```

[Federal Register Volume 77, Number 158 (Wednesday, August 15, 2012)]
[Proposed Rules]
[Pages 49307-49343]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-19789]

[[Page 49307]]

Vol. 77

Wednesday,

No. 158

August 15, 2012

Part VI

Environmental Protection Agency

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40 CFR Part 52

Approval and Promulgation of Implementation Plans; States of Minnesota 
and Michigan; Regional Haze Federal Implementation Plan; Proposed Rule

Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / 
Proposed Rules

[[Page 49308]]

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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.

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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.

[[Page 49309]]

    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 (PM2.5) (e.g., 
sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and 
soil dust), and their precursors (e.g., sulfur dioxide 
(SO2), nitrogen oxides (NOX)). Fine particle 
precursors react in the atmosphere to form PM2.5, which 
impairs visibility by scattering and absorbing light. Visibility 
impairment reduces the clarity, color, and visible distance that one 
can see. PM2.5 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).
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    \1\ Visual range is the greatest distance, in kilometers or 
miles, at which a dark object can be viewed against the sky.
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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.
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    \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.''
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    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\
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    \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).
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    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 Sec.  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

[[Page 49310]]

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.
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    \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.''
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    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.
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    \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.
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    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 
SO2, NOX, 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.

[[Page 49311]]

                Table V-A.1--List of Taconite Facilities
------------------------------------------------------------------------
            State                    Company                Unit
------------------------------------------------------------------------
Minnesota...................  U.S. Steel, Minntac.  Grate-Kiln Lines 3-
                                                     7.
Minnesota...................  Northshore Mining     Straight-Grate
                               Company.              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 SO2.
    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 
NOX and SO2

    EPA proposes to find that BART for NOX for indurating 
furnaces is low NOX burners for both straight-grate and 
grate-kilns. The feasibility of using low NOX burners on 
grate-kilns is based on an October 26, 2011 ``Summary Report for USS On 
NOX 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 NOX Main Burner Final Report & 
Facility NOX Management,'' which states that there has been 
neither an increase in fuel consumption nor degradation of pellet 
quality with the use of a low NOX 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 NOX reduced when burning 
coal and gas and $210/ton of NOX 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 NOX 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 NOX emitted. There is also no increase in combustion 
related emissions, such as carbon monoxide or volatile organic 
compounds, and there is no reason for SO2 emissions to 
increase through use of a low NOX 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

[[Page 49312]]

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 NOX 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 NOX 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 NOX 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 NOX from Pelletizing 
Furnaces,'' by Fives and ``Environmental Benefits for the Adaptation of 
Commonly Used Low-NOX 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 NOX from 
combustion as well as post-treatment methods for NOX 
removal. This was followed by successful bench-scale testing of Fives 
low NOX LE burners to achieve NOX 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 
NOX emissions and a rate of 0.25 lbs. NOX/MMBtu 
at an estimated cost-effectiveness of $370/ton. Based on the results of 
this test program, it was concluded that NOX 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 
NOX 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 NOX burners.
    EPA proposes to determine that BART for SO2 for 
straight-grate kilns is existing controls because these furnaces do not 
burn coal. EPA also proposes to find that BART for SO2 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 SO2, or a 95 percent emission reduction 
requirement, on a 30-day rolling average, has been determined to be 
BART for SO2. 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 SO2 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
------------------------------------------------------------------------
                                                       Control equipment
       Emission unit name              EU No.\7\       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. NOX 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 NOX retrofit control technologies have 
been identified as being available for indurating furnaces:
     External Flue Gas Recirculation,
     Low NOX 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

[[Page 49313]]

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 NOX 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 NOX burners,
     Low NOX 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 NOX emission reductions projected by 
Minntac with the technically feasible control technologies.

                                              Table V-B.2--Pellet Furnace Projected NOX Emission Reductions
                                                                          [TPY]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Assumed
                                                              control
                 NOX Control technology                     efficiency        Line 3          Line 4          Line 5          Line 6          Line 7
                                                             (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
None (Baseline).........................................  ..............           1,345           1,812           1,820           1,776           1,928
Low NOX burners + Ported kilns..........................              15              na             249             273              na              na
Low NOX 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 NOX Control Cost
                                                     [$/Ton]
----------------------------------------------------------------------------------------------------------------
     NOX Control technology           Line 3          Line 4          Line 5          Line 6          Line 7
----------------------------------------------------------------------------------------------------------------
Low NOX burners + Ported kilns..              na          $5,844          $5,974              na              na
Low NOX 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. SO2 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 SO2 reductions occur within the existing 
wet scrubbers, they are considered low efficiency SO2 
scrubbers. Minntac estimates that these existing scrubbers remove 15 to 
30 percent of the SO2 in the exhaust gas from these lines.
Step 1: Identify all Available Retrofit Control Technologies
    Minntac identified the following SO2 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 SO2 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

[[Page 49314]]

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 SO2 
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 SO2 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 
SO2 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 SO2 remaining after the 
existing scrubber. The following tables illustrate the SO2 
emission reductions projected by Minntac with the technically feasible 
control technologies.

