033/SV030, CE034/SV031, CE035/SV032. Although the indurating furnaces can burn both natural gas and fuel oil, natural gas is the primary fuel. Since natural gas is low in sulfur, the primary source of sulfur at these furnaces is the iron ore used to form the pellets. Additional sulfur may be present in the additives used in the pellets. Each line is controlled by four venture-rod scrubbers. The wet scrubbers are designed to remove PM and would be considered high efficiency PM wet scrubbers. Since collateral SO 2 reductions occur within the existing wet scrubbers, they are considered low efficiency SO 2 scrubbers. Hibbing estimates that these existing scrubbers remove 15 to 30 percent of the SO 2 in the exhaust gas from Lines 1, 2, and 3. Step 1: Identify all Available Retrofit Control Technologies Hibbing identified the following SO 2 retrofit control technologies 11 : 11 See BART analysis submitted to MPCA by Hibbing Taconite Company in September 2006, http://www.pca.state.mn.us/index.php/view-document.html?gid=2223. • Wet Walled Electrostatic Precipitator (WWESP), • Wet Scrubbing (High and Low Efficiency), • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption, • Energy Efficiency Projects, Alternate Fuels, and • Coal Processing. Step 2: Eliminate Technically Infeasible Options Hibbing eliminated Dry Sorbent Injection, Spray Dryer Absorption, Alternative Fuels, and Coal Drying from consideration due to technical infeasibility. With Dry Sorbent Injection and Spray Dryer Absorption, the high moisture content of the exhaust would lead to saturation of the baghouse filter cake and plugging of the filters and the dust collection system. Alternative Fuels were eliminated because Hibbing is prohibited from burning solids fuels. Coal Drying is technically infeasible because Hibbing does not burn coal. In addition, Hibbing has already implemented Energy Efficiency Projects. The company indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company did not evaluate this option any further. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Hibbing estimated the control efficiency of WWESPs to be approximately 80 percent. A secondary wet scrubber was estimated to control roughly 60 percent of the SO 2 remaining after the existing scrubber. Hibbing also expected that modifying the existing wet scrubber would control between 0 and 50 percent of the SO 2 currently emitted. The following tables illustrate the SO 2 emission reductions projected by Hibbing with the technically feasible control technologies. Table V-B.27—Annual SO 2 Emissions [TPY] Line 1 Line 2 Line 3 Total Baseline SO 2 Emissions 202.2 179.5 188.1 569.8 Table V-B.28—Projected SO 2 Emission Reductions [TPY] SO 2 Control technology Line 1 Line 2 Line 3 Total WWESP 161.8 143.6 150.5 455.9 Secondary Wet Scrubber 121.3 121.3 121.3 363.9 Modification of Wet Scrubber 0-101.1 0-101.1 0-101.1 0-303.3 Step 4: Evaluate Impacts and Document the Results Cost of Control Hibbing estimated the annualized pollution control cost of installing and operating WWESPs to be about $37,000 per ton of SO 2 removed. The cost of installing and operating a secondary wet scrubber was estimated to be between $57,000 and $67,000 per ton of SO 2 removed. Given the space limitations and equipment additions that would be required to modify the existing wet scrubber, Hibbing determined that it would be more cost effective to construct a new, secondary scrubber; therefore, no cost estimate was provided for modifications to the existing wet scrubber. Energy and Non-air Quality Environmental Impacts There are no impacts because no additional controls are being proposed, as discussed in the Step 4 and Step 6 discussions. Step 5: Evaluate Visibility Impacts There are no visibility impacts because no additional controls are being proposed, as discussed in the Step 4 and Step 6 discussions. Step 6: Propose BART Although we do not agree that MPCA and Hibbing have adequately documented the infeasibility of all of the SO 2 controls described above, we agree that, because Hibbing is burning natural gas, additional SO 2 controls are not economically reasonable and are, therefore, not necessary for BART. EPA is proposing to determine that BART is existing controls. Hibbing provided the results of emissions testing that was performed in 2010 on the stacks associated with Lines 1, 2, and 3. Based on these test results, EPA is proposing the following limits: 56.0 lb SO 2 /hr for Line 1, 63.0 lb SO 2 /hr for Line 2, and 64.0 lb SO 2 /hr for Line 3. These limits are measured on a 30-day rolling average and do not apply when the subject units are burning fuel oil. Compliance is required within 30 days of the effective date of this rule. 6. U.S. Steel Keewatin U.S. Steel Keewatin (Keetac) operates one straight grate indurating furnace which is identified in Table V-B.29 below. Table V-B.29—Keetac Emission Units Emission Unit Name EU No. Stack No. Phase II Grate-Kiln Indurating Furnace EU030 SV051 a. NO X BART Analysis Step 1: Identify All Available Retrofit Control Technologies Keetac identified the following NO X retrofit control technologies as available and applicable to pellet furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction with Reheat. Step 2: Eliminate Technically Infeasible Options Keetac eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. The company indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company did not evaluate this option any further. Keetac eliminated Alternative Fuels because the furnace already uses solid fuels that result in lower flame temperature and, thus, lower NO X emissions. Switching to another fuel such natural gas (which Keetac already is capable of using) could exchange one visibility impairing pollutant for another (NO X for SO 2 ). Keetac also believes that this option is not mandated by EPA. Keetac identified Ported Kilns and Selective Catalytic Reduction with conventional Reheat as the only technologies that are technically feasible. Also, U.S. Steel documented the infeasibility of SCR controls (see section V.B.1.a., above). Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Table V-B.30 identifies the projected NO X emission reductions resulting from use of low NO X burners. Table V-B.30—Projected Annual NO X Emission Reductions NO X control technology Assumed control efficiency (percent) Phase II furnaces (TPY) None (Baseline) 4,154.0 Low NO X Burners 70 2,908 Ported Kiln 5 207.7 Step 4: Evaluate Impacts and Document Results Table V-B.30 [COST PER TON OF POLLUTANT REMOVED] NO X control technology Phase II furnace Low NO X burners $500 Ported Kiln-diff. due to discrepancy in submittal $2,938-$6,032 Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART For NO X , EPA is proposing a limit of 1.2 lbs/MMBtu on a 30-day rolling average for the Phase II furnace. Compliance is to be achieved within 1 year and 6 months after the effective date of this rule. b. SO 2 BART Analysis Step 1: Identify All Available Retrofit Control Technologies Keetac identified the following SO 2 retrofit control technologies as available and applicable to pellet furnaces: • Wet Walled Electrostatic Precipitator (WWESP), • Secondary Wet Scrubber, • Modifications to Existing Wet Scrubber, • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption, • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Eliminate Technically Infeasible Options In considering control options for sulfur dioxide, Keetac eliminated Dry Sorbent Injection, Spray Dryer Absorption, Alternative Fuels, and Coal Processing from consideration since they were technically infeasible. With Dry Sorbent Injection and Spray Dryer Absorption, the high moisture content of the exhaust would lead to saturation of the baghouse filter cake and plugging of the filters and the dust collection system. The company indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company did not evaluate this option any further. Alternative Fuels were eliminated due to the uncertainty of alternative fuel costs, the potential of replacing one visibility pollutant for another, and Keetac's belief that BART does not intend to mandate a fuel switch. Coal Processing requires a source of excess or of low pressure stream to remove water from the washed coal. There is no such heat source at Keetac so this option is technically infeasible. In addition, Keetac has already implemented a number of Energy Efficiency Projects. The potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details; since no particular project has been envisioned, the company decided not to evaluate this option any further. Keetac evaluated modifying the existing scrubber to determine whether further SO 2 removal could be achieved. However, Keetac has recently installed new wet scrubbers to control SO 2 emissions. Since operation of the scrubber has been optimized, further improvement of the removal efficiency is not feasible and was not considered further in the report. EPA disagrees with Keetac's assessment of the feasibility of Flue-gas desulfurization, which will be discussed more fully elsewhere. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Keetac evaluated WWESPs and Secondary Wet Scrubber as the two remaining retrofit technologies it deemed to be available and technically feasible. Keetac estimated the control efficiency of WWESPs to be approximately 80 percent. A secondary wet scrubber was estimated to control roughly 60 percent of the SO 2 remaining after the existing scrubber. The following table illustrates the SO 2 emission reductions projected by Keetac with the technically feasible control technologies. Table V-B.32—Projected SO 2 Emission Reductions [TPY] SO 2 Control technology Phase II furnace Baseline Emissions (existing scrubber) 850.5 WWESP (after existing scrubber) 760.4 Secondary Wet Scrubber (after existing scrubber) 570.3 Step 4: Evaluate Impacts and Document Results Keetac's estimates of the annualized pollution control cost of installing and operating the WWESP and Secondary Wet Scrubber are shown in the table V-B.33 below. Table V-B.33—Pellet Furnace Projected SO 2 Control Cost [$ PER TON OF POLLUTANT REMOVED] SO 2 Control technology Phase II furnace WWESP (after existing scrubber) $15,165 Secondary Wet Scrubber (after existing scrubber) 8,870 Step 5: Evaluate Visibility Impacts Visibility impacts were not modeled because additional reductions were not determined to be cost effective. Step 6: Propose BART Keetac's existing recirculating lime scrubber satisfies BART. Therefore, EPA is proposing that the scrubber be subject to a 57 percent SO 2 removal efficiency and a limit, based on