                                                            Table V-B.4--Annual SO2 Emissions
                                                                          [TPY]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         Line 3           Line 4           Line 5           Line 6           Line 7           Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline SO2 Emissions............................           329.4            447.5            447.5            544.8            544.8             2314
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                     Table V-B.5--Projected SO2 Emission Reductions
                                                                          [TPY]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 SO2 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 SO2 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 SO2 
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 SO2 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 SO2 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 SO2 controls for Minntac are not reasonably 
cost effective, so visibility impacts were not modeled for additional 
SO2 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 SO2 controls described above, we agree that 
additional SO2 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 SO2/hr for Line 3, 56.1 lb SO2/hr 
for Line 4, 67.9 lb SO2/hr for Line 5, 64.5 lb 
SO2/hr for Line 6, and 67.1 lb SO2/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 NOX retrofit control technologies have 
been identified as being available for the heating boilers:
     External Flue Gas Recirculation,
     Low-NOX 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

[[Page 49315]]

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 NOX emission reductions projected by 
Minntac with the technically feasible control technologies.

                          Table V-B.6--Heating Boiler Projected NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                          Boilers  1, 2,
       NOX Control technology              Control          4,         Emissions             Cost
                                          efficiency         5
 
----------------------------------------------------------------------------------------------------------------
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 NOX 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 NOX emissions generated by the four heating boilers 
at the Minntac facility total 56.7 TPY. The most cost efficient control 
is low NOX burners at $6,653 to $8,646 per ton, which would 
yield a 28.4 TPY reduction.
Step 5: Evaluate Visibility Impacts
    Additional NOX 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 
NOX 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 NOX emission limits 
for the heating boilers. Thus, EPA is not proposing a NOX 
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 NOX 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
------------------------------------------------------------------------
                                                  Control equipment and
       Emission unit name            EU No.           stack numbers
------------------------------------------------------------------------
Indurating Furnace 11--          EU100  CE101/SV101, CE102/
 Hood Exhaust.                                    SV102, CE103/SV103.
Indurating Furnace 11--          EU104  CE104/SV104, CE105/
 Waste Gas.                                       SV105.
Indurating Furnace 12--          EU110  CE111/SV111, E112/
 Hood Exhaust.                                    SV112, CE113/SV113.
Indurating Furnace 12--          EU114  CE114/SV114, CE115/
 Waste Gas.                                       SV115.
------------------------------------------------------------------------

a. NOX BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    The following NOX retrofit control technologies have 
been identified as being available for indurating furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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 NOX emission 
baseline for Northshore and the reductions achievable using low 
NOX burners.

[[Page 49316]]

                                                  Table V-B.8--Projected Annual NOX Emission Reduction
                                                                          [TPY]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Furnace 11                        Furnace 12
                            NOX Control                                  Assumed     -------------------------------------------------------------------
                                                                         control        Hood exhaust      Waste gas       Hood exhaust      Waste gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
None (Baseline)....................................................  ...............            112.4            273.7            109.9            267.7
Low NOX Burners....................................................            70%               79              192               77              187
--------------------------------------------------------------------------------------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
Cost of Control

                                Table V-B.9--Pellet Furnace Projected NOX Control
                                       [Cost per ton of pollutant removed]
----------------------------------------------------------------------------------------------------------------
                                                 Furnace 11       Furnace 11       Furnace 12       Furnace 12
           NOX Control Technology                  (hood)          (waste)           (hood)          (waste)
----------------------------------------------------------------------------------------------------------------
Low NOX 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. SO2 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 SO2 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 SO2 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 SO2 remaining after the 
existing scrubber. The following tables illustrate the SO2 
emission reductions projected by Northshore with the technically 
feasible control technologies.

                                                           Table V-B.10--Annual SO2 Emissions
                                                                          [TPY]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Furnace 11                        Furnace 12
                                                                    --------------------------------------------------------------------      Total
                                                                       Hood exhaust      Waste gas       Hood exhaust      Waste gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline SO2 Emissions.............................................            28.6              9.5             26.3              8.8             73.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 49317]]

                                 Table V-B.11--Projected SO2 Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                            Furnace 11                      Furnace 12
     SO2 control technology      ----------------------------------------------------------------      Total
                                   Hood exhaust      Waste gas     Hood exhaust      Waste gas
----------------------------------------------------------------------------------------------------------------
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 SO2 removed. The cost of installing 
and operating a secondary wet scrubber was estimated to be between 
$140,000 and $420,000 per ton of SO2 removed.
Energy and Non-air Quality Environmental Impacts
    Because the cost of additional SO2 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 SO2 controls for Northshore are not 
reasonably cost effective, so visibility impacts were not modeled for 
additional SO2 controls.
Step 6: Propose BART
    Although we do not agree that MPCA and Northshore have adequately 
documented the infeasibility of all of the SO2 controls 
described above, we agree that, because Northshore is burning natural 
gas and fuel oil, additional SO2 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 SO2/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 SO2/hr for Furnace 
11 and 17.1 lb SO2/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 NOX retrofit control technologies have 
been identified as being available for the process boilers:
     External Flue Gas Recirculation,
     Low-NOX 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-NOX 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 NOX emission 
reductions projected by Northshore with the technically feasible 
technologies.

                             Table V-B.12--Projected Annual NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Control
                     NOX Control technology                         efficiency       Emissions         Cost
                                                                     (percent)
----------------------------------------------------------------------------------------------------------------
None (Baseline).................................................  ..............            41.2  ..............