CEMS data, of 225 lbs SO 2 per hour on a 30-day rolling average. In addition, EPA is proposing to require that the scrubber be operated at or above a pH of 7.5. Compliance with all SO 2 emission limits is required beginning 90 days from the effective date of this rule. 7. Tilden Mining Company LLC (TMC) The BART-subject emission units include indurating furnace/grate-kiln EUKILN 1, EU PRIMARY CRUSHER, EU COOLER 1, EU DRYER 1, EU BOILER 1, and EU BOILER 2. a. NO X BART Analysis Step 1: Identify All Available and Technically Feasible Retrofit Technologies The following NO X retrofit control technologies have been identified as being available and applicable for indurating furnaces: • External Flue Gas Recirculation, • Low-NO X Burners, • Induced Flue Gas Recirculation Burners, • Energy Efficiency Projects, • Ported Kilns, • Alternate Fuels, and • Selective Catalytic Reduction. Step 2: Eliminate Technically Infeasible Options Tilden eliminated External Flue Gas Recirculation and Induced Flue Gas Recirculation Burners from consideration since they were technically infeasible for the specific application to pellet furnaces due to the high oxygen content of the flue gas. Tilden eliminated Energy Efficiency Projects due to the difficulty of assigning a general potential emission reduction for this category. Ported Kilns were eliminated by Tilden because any reduction in NO X would be minor. Tilden eliminated Alternative Fuels because the environmental and economic benefits of such a change are uncertain and Tilden believes that this option is not mandated by EPA. Also, U.S. Steel documented the infeasibility of SCR controls (see section V.B.1.a., above). Tilden also determined that non-selective catalytic reduction, regenerative selective reduction, selective non-catalytic reduction and low temperature oxidation are technically infeasible. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Table V-B.34 illustrates the NO X emission reductions resulting from use of low NO X burners. Table V-B.34—Projected Annual NO X Emission Reductions NO X Control Technology Assumed control efficiency (percent) Line 1 (tons per year) None (Baseline) 4,613 Low NO X burners 70 3,229 Step 4: Evaluate Impacts and Document Results The annualized pollution control cost of installing and operating low NO X burners is in Table V-B.35 below. Table V-B.35—Pellet Furnace Projected NO X Control Cost [COST PER TON OF POLLUTANT] NO X Control technology Indurating furnace Low NO X burners $ 500/ton. Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART For Line 1, EPA is proposing a limit of 1.2 lbs/MMBtu on a 30-day rolling average to be achieved within 1 year and 6 months after the effective date of this rule. b. SO 2 BART Analysis Step 1: Identify All Available Retrofit Control Technologies Tilden identified the following SO 2 retrofit control technologies as available and applicable to pellet furnaces: • Wet Walled Electrostatic Precipitator (WWESP), • Wet Scrubbing, • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption (SDA), • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Eliminate Technically Infeasible Options Tilden indicated that the potential fuel reductions and the commensurate emission reductions for future Energy Efficiency Projects cannot accurately be predicted without specific details. Therefore, due to the uncertainty and generalization of this category, energy efficiency projects were not subject to further analysis. Alternative Fuels were eliminated due to the uncertainty of alternative fuel costs, the potential of replacing one visibility pollutant for another, and Tilden's belief that BART does not intend to mandate a fuel switch. Using processed fuels at a taconite plant would require research, test burns, and extended trials to identify potential impacts on plant systems, including the furnaces, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available and were not subject to further analysis by Tilden. Step 3: Evaluate Control Effectiveness of Remaining Control Technologies Tilden evaluated a WWESP and wet scrubber after its existing ESP, spray dry absorption, and dry sorbent injection as the remaining retrofit technologies it deemed to be available and technically feasible. Tilden estimated the control efficiency of WWESPs and a wet scrubber to be about 80 percent, dry sorbent injection to be 55 percent and spray dry absorption to be 90 percent. The following table illustrates the SO 2 emission reductions projected by Tilden technologies. Table V-B.36—Projected SO 2 Emission Reductions [TPY] SO 2 Control technology Line 1 Spray Dry Absorption 1,037.8 Wet Walled ESP 922.5 Wet Scrubber 922.5 Dry Sorbent Injection 634.2 Step 4: Evaluate Impacts and Document Results EPA has determined the cost-effectiveness of a 90 percent FGD scrubber to be $4500-$5500/ton using EPA's Air Pollution Control Cost Manual. Step 5: Evaluate Visibility Impacts See section V.C. Step 6: Propose BART For Line 1, EPA is proposing a limit of 5 ppmv or a 95 percent emission reduction, on a 30-day rolling average, to be achieved within 2 years after the effective date of this rule. c. Non-Furnace BART Analysis Process Boiler #1 and Process Boiler #2 Two natural gas and fuel oil fired process boilers (Process Boiler #1 and Process Boiler #2) require BART analysis. These boilers provide steam required to operate the taconite plant, as needed. The boilers are permitted to burn only natural gas and used oil. SO 2 Analysis Step 1: Identification of Available Retrofit Control Technologies • Wet Walled Electrostatic Precipitator, • Wet Scrubber, • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption (SDA), • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Elimination of Technically Infeasible Options Tilden's process boilers cannot burn solid fuel, which eliminates coal processing. Due to the increased price of fuel, Tilden has already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially emission reductions. Due to the uncertainty and generalization of this category, this option was eliminated. Similarly, Tilden eliminated alternative fuels because the environmental and economic benefits of such a change are uncertain, the limited fuel options available, and the fact that natural gas and oil are the fuels burned in the boilers. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the SO 2 emission reductions projected by Tilden with the technically feasible technologies. Table V-B.37—Projected Annual SO 2 Emission Reductions [TPY] Control technology Control efficiency (percent) Emissions Cost None (Baseline) 0.25 SDA 90 0.03 $38,403,000 Wet Scrubber 80 0.05 7,448,000 WWESP 80 0.05 15,733,000 Dry Scrubber 55 0.11 35,381,000 Step 4: Evaluate Impacts and Document Results The two process boilers have very modest SO 2 emissions at 0.25 TPY. A wet scrubber would reduce emissions by 80 percent, but at an annual cost of about $1.5 million and a cost-effectiveness of $7,448,000 per ton. Step 5: Evaluate Visibility Impacts Visibility impacts were not modeled because additional reductions are not cost-effective. Step 6: Propose BART This BART analysis shows that adding a control device to control SO 2 emissions from the boilers would yield a very modest emission reduction at a multi-million dollar per ton cost. Thus, EPA is proposing retaining the 1.2% by weight sulfur content limit on the boilers when oil is burned. NO X Analysis Step 1: Identification of Available Retrofit Control Technologies • External Flue Gas Recirculation, • Low-NO X Burners, • Low-NO X Burners with Overfire Air, • Induced Flue Gas Recirculation Burners, • Low Excess Air, • Reburning, • Energy Efficiency Projects, • Alternate Fuels, • Non-Selective Catalytic Reduction, • Selective Catalytic Reduction (SCR), • Regenerative SCR, • Selective Non-Catalytic Reduction, and • Low Temperature Oxidation. Step 2: Elimination of Technically Infeasible Options External flue gas recirculation was eliminated as process boilers #1 and #2 do not have the capability of control at the burner tip, which is needed for this control technology. As noted in SO 2 determination, Tilden has already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially emission reductions. Due to the uncertainty and generalization of this category, this option was eliminated. Similarly, Tilden eliminated alternative fuels because the environmental and economic benefits of such a change are uncertain and limited fuel options are available for the boilers. Operating a boiler with low excess air minimizes NO X production during combustion. Tilden already operates process boiler #1 and #2 with low excess air. This option was thus not evaluated further as the benefit has already been achieved. Reburning is infeasible as the Tilden boilers do not burn solid fuel. Regenerative SCR has only been used on wood-fired boilers. This technology has not been applied to liquid or natural gas fired boilers. Regenerative SCR is currently infeasible for the Tilden boilers. Low temperature oxidation is a post-combustion technology that uses an oxidant to oxide pollutants including NO X . A scrubbing system is then used to remove the nitrates. Low temperature oxidation is an emerging technology that is currently infeasible as BART control on the Tilden boilers. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the NO X emission reductions projected by Tilden with the technically feasible technologies. Table V-B.38—Projected Annual NO X Emission Reductions [TPY] Control technology Control efficiency (percent) Emissions Cost None (baseline) 79.23 SCR 80 15.85 $39,888 LNB/Flue Gas Recirculation 75 19.81 5,112 LNB/OFA 67 26.15 7,361 LNB 50 36.61 7,244 Selective Non-Catalytic Reduction 50 36.61 11,833 Step 4: Evaluate Impacts and Document Results The two process boilers have modest NO X emissions at about 80 TPY each. The combustion control technologies produce good control efficiencies at a lower cost compared to the post-combustion options. All the combustion control options have similar costs. A low NO X burner coupled with flue gas recirculation produces a 59.42 TPY NO X reduction per unit, the greatest control, at a cost of $5,122 per ton. Step 5: Evaluate Visibility Impacts Visibility impacts were not modeled because no additional reductions are required. Step 6: Propose BART Given that the control options are modest reductions in NO X emission on a TPY basis, that modest reduction would need to provide a strong visibility improvement or be trivial in cost to justify a BART limit indicative of additional control. That is not the case for the process boilers. Thus, EPA is proposing