Selective Catalytic Reduction...................................              90             4.1         $30,160
Low-NOX Burners w/Induced Flue Gas Recirculation................              75            10.3          10,675
Low-NOX Burners.................................................              50            20.6             723

[[Page 49318]]

 
Selective Non-Catalytic Reduction...............................              50            20.6          12,126
----------------------------------------------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
    The NOX emissions generated by the two process boilers 
are of modest size, totaling 41.2 TPY. The most cost efficient control 
is low NOX 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 NOX 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 NOX 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 NOX 
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 NOX 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
------------------------------------------------------------------------
                                                   Control equipment and
      Emission unit name              EU No.           stack numbers
------------------------------------------------------------------------
Line 1 Pellet Induration......  EU40.............  SV046
Line 2 Pellet Induration......  EU42.............  SV048, SV049
------------------------------------------------------------------------

a. NOX BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    United Taconite identified the following NOX retrofit 
control technologies as being available for indurating furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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 NOX emission baseline for 
United Taconite and the reductions achievable using low NOX 
burners.

                             Table V-B.14--Projected Annual NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Assumed
                           NOX Control                                control         Line 1          Line 2
----------------------------------------------------------------------------------------------------------------
None (Baseline).................................................  ..............            1643            3687
Low NOX Burners.................................................             70%            1150            2581
----------------------------------------------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results

               Table V-B.15--Pellet Furnace Projected NOX
------------------------------------------------------------------------
                      NOX Control                        Line 1   Line 2
------------------------------------------------------------------------
Low NOX 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. SO2 BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    In its BART analysis, United Taconite identified the following 
SO2 reduction

[[Page 49319]]

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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Additional
                                    Uncontrolled    Existing     control                  Max hourly
                                         SO2          SO2         (BART      lb/ MMBtu     emission     Tons SO2     Tons SO2      Total      $/Ton SO2
        Control technology            emissions     removal      analysis       SO2          rate       emitted      removed     annualized    removed
                                     rate  (lb/    efficiency     App A)                   (total)                                  cost
                                       MMBtu)      (percent)    (percent)                  (lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 
SO2 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 SO2 Emission Reductions and Resulting Cost-Effectiveness
----------------------------------------------------------------------------------------------------------------
                                              Assumed
               SO2 Control                    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
------------------------------------------------------------------------
                                                  Control equipment and
       Emission unit name            EU No.           stack numbers
------------------------------------------------------------------------
Indurating Furnace.............           EU026  CE014/SV014, CE015/
                                                  SV015, CE016/SV016,
                                                  CE017/SV017.
------------------------------------------------------------------------

a. NOX BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    ArcelorMittal identified the following NOX retrofit 
control technologies as being available for indurating furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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

[[Page 49320]]

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 NOX emission reductions 
from use of Low NOX burners.

         Table V-B.19--Projected Annual NOX Emission Reductions
                                  [TPY]
------------------------------------------------------------------------
                                    Assumed control
     NOX Control technology           efficiency             Total
------------------------------------------------------------------------
None (Baseline) \6\.............  ..................                3639
Low NOX Burners.................                 70%                2547
------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
    The annualized pollution control cost of installing and operating 
low NOX burners is in Table V-B.20 below.

  Table V-B.20--Pellet Furnace Projected NOX Control Cost-Effectiveness
------------------------------------------------------------------------
                NOX Controls                      Indurating furnace
------------------------------------------------------------------------
Low NOX 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. SO2 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 SO2 reductions 
occur within the existing wet scrubbers, they are considered low 
efficiency SO2 scrubbers. ArcelorMittal estimates that these 
existing scrubbers remove 15 to 30 percent of the SO2 in the 
exhaust gas.
Step 1: Identify all Available Retrofit Control Technologies
    ArcelorMittal identified the following SO2 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 
SO2 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 SO2 
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 SO2 remaining after the 
existing scrubber. The following tables illustrate the SO2 
emission reductions projected by ArcelorMittal with the technically 
feasible control technologies.

                   Table V-B.21--Annual SO2 Emissions
                                  [TPY]
------------------------------------------------------------------------
                                                                 Total
------------------------------------------------------------------------
Baseline SO2 Emissions.......................................      179.2
------------------------------------------------------------------------

             Table V-B.22--Projected SO2 Emission Reductions
                                  [TPY]
------------------------------------------------------------------------
                    SO2 Control technology                       Total
------------------------------------------------------------------------
WWESP........................................................      143.2
Secondary Wet Scrubber.......................................      107.6
------------------------------------------------------------------------

[[Page 49321]]

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 
SO2 removed. The cost of installing and operating a 
secondary wet scrubber was estimated to be approximately $83,000 per 
ton of SO2 removed.
Energy and Non-air Quality Environmental Impacts
    Because the cost of additional SO2 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 SO2 controls for ArcelorMittal are not 
reasonably cost effective, so visibility impacts were not modeled for 
additional SO2 controls.
Step 6: Propose BART
    Although we do not agree that MPCA and ArcelorMittal have 
adequately documented the infeasibility of all of the SO2 
controls described above, we agree that, because ArcelorMittal is 
burning natural gas, additional SO2 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 SO2/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
------------------------------------------------------------------------
                                                   Control equipment and
      Emission unit name              EU No.           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. NOX BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    Hibbing identified the following NOX retrofit control 
technologies as available and applicable to pellet furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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 NOX emission reductions 
resulting from use of low NOX burners.