the current good combustion practice as the NO X emission restrictions for both Process Boiler #1 and Process Boiler #2. Line 1 Dryer The Line 1 Dryer includes a combustion box in which natural gas and used oil is burned as fuel. The flue gas from the combustion box flows into a rotary dryer that repeatedly tumbles wet taconite ore concentrate through the flue gas stream to reduce the amount of entrained moisture in the taconite ore concentrate. The particulate emissions from the dryer are controlled by cyclones and impingement scrubbers in series. The dryer is only permitted to use natural gas and used oil for fuel. The Line 1 Dryer has low emissions of SO 2 due to the low sulfur content of the permitted fuels. In addition, collateral SO 2 reductions occur within the existing impingement scrubbers, and therefore the existing scrubber is considered a low-efficiency SO 2 scrubber. SO 2 Analysis Step 1: Identification of Available Retrofit Control Technologies • Wet Walled Electrostatic Precipitator, • Wet Scrubber, • Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection), • Spray Dryer Absorption (SDA), • Energy Efficiency Projects, • Alternate Fuels, and • Coal Processing. Step 2: Elimination of Technically Infeasible Options The Line 1 Dryer cannot burn solid fuel, which eliminates coal processing. Tilden has already implemented energy efficiency projects on the dryer. Each project carries its own fuel usage reductions and potentially emission reductions. Due to the uncertainty and generalization of this category, this option was eliminated. Dry sorbent injection uses a fabric filter, “baghouse,” as part of the control system. The Line 1 Dryer exhaust is saturated with moisture. Such moisture would foul the baghouse. The same is true if the baghouse is placed following the wet scrubber into which the dryer currently exhausts. The dry sorbent injection system is thus technically infeasible for the Line 1 Dryer. The SDA system also uses a baghouse to capture the dry solids. The moisture in the dryer exhaust similarly creates problems with the baghouse. Thus, SDA is infeasible for Tilden's Line 1 Dryer. Alternative fuels are infeasible because the environmental and economic benefits of such a change are uncertain, the limited fuel options available, and the fact that natural gas and oil are the fuels used for the dryer. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the SO 2 emission reductions projected by Tilden with the technically feasible technologies. Table V-B.39—Projected Annual SO 2 Emission Reductions [TPY] Control technology Control efficiency (percent) Emissions Cost None (baseline) 34.07 Wet Scrubber 80 6.81 $25,103 WWESP 80 6.81 52,432 Step 4: Evaluate Impacts and Document Results The Line 1 Dryer has SO 2 emissions of 34.07 TPY. The moisture in the dryer exhaust limits the control options for this unit. A wet scrubber would reduce emissions by 27.26 TPY or 80 percent at an annual cost of about $25,000. The SO 2 emissions from this unit are already limited by fuel restrictions and the existing low-efficiency SO 2 scrubber. Step 5: Evaluate Visibility Impacts Visibility impacts were not modeled because no additional reductions are required. Step 6: Propose BART This BART analysis shows that adding a control device to control SO 2 emissions from the boilers would yield a modest emission reduction at a cost that could exceed $25,000 per ton. Thus, EPA is proposing retaining the fuel restriction of 1.5% by weight sulfur content limit when oil is burned. NO X Analysis Step 1: Identification of Available Retrofit Control Technologies • External Flue Gas Recirculation, • Low-NO X Burners (LNB), • Low-NO X Burners with Overfire Air, • Induced Flue Gas Recirculation Burners, • Low Excess Air, • Reburning, • Energy Efficiency Projects, • Alternate Fuels, • Non-Selective Catalytic Reduction, • Selective Catalytic Reduction (SCR), • Regenerative SCR, • Selective Non-Catalytic Reduction, and • Low Temperature Oxidation. Step 2: Elimination of Technically Infeasible Options External flue gas recirculation was eliminated as the configuration of the Line 1 Dryer burner does have the capability of control at the burner tip, which is needed for this control technology. As noted in the SO 2 determination, Tilden has already implemented energy efficiency projects. Each project carries its own fuel usage reductions and potentially emission reductions. Due to the uncertainty and generalization of this category, this option was eliminated. Similarly, Tilden eliminated alternative fuels because the environmental and economic benefits of such a change are uncertain and limited fuel options are available for the boilers. Induced flue gas recirculation burner technology is infeasible for the Line 1 Dryer. Operating a boiler with low excess air minimizes NO X production during combustion. Similar to process boiler #1 and #2, the dryer is already operated with low excess air. This option was thus not evaluated further as the benefit has already been achieved. Reburning is infeasible as the Line 1 Dryer does not burn solid fuel. Regenerative SCR has only been used on wood-fired boilers. This technology has not been applied to liquid or natural gas fired burners. Regenerative SCR is currently infeasible for the Line 1 Dryer. Low temperature oxidation is a post-combustion technology that uses an oxidant to oxide pollutants including NO X . A scrubbing system is then used to remove the nitrates. Low temperature oxidation has not been applied on a taconite dryer. It is currently considered infeasible as BART control option on the dryer unit. Step 3: Evaluation of the Control Effectiveness of the Remaining Control Technologies The following table illustrates the NO X emission reductions projected by Tilden with the technically feasible technologies. Table V-B.40—Projected Annual NO X Emission Reductions [TPY] Control technology Control efficiency percent Emissions Cost None (baseline) 15.1 SCR 80 3.02 $83,472 LNB/Flue Gas Recirculation 75 3.77 11,891 LNB/OFA 67 4.98 11,535 LNB 50 7.55 8,090 Selective Non-Catalytic Reduction 50 7.55 36,949 Step 4: Evaluate Impacts and Document Results The Line 1 Dryer has modest NO X emissions of 15.1 TPY. The combustion control technologies produce good control efficiencies at a lower cost compared to the post-combustion options. A low NO X burner produces a 7.55 TPY NO X reduction at a cost of $8,090 per ton. Step 5: Evaluate Visibility Impacts Visibility impacts were not modeled because no additional reductions are required. Step 6: Propose BART Given that the control options are modest reductions in NO X emission on a TPY basis, that modest reduction would need to provide a strong visibility improvement or be trivial in cost to justify a BART limit indicative of additional control. That is not the case for the Tilden Line 1 Dryer. Thus, EPA is proposing the current good combustion practice as the NO X emission restrictions for the Line 1 Dryer. C. Bart Visibility Improvement Analysis 1. Background There are five factors considered in a case-by-case BART analysis once a source has been determined to be subject to BART. The first four pertain to identifying and evaluating available control technologies based on technical feasibility, emission control levels, control cost effectiveness, and energy and non-air quality environmental impacts. The first four factors have been discussed elsewhere in this proposed rulemaking. The fifth factor covers the visibility improvements resulting from the BART emission controls. The “Final Regional Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” document discussed in EPA's “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations” final rule (70 FR 39104) (Regional Haze Rule) addresses application of the fifth factor. Although it is a required element of a BART analysis, there is substantial flexibility allowed in determining how the visibility impacts factor is implemented and how much weight and significance is assigned to this factor. 2. Visibility Improvement Modeling EPA is relying on visibility improvement modeling conducted previously by the MPCA and documented in MPCA's document “Visibility Improvement Analysis of Controls Implemented Due to BART Determinations on Emission Units Subject-to-BART,” October 23, 2009, and also detailed in “Appendix 9.5: BART Visibility Modeling,” included as part of MPCA's December 2009 regional haze SIP submittal. The visibility improvement modeling conducted by MPCA examined the degree of visibility improvement in the Class I areas of Voyageurs National Park (Voyageurs), Boundary Waters Canoe Area Wilderness (Boundary Waters), and Isle Royale National Park (Isle Royale), determined to be impacted by NO X and SO 2 sources and State-estimated BART emission reductions covered in MPCA's BART analysis. The sources investigated by the MPCA, and of interest in our BART proposed rule, were Minnesota Power-Boswell Energy Center, Minnesota Power-Taconite Harbor, Northshore Mining-Silver Bay, and United Taconite-Fairlane Plant (now named United Taconite). These sources are located in the same general area as the sources addressed by BART determinations in this proposed rule. The discussion below uses MPCA's emissions data and modeled visibility impact data to derive visibility impact ratios as a function of changes in emissions of NO X and SO 2 at MPCA-modeled facilities. These visibility-emissions ratios were then applied to the BART-based emission changes for the sources subject to this BART rule to derive possible visibility impacts. The modeling system used by MPCA for BART visibility analyses is discussed in detail in “Technical Support Document of the Minnesota State Implementation Plan for Regional Haze,” May 2009, and in Appendix 9.5 of MPCA's December 2009 regional haze SIP submittal. The system utilizes: • Comprehensive Air Quality Model (CAMx) as the photochemical modeling tool, • The Pennsylvania State University/National Center for Atmospheric Research (PSU/NCAR) Mesoscale Meteorological Model (MM5) as the meteorological model, • Emissions Modeling System (EMS-2003) as the emissions model. The base period modeling for the MPCA work included emissions from 2002. The Particulate Source Apportionment Technology (PSAT) tool in CAMx, along with the new IMPROVE visibility extinction formula (to calculate light extinction resulting from monitored or modeled nitrate, sulfate, and PM 2.5 concentrations and assumed relative humidity (pH) extinction factors) was used to evaluate air quality/visibility impacts from the individual sources. The modeling domain featured a 36 kilometer resolution grid extending over the eastern two-thirds of the United States, and encompassed a smaller 12 kilometer resolution nested modeling domain, with Plume-in-Grid (PiG) concentration estimates, covering all of Minnesota. Visibility was assessed in each of the three Class I areas using 15 modeling receptors in Voyageurs, 62 modeling receptors in Boundary Waters, and 15 modeling receptors in Isle Royale. The MPCA modeling examined the impact of the BART controls on both the number of days (ΔDays) with a change (increase) in deciview 12 above 0.5 (ΔDays > 0.5) and the 98th percentile change in deciview values (Δdv). 