                             Table V-B.24--Projected Annual NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                      Assumed
             NOX Control technology                   control         Line 1          Line 2          Line 3
                                                    efficiency
----------------------------------------------------------------------------------------------------------------
None (Baseline).................................  ..............         2,143.5         2,143.5         2,247.1
Low NOX 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 NOX burners is in Table V-B.25 below.

[[Page 49322]]

         Table V-B.25--Pellet Furnace Projected NOX Control Cost
                   [cost per ton of pollutant removed]
------------------------------------------------------------------------
         NOX Control Technology            Line 1     Line 2     Line 3
------------------------------------------------------------------------
Low NOX 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. SO2 BART analysis
    Hibbing operates three straight grate indurating furnaces which are 
identified in table V-B.26 below.

                Table V-B.26--Hibbing SO2 Emission Units
------------------------------------------------------------------------
                                                   Control equipment and
      Emission unit name              EU No.           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 SO2 reductions 
occur within the existing wet scrubbers, they are considered low 
efficiency SO2 scrubbers. Hibbing estimates that these 
existing scrubbers remove 15 to 30 percent of the SO2 in the 
exhaust gas from Lines 1, 2, and 3.
Step 1: Identify all Available Retrofit Control Technologies
    Hibbing identified the following SO2 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 SO2 remaining after the 
existing scrubber. Hibbing also expected that modifying the existing 
wet scrubber would control between 0 and 50 percent of the 
SO2 currently emitted. The following tables illustrate the 
SO2 emission reductions projected by Hibbing with the 
technically feasible control technologies.

                                       Table V-B.27--Annual SO2 Emissions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                   Line 1           Line 2           Line 3           Total
----------------------------------------------------------------------------------------------------------------
Baseline SO2 Emissions......................           202.2            179.5            188.1            569.8
----------------------------------------------------------------------------------------------------------------

                                 Table V-B.28--Projected SO2 Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
             SO2 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

[[Page 49323]]

 
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 
SO2 removed. The cost of installing and operating a 
secondary wet scrubber was estimated to be between $57,000 and $67,000 
per ton of SO2 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 SO2 controls 
described above, we agree that, because Hibbing is burning natural gas, 
additional SO2 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 SO2/hr for Line 1, 63.0 lb 
SO2/hr for Line 2, and 64.0 lb SO2/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. NOX BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    Keetac identified the following NOX retrofit control 
technologies as available and applicable to pellet furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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 
NOX emissions. Switching to another fuel such natural gas 
(which Keetac already is capable of using) could exchange one 
visibility impairing pollutant for another (NOX for 
SO2). 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 NOX emission 
reductions resulting from use of low NOX burners.

                             Table V-B.30--Projected Annual NOX Emission Reductions
----------------------------------------------------------------------------------------------------------------
                                                                    Assumed control         Phase II furnaces
                    NOX control technology                       efficiency  (percent)            (TPY)
----------------------------------------------------------------------------------------------------------------
None (Baseline)...............................................  .......................                  4,154.0
Low NOX Burners...............................................                       70                    2,908
Ported Kiln...................................................                        5                    207.7
----------------------------------------------------------------------------------------------------------------

[[Page 49324]]

Step 4: Evaluate Impacts and Document Results

                              Table V-B.30
                   [COST PER TON OF POLLUTANT REMOVED]
------------------------------------------------------------------------
                NOX control technology                  Phase II furnace
------------------------------------------------------------------------
Low NOX 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 NOX, 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. SO2 BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    Keetac identified the following SO2 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 SO2 removal could be achieved. However, 
Keetac has recently installed new wet scrubbers to control 
SO2 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 SO2 remaining after the 
existing scrubber. The following table illustrates the SO2 
emission reductions projected by Keetac with the technically feasible 
control technologies.

             Table V-B.32--Projected SO2 Emission Reductions
                                  [TPY]
------------------------------------------------------------------------
                                                             Phase II
                 SO2 Control technology                       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 SO2 Control Cost
                    [$ PER TON OF POLLUTANT REMOVED]
------------------------------------------------------------------------
                                                             Phase II
                 SO2 Control technology                       furnace
------------------------------------------------------------------------
WWESP (after existing scrubber).........................         $15,165
Secondary Wet Scrubber (after existing scrubber)........           8,870
------------------------------------------------------------------------

[[Page 49325]]

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 SO2 removal efficiency and a limit, based on CEMS 
data, of 225 lbs SO2 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 SO2 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. NOX BART Analysis
Step 1: Identify All Available and Technically Feasible Retrofit 
Technologies
    The following NOX retrofit control technologies have 
been identified as being available and applicable for indurating 
furnaces:
     External Flue Gas Recirculation,
     Low-NOX 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 NOX 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 NOX emission reductions 
resulting from use of low NOX burners.

         Table V-B.34--Projected Annual NOX Emission Reductions
------------------------------------------------------------------------
                                                 Assumed
                                                 control    Line 1 (tons
           NOX Control Technology              efficiency     per year)
                                                (percent)
------------------------------------------------------------------------
None (Baseline).............................  ............         4,613
Low NOX burners.............................            70         3,229
------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
    The annualized pollution control cost of installing and operating 
low NOX burners is in Table V-B.35 below.