12 The deciview is a visual index designed to be linear with respect to perceived visibility changes over its entire range in a way that is analogous to the decibel index for sound. The deciview scale is zero for pristine conditions and increases as visibility degrades. Only one of the sources examined by MPCA and addressed here included emission changes from furnaces at a taconite facility. This facility, United Taconite, is located in St. Louis County, Minnesota, roughly 60-80 kilometers from the Class I areas in Northern Minnesota, Voyageurs and Boundary Waters, and approximately 120 kilometers from Isle Royale. The MPCA modeling compared the 2002 actual emissions used in Minnesota's regional haze SIP modeling to the emissions assumed based on the state-determined BART emission controls with corresponding modeled emission reductions for NO X and sulfur dioxide. Modeling was conducted for the meteorological years of 2002 and 2005. The results are shown in MPCA's BART analysis in terms of the change in Δdv and ΔDays for PM 2.5 , 13 sulfate (SO 4 ), and nitrate (NO 3 ). 13 All fine particulates, including sulfates, nitrates, and other fine particulate components. The MPCA visibility modeling documentation details visibility due to the implementation of BART controls for all of the sources considered by the State. However, the FIP covered by this proposed rule only addresses BART control of furnaces located at taconite facilities. Therefore, we have given special attention to the visibility modeling results for the one taconite facility addressed in detail in MPCA's BART visibility modeling discussion, United Taconite. The detailed modeling information for United Taconite, as presented in MPCA's visibility modeling documentation is duplicated below: Table V-C.1—Emissions (United Taconite) [Actual 2002 Emissions in Tons Modeled] Description Stack ID NO X SO 2 PM 2.5 PM 10 Facility Elevated Stack Total* 1,765 3,222 183 473. BART Unit Stack Total SV049 1,764 3,222 13 367. BART Unit Stack Percent of Facility Total Emissions* 100% 100% 7% 78%. BART Unit Stack Total with BART Controls 1,764 1,385 No BART Controls. BART Unit Stack Emission Reduction due to BART Controls 0% −57% * Facility total only accounts for emissions from elevated stacks. The criteria for elevated stacks is those with a plume rise of 50 meters or more as calculated by the emissions model. Tables V-C.2 Through V-C.4—Number of Days With Visibility Degradation > 0.5 dv and 98th Percentile Deciview Impact Values (United Taconite) Parameter Met Year Class I Area Boundary Waters Base BART Change Voyageurs Base BART Change Isle Royale Base BART Change PM 2.5 Days > 0.5 dv 2002 59 44 −15 32 20 −12 8 1 −7 2005 40 24 −16 22 11 −11 3 2 −1 '02 & 05 99 68 −31 54 31 −23 11 3 −8 98th Percentile dv 2002 3.0 1.7 −1.3 1.8 0.8 −0.9 0.6 0.3 −0.3 2005 1.5 1.1 −0.4 1.0 0.7 −0.3 0.4 0.2 −0.2 '02 & 05 3.1 1.9 −1.2 1.9 1.1 −0.8 0.6 0.3 −0.3 SO 4 Days > 0.5 dv 2002 47 29 −18 29 17 −12 8 0 −8 2005 32 15 −17 20 6 −14 3 0 −3 '02 & 05 79 44 −35 49 23 −26 11 0 −11 98th Percentile dv 2002 3.0 1.6 −1.4 1.7 0.8 −0.9 0.5 0.3 −0.3 2005 1.4 0.7 −0.7 0.9 0.5 −0.4 0.4 0.2 −0.2 '02 & 05 3.0 1.7 −1.3 1.9 1.0 −0.9 0.6 0.3 −0.3 NO 3 Days > 0.5 dv 2002 5 8 3 0 1 1 0 0 0 2005 7 11 4 1 4 3 0 1 1 '02 & 05 12 19 7 1 5 4 0 1 1 98th Percentile dv 2002 0.4 0.5 0.1 0.1 0.1 0.0 0.1 0.1 0.0 2005 0.5 0.6 0.1 0.2 0.2 0.1 0.1 0.1 0.0 '02 & 05 0.6 0.7 0.2 0.2 0.3 0.1 0.1 0.1 0.0 As the tables indicate, while there were no NO X emission reductions associated with the State's assessed BART emission controls at United Taconite, the SO 2 emission reductions resulted in reductions in the number of days with deciview changes above 0.5 at all three Class I areas, including ΔDays reductions in excess of 10 at Boundary Waters and Voyageurs. Additionally, the 98th percentile deciview values were reduced (Δdv) for each Class I area. These improvements were associated with a 1,837 tons per year reduction in SO 2 emissions at this facility. Because there were no reductions in NO X at United Taconite associated with the State-determined BART emission controls, the improvement in visibility due to SO 2 emission reductions are offset by visibility degradation resulting from small nitrate increases. According to MPCA, the reduced levels of SO 2 downwind from United Taconite would allow more ammonia in the atmosphere to become available to react with NO X to form ammonium nitrate, a compound that can contribute to visibility impairment. The modeled SO 2 emission reduction and visibility impacts for PM 2.5 can be used to derive visibility impact/emission reduction ratios at each of the Class I areas. Table V-C.5 presents the modeled emission reductions and derived visibility impact ratios for fine particulates for United Taconite at each of the Class I areas. Note that the ΔDaysPM 2.5 numbers used in this table (and in subsequent tables) are annual averages. Also note that, in this table and in subsequent tables, we have considered Δdv and ΔDays values for PM 2.5 , which include the visibility impacts of both nitrates and sulfates, as well as other fine particulate components. Table V-C.5—BART NO X and SO 2 Emission Reductions and Modeled Visibility Impact/Emission Reduction Ratios for Fine Particulates at Class I Areas for United Taconite Parameter Boundary Waters Voyageurs Isle Royale NO X Emissions Decrease 0 tons/year SO 2 Emissions Decrease (ΔSO 2 ) 1,837 tons/year Δdv PM2.5 −1.2 −0.8 −0.3 Δdv PM2.5 /ΔSO 2 −0.00065 −0.00043 −0.000098 ΔDays PM2.5 −10 −8 −3 ΔDays PM2.5 /ΔSO 2 −0.0054 −0.0044 −0.0016 Other sources addressed in MPCA's modeling study would reduce both NO X and SO 2 emissions through the implementation of BART emission controls. Three examples of sources considered for BART controls are located near the Class I areas of interest, Minnesota Power-Taconite Harbor, Minnesota Power-Boswell Energy Center, and Northshore Mining-Silver Bay. Both Minnesota Power-Taconite Harbor and Northshore Mining-Silver Bar are located near Lake Superior and east of the Minnesota taconite facilities considered in this FIP proposed rule. Minnesota Power-Boswell Energy Center is located in northern Minnesota and west of the area encompassing the Minnesota taconite facilities considered in this FIP proposed rule. All three of these source facilities addressed by the MPCA would have both NO X emission reductions and SO 2 emission reductions under MPCA's-determined BART emission controls. We have used the State's modeled BART emission reductions and visibility impacts for fine particulates to determine the sensitivity of visibility parameters for the Class I areas to changes in NO X and SO 2 emissions. The modeled emission changes, Δdv, and ΔDays values used to calculate the sensitivity of visibility parameters to emission changes were taken from Appendix 9.5 of Minnesota's December 2009 SIP revision submittal. Table V-C.6 presents the modeled emission reductions and derived visibility impact ratios for Minnesota Power-Boswell Energy Center at each of the Class I areas. Table V-C.6—BART NO X and SO 2 Emission Reductions and Modeled Visibility Impact/Emission Reduction Ratios for Fine Particulates at Class I Areas for Minnesota Power-Boswell Energy Center Parameter Boundary Waters Voyageur Isle Royale NO X Emissions Decrease (ΔNO X ) 3,978 tons/year SO 2 Emissions Decrease (ΔSO 2 ) 11,952 tons/year Δdv PM2.5 −2.1 −2.0 −0.9 Δdv PM2.5 /ΔNO X −0.00053 −0.00050 −0.00023 Δdv PM2.5 /ΔSO 2 −0.00018 −0.00017 −0.000075 ΔDays PM2.5 −30 −21 −15 ΔDays PM2.5 /ΔNO X −0.0075 −0.0053 −0.0038 ΔDays PM2.5 /ΔSO 2 −0.0025 −0.0018 −0.0013 Table V-C.7 presents the modeled emission reductions and derived visibility impact ratios for fine particulates for Minnesota Power-Taconite Harbor at each of the Class I areas. Table V-C.7—BART NO X and SO 2 Emission Reductions and Modeled Visibility Impact/Emission Reduction Ratios for Fine Particulates at Class I Areas for Minnesota Power-Taconite Harbor Parameter Boundary Waters Voyageur Isle Royale NO X Emissions Decrease (ΔNO X ) 399 tons/year SO 2 Emissions Decrease (ΔSO 2 ) 566 tons/year Δdv PM2.5 −0.4 −0.1 −0.3 Δdv PM2.5 /ΔNO X −0.0010 −0.00025 −0.00075 Δdv PM2.5/ ΔSO 2 −0.00071 −0.00018 −0.00053 ΔDays PM2.5 −4 −2 −3 ΔDays PM2.5 /ΔNO X −0.010 −0.0050 −0.0075 ΔDays PM2.5 /ΔSO 2 −0.0071 −0.0035 −0.0053 Table V-C.8 presents the modeled emission reductions and derived visibility impact ratios for fine particulates for Northshore Mining-Silver Bay at each of the Class I areas. Table V-C.8. BART NO X and SO 2 Emission Reductions and Modeled Visibility Impact/Emission Reduction Ratios for Fine Particulates at Class I Areas for Northshore Mining-Silver Bay Parameter Boundary Waters Voyageur Isle Royale NO X Emissions Decrease (ΔNO X ) 678 tons/year SO 2 Emissions Decrease (ΔSO 2 ) 444 tons/year Δdv PM2.5 −0.2 −0.1 −0.2 Δdv PM2.5 /ΔNO X −0.00029 −0.00023 −0.00029 Δdv PM2.5 /ΔSO 2 −0.00045 −0.00023 −0.00045 ΔDays PM2.5 −5 −1 −3 ΔDays PM2.5 /ΔNO X −0.0074 −0.0015 −0.0044 ΔDays PM2.5 /ΔSO 2 −0.011 −0.0023 −0.0068 The above visibility factor/emission change ratio data show significant variation from source-to-source and between impacted Class I areas. This variation is caused by differences in the relative locations of the sources (relative to the locations of the Class I areas), variations in background sources, variations in transport patterns on high haze factors, and other factors that we cannot assess without detailed modeling of the visibility impacts for the sources as a function of pollutant emission type. The above data, however, can be used to approximate possible visibility impacts due to the production of fine particulates downwind of the taconite facilities addressed in this FIP proposed rule. To estimate the visibility impacts, we have averaged the fine particulate Δdv and ΔDays emission change ratios for NO X and SO 2 for the four sources documented [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2012-19789. Public record. Not legal advice.