         Table V-B.35--Pellet Furnace Projected NOX Control Cost
                       [COST PER TON OF POLLUTANT]
------------------------------------------------------------------------
          NOX Control technology                 Indurating furnace
------------------------------------------------------------------------
Low NOX 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. SO2 BART Analysis
Step 1: Identify All Available Retrofit Control Technologies
    Tilden identified the following SO2 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 SO2 emission reductions projected by Tilden 
technologies.

             Table V-B.36--Projected SO2 Emission Reductions
                                  [TPY]
------------------------------------------------------------------------
                   SO2 Control technology                       Line 1
------------------------------------------------------------------------
Spray Dry Absorption.......................................      1,037.8
Wet Walled ESP.............................................        922.5
Wet Scrubber...............................................        922.5
Dry Sorbent Injection......................................        634.2
------------------------------------------------------------------------

[[Page 49326]]

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.
SO2 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 SO2 emission 
reductions projected by Tilden with the technically feasible 
technologies.

                             Table V-B.37--Projected Annual SO2 Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Control
                       Control technology                           efficiency       Emissions         Cost
                                                                     (percent)
----------------------------------------------------------------------------------------------------------------
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 SO2 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 
SO2 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.
NOX Analysis
Step 1: Identification of Available Retrofit Control Technologies
     External Flue Gas Recirculation,
     Low-NOX Burners,
     Low-NOX 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 
SO2 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 NOX 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 NOX. 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 NOX emission 
reductions projected by Tilden with the technically feasible 
technologies.

[[Page 49327]]

                             Table V-B.38--Projected Annual NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Control
                       Control technology                           efficiency       Emissions         Cost
                                                                     (percent)
----------------------------------------------------------------------------------------------------------------
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 NOX 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 
NOX burner coupled with flue gas recirculation produces a 
59.42 TPY NOX 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 
NOX 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 NOX 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 SO2 
due to the low sulfur content of the permitted fuels. In addition, 
collateral SO2 reductions occur within the existing 
impingement scrubbers, and therefore the existing scrubber is 
considered a low-efficiency SO2 scrubber.
SO2 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 SO2 emission 
reductions projected by Tilden with the technically feasible 
technologies.

                             Table V-B.39--Projected Annual SO2 Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Control
                       Control technology                           efficiency       Emissions         Cost
                                                                     (percent)
----------------------------------------------------------------------------------------------------------------
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 SO2 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 SO2 emissions from this 
unit are already limited by fuel restrictions and the existing low-
efficiency SO2 scrubber.

[[Page 49328]]

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 
SO2 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.
NOX Analysis
Step 1: Identification of Available Retrofit Control Technologies
     External Flue Gas Recirculation,
     Low-NOX Burners (LNB),
     Low-NOX 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 SO2 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 NOX 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 NOX. 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 NOX emission 
reductions projected by Tilden with the technically feasible 
technologies.

                             Table V-B.40--Projected Annual NOX Emission Reductions
                                                      [TPY]
----------------------------------------------------------------------------------------------------------------
                                                                      Control
                       Control technology                           efficiency       Emissions         Cost
                                                                      percent
----------------------------------------------------------------------------------------------------------------
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 NOX 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 
NOX burner produces a 7.55 TPY NOX 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 
NOX 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 NOX 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

[[Page 49329]]

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 NOX and SO2 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 
NOX and SO2 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 PM2.5 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 ([Delta]Days) with a change (increase) in deciview 
\12\ above 0.5 ([Delta]Days > 0.5) and the 98th percentile change in 
deciview values ([Delta]dv).
---------------------------------------------------------------------------

    \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 NOX 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 
[Delta]dv and [Delta]Days for PM2.5,\13\ sulfate 
(SO4), and nitrate (NO3).
---------------------------------------------------------------------------

    \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           NOX             SO2            PM2.5            PM10
----------------------------------------------------------------------------------------------------------------
        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                                100%            100%              7%  78%.
 Facility Total Emissions*.
                                                                               ---------------------------------
BART Unit Stack Total with                               1,764           1,385          No BART Controls.
 BART Controls.
BART Unit Stack Emission                                    0%            -57%
 Reduction due to BART
 Controls.
----------------------------------------------------------------------------------------------------------------
 * 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.

[[Page 49330]]

      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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                           Class I Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Boundary Waters               Voyageurs                 Isle Royale
                          Parameter                            Met Year --------------------------------------------------------------------------------
                                                                           Base     BART    Change    Base     BART    Change    Base     BART    Change
--------------------------------------------------------------------------------------------------------------------------------------------------------
PM2.5
    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
SO4
    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
NO3
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 NOX emission 
reductions associated with the State's assessed BART emission controls 
at United Taconite, the SO2 emission reductions resulted in 
reductions in the number of days with deciview changes above 0.5 at all 
three Class I areas, including [Delta]Days reductions in excess of 10 
at Boundary Waters and Voyageurs. Additionally, the 98th percentile 
deciview values were reduced ([Delta]dv) for each Class I area. These 
improvements were associated with a 1,837 tons per year reduction in 
SO2 emissions at this facility. Because there were no 
reductions in NOX at United Taconite associated with the 
State-determined BART emission controls, the improvement in visibility 
due to SO2 emission reductions are offset by visibility 
degradation resulting from small nitrate increases. According to MPCA, 
the reduced levels of SO2 downwind from United Taconite 
would allow more ammonia in the atmosphere to become available to react 
with NOX to form ammonium nitrate, a compound that can 
contribute to visibility impairment.
    The modeled SO2 emission reduction and visibility 
impacts for PM2.5 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 [Delta]DaysPM2.5 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 [Delta]dv 
and [Delta]Days values for PM2.5, which include the 
visibility impacts of both nitrates and sulfates, as well as other fine 
particulate components.

  Table V-C.5--BART NOX and SO2 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
----------------------------------------------------------------------------------------------------------------
NOX Emissions Decrease..........................                            0 tons/year
                                                 ---------------------------------------------------------------
SO2 Emissions Decrease ([Delta]SO2).............                          1,837 tons/year
                                                 ---------------------------------------------------------------
[Delta]dvPM2.5..................................  -1.2..............................      -0.8         -0.3
[Delta]dvPM2.5/[Delta]SO2.......................  -0.00065..........................      -0.00043     -0.000098
[Delta]DaysPM2.5................................  -10...............................      -8           -3
[Delta]DaysPM2.5/[Delta]SO2.....................  -0.0054...........................      -0.0044      -0.0016
----------------------------------------------------------------------------------------------------------------

    Other sources addressed in MPCA's modeling study would reduce both 
NOX and SO2 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 NOX 
emission reductions and SO2 emission reductions

[[Page 49331]]

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 
NOX and SO2 emissions. The modeled emission 
changes, [Delta]dv, and [Delta]Days 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 NOX and SO2 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
----------------------------------------------------------------------------------------------------------------
NOX Emissions Decrease ([Delta]NOX).............                          3,978 tons/year
                                                 ---------------------------------------------------------------
SO2 Emissions Decrease ([Delta]SO2).............                         11,952 tons/year
                                                 ---------------------------------------------------------------
[Delta]dvPM2.5..................................  -2.1..............................      -2.0         -0.9
[Delta]dvPM2.5/[Delta]NOX.......................  -0.00053..........................      -0.00050     -0.00023
[Delta]dvPM2.5/[Delta]SO2.......................  -0.00018..........................      -0.00017     -0.000075
[Delta]DaysPM2.5................................  -30...............................     -21          -15
[Delta]DaysPM2.5/[Delta]NOX.....................  -0.0075...........................      -0.0053      -0.0038
[Delta]DaysPM2.5/[Delta]SO2.....................  -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 NOX and SO2 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
----------------------------------------------------------------------------------------------------------------
NOX Emissions Decrease ([Delta]NOX).............                           399 tons/year
                                                 ---------------------------------------------------------------
SO2 Emissions Decrease ([Delta]SO2).............                           566 tons/year
                                                 ---------------------------------------------------------------
[Delta]dvPM2.5..................................  -0.4..............................      -0.1          -0.3
[Delta]dvPM2.5/[Delta]NOX.......................  -0.0010...........................      -0.00025      -0.00075
[Delta]dvPM2.5/[Delta]SO2.......................  -0.00071..........................      -0.00018      -0.00053
[Delta]DaysPM2.5................................  -4................................      -2            -3
[Delta]DaysPM2.5/[Delta]NOX.....................  -0.010............................      -0.0050       -0.0075
[Delta]DaysPM2.5/[Delta]SO2.....................  -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 NOX and SO2 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
----------------------------------------------------------------------------------------------------------------
NOX Emissions Decrease ([Delta]NOX).............                           678 tons/year
                                                 ---------------------------------------------------------------
SO2 Emissions Decrease ([Delta]SO2).............                           444 tons/year
                                                 ---------------------------------------------------------------
[Delta]dvPM2.5..................................  -0.2..............................      -0.1          -0.2
[Delta]dvPM2.5/[Delta]NOX.......................  -0.00029..........................      -0.00023      -0.00029
[Delta]dvPM2.5/[Delta]SO2.......................  -0.00045..........................      -0.00023      -0.00045
[Delta]DaysPM2.5................................  -5................................      -1            -3
[Delta]DaysPM2.5/[Delta]NOX.....................  -0.0074...........................      -0.0015       -0.0044
[Delta]DaysPM2.5/[Delta]SO2.....................  -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

[[Page 49332]]

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 [Delta]dv 
and [Delta]Days emission change ratios for NOX and 
SO2 for the four sources documented in Tables V-C.5 through 
V-C.8 above for each of the Class I areas. These averaged visibility 
factor/emission change ratios are summarized in Table V-C.9.

   Table V-C.9--Averaged Visibility Impact/Emission Change Ratios for
                     Analyzed/Impacted Class I Areas
------------------------------------------------------------------------
                                  Boundary
        Parameter ratio            Waters       Voyageurs    Isle Royale
------------------------------------------------------------------------
[Delta]dvPM2.5/[Delta]NOX.....      -0.00061      -0.00033      -0.00040
[Delta]dvPM2.5/[Delta]SO2.....      -0.00050      -0.00025      -0.00029
[Delta]Days/[Delta]NOX........      -0.0083       -0.004        -0.005
[Delta]Days/[Delta]SO2........      -0.0067       -0.0030       -0.0033
------------------------------------------------------------------------

    To calculate the visibility impacts for the Minnesota source 
facilities covered by this FIP proposed rule, we multiplied the total 
estimated BART NOX and SO2 emission reductions 
for each subject facility by the appropriate visibility factor/emission 
change ratios in Table V-C.9 and combined the results to estimate the 
total visibility impacts that would result from the reduction of 
PM2.5 concentrations. The estimated visibility factor 
changes by Class I area for each of the subject taconite facilities in 
Minnesota are given in Tables V-C.10 through V-C.15.

  Table V-C.10--Estimated Emission Reductions and Resulting Changes in
                  Visibility Factors for ArcelorMittal
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......               2,859 tons/year
                              ------------------------------------------
[Delta]dv....................  -1.7...........         -0.9         -1.1
[Delta]Days > 0.5 dv.........  -24............          -11          -18
------------------------------------------------------------------------

  Table V-C.11--Estimated Emission Reductions and Resulting Changes in
                 Visibility Factors for Hibbing Taconite
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......               5,259 tons/year
                              ------------------------------------------
[Delta]dv....................  -3.2...........         -1.7         -2.1
[Delta]Days > 0.5 dv.........  -44............          -21          -26
------------------------------------------------------------------------

  Table V-C.12--Estimated Emission Reductions and Resulting Changes in
                Visibility Factors for Northshore Mining
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......                926 tons/year
                              ------------------------------------------
[Delta]dv....................  -0.6...........         -0.3         -0.4
[Delta]Days > 0.5 dv.........  -8.............           -4           -5
------------------------------------------------------------------------

  Table V-C.13--Estimated Emission Reductions and Resulting Changes in
                 Visibility Factors for United Taconite
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......               3,208 tons/year
                              ------------------------------------------
SO2 Emissions Reduction......               3,639 tons/year
                              ------------------------------------------
[Delta]dv....................  -1.9...........        -0.99        -1.16
[Delta]Days > 0.5 dv.........  -29............          -12          -14
------------------------------------------------------------------------

[[Page 49333]]

  Table V-C.14--Estimated Emission Reductions and Resulting Changes in
                Visibility Factors for U.S. Steel-Keetac
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......               2,908 tons/year
                              ------------------------------------------
[Delta]dv....................  -1.8...........         -1.0         -1.2
[Delta]Days > 0.5 dv.........  -28............          -12          -15
------------------------------------------------------------------------

  Table V-C.15--Estimated Emission Reductions and Resulting Changes in
                Visibility Factors for U.S. Steel-Minntac
------------------------------------------------------------------------
     Visibility factor or
pollutant emissions reduction  Boundary Waters    Voyageur   Isle Royale
------------------------------------------------------------------------
NOX Emissions Reduction......               6,077 tons/year
                              ------------------------------------------
SO2 Emissions Reduction......                980 tons/year
                              ------------------------------------------
[Delta]dv....................  -3.3...........         -1.7         -2.1
[Delta]Days > 0.5 dv.........  -45............          -21          -26
------------------------------------------------------------------------

    From Tables V-C.10 through V-C.15, it can be seen that the BART 
emission controls determined for the Minnesota taconite facilities have 
the potential to produce significant improvements in visibility at all 
three Class I areas.
    The State of Michigan has provided some emissions, air quality, and 
visibility modeling data for Tilden that may be used to provide an 
estimate of the visibility impact for the implementation of BART 
emission controls at Tilden. The Michigan SIP submittal for regional 
haze, dated October 2010, does include BART assessment data for Tilden, 
and Tilden NOX and SO2 emissions have been 
modeled, along with the emissions for many other source facilities to 
derive visibility impacts at two Class I areas, Isle Royale National 
Park and Seney National Wildlife Refuge (Seney). Maximum visibility 
impacts have been determined for each modeled source facility at the 
two Class I areas. To model the visibility impacts, air quality impacts 
were estimated for each pollutant emitted using the CALPUFF model for 
2000-2004 emissions. The modeled air quality impacts were entered 
through the IMPROVE visible extinction equation to calculate the visual 
extinction coefficient for each modeled facility. The facility-specific 
visual extinction coefficients were used to calculate the facility-
specific visibility impact in deciviews. The modeling results for 
Tilden are discussed in Appendices 9H: ``Tilden Mining Company BART 
Technical Analysis,'' 10E: ``Calpuff Modeling, Q/D And Visibility For 
Seney,'' and 10D: ``Calpuff Modeling, Q/D And Visibility For Isle 
Royale'' for Michigan's October 2010 haze SIP submittal.
    The visibility modeling for Tilden shows that it contributed 0.674 
deciviews, with 41 days exceeding 0.5 deciviews from 2002-2004, at Isle 
Royale National Park. Over 96 percent of the modeled SO2 and 
NOX emissions from Tilden were from its indurating furnace. 
Michigan's post control modeling scenario no. 3 reflects both 80 
percent NOX and SO2 emission reductions, which 
are similar to the controls being proposed as BART and these reductions 
result in a 0.501 deciview improvement at IRNP. The visibility impact 
resulting from 70 percent reduction for both SO2 and 
NOX can be approximated by taking \7/8\ of 0.501, which 
results in an improvement of 0.438 deciviews.
    In conclusion, the available information indicates that control of 
emissions from taconite plants in Minnesota and Michigan can be 
expected to yield significant benefits in reducing visibility 
impairment in the Class I areas in the two states. Extrapolating from 
modeling results provided by the two states, the impacts of candidate 
control options range from about 0.5 deciviews to 3.3 deciviews, with 
between about 10 and about 130 fewer days over three years with impacts 
above 0.5 deciviews. While these estimates are not based on direct 
modeling of the scenarios of interest, the scenarios being addressed 
here are sufficiently similar to the scenarios addressed in state 
modeling that EPA considers these estimates to provide adequate 
indication of the benefits of these controls. Each BART determination 
is a function of consideration of visibility improvements and other 
factors for the individual unit, but in general EPA's assessment of 
visibility impacts finds that technically feasible controls that are 
available at a reasonable cost for taconite plants can be expected to 
provide a visibility benefit that makes those controls warranted.

D. Testing and Monitoring, Recordkeeping, and Reporting Requirements.

    To ensure compliance with the proposed BART limits, EPA has 
proposed testing and monitoring requirements for the taconite plants 
subject to this rule. The proposed FIP also includes recordkeeping and 
reporting requirements for these sources.

VI. Proposed Action

    We are proposing to approve the following NOX and 
SO2 BART limits for the taconite plants in Minnesota and 
Michigan that are subject to BART.

U.S. Steel Minntac

    NOX--A limit of 1.2 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.
    SO2--71.3 lbs SO2/hr for Line 3, 56.1 lbs 
SO2/hr for Line 4, 67.9 lbs SO2/hr for Line 5, 
64.5 lbs SO2/hr for Line 6, and 67.1 lbs SO2/hr 
for Line 7. Compliance is to be achieved with these limits within three 
months after the effective date of this rule. These limits are measured 
on a 30-day rolling average.

Northshore Mining

    NOX--A limit of 1.2 lbs/MMBtu on a 30-day rolling 
average for all lines to be

[[Page 49334]]

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. 
An emission limit of 0.085 lb/hr as a 30-day rolling average shall 
apply to each of the boilers, Process Boiler 1 and Process 
Boiler 2, beginning no later than 5 years from the effective 
date of this rule. The process boiler limits shall apply at all times a 
unit is operating.
    SO2--A limit of 16.3 lbs SO2/hr for Furnace 
11 and 17.1 lbs SO2/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. An 80.0 percent SO2 reduction 
requirement is also required for the stacks serving Furnaces 11 and 12. 
Compliance is to be achieved with these limits within 6 months after 
the effective date of this rule.

United Taconite

    NOX--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 of this rule for Line 2 and 2 years and 6 
months after the effective date for Line 1.
    SO2--A limit of 5 ppmv, 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. As 
an alternative, the owner or operator may meet a 95 percent 
SO2 removal efficiency limit, on a 30-day rolling average, 
for Line 1, Line 2, or both lines instead of complying with the 5 ppmv 
limit. The owner or operator shall comply with the limit within 2 years 
after the effective date of this rule for Line 2 and within 4 years 
after the effective date of this rule for Line 1.

ArcelorMittal

    NOX--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.
    SO2--23.0 lbs SO2/hr, on a 30-day rolling 
average, for its indurating furnace. This limit does not apply when the 
subject source is burning fuel oil. Compliance is to be achieved with 
this limit within three months after the effective date of this rule.

Hibbing Taconite

    NOX--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.
    SO2--A limit of 56.0 lbs SO2/hr for Line 1, 
63.0 lbs SO2/hr for Line 2, and 64.0 lbs/hr for Line 3, 
measured on a 30-day rolling average. These limits do not apply when 
the subject source is burning fuel oil. Compliance is to be achieved 
with these limits within 3 months after the effective date of this 
rule.

U.S. Steel Keewatin

    NOX--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 Phase II furnace.
    SO2--Keetac's existing recirculating lime scrubber 
satisfies BART. This scrubber is subject to a 57 percent SO2 
removal efficiency and a limit, based on CEMS data, of 225 lbs 
SO2 per hour on a 30-day rolling average. This scrubber is 
also required to operate at or above a pH of 7.5. Compliance is to be 
achieved with these limits within 90 days after the effective date of 
this rule.

Tilden

    NOX--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 Line 1.
    SO2--A limit of 5 ppmv, on a 30-day rolling average, to 
be achieved within 2 years after the effective date of this rule for 
Line 1. As an alternative, the owner or operator may meet a 95 percent 
SO2 removal efficiency limit, on a 30-day rolling average, 
for Line 1 instead of complying with the 5 ppmv limit. The owner or 
operator shall comply with the limit within 2 years after the effective 
date of this rule. An emission limit of 1.20 percent sulfur content by 
weight shall apply to fuel combusted in Process Boiler 1 
(EUBOILER1) and Process Boiler 2 (EUBOILER2) beginning 3 
months from the effective date of this rule. An emission limit of 1.50 
percent sulfur content by weight shall apply to fuel combusted in the 
Line 1 Dryer (EUDRYER1) beginning 3 months from the effective date of 
this rule.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

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

B. Paperwork Reduction Act

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

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-

[[Page 49335]]

profit enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of this proposed action on 
small entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
EPA's proposal adds additional controls to certain sources. The 
Regional Haze FIP that EPA is proposing for purposes of the regional 
haze program consists of imposing Federal control requirements to meet 
the BART requirement for NOX and SO2 emissions on 
specific units at six sources in Minnesota and one in Michigan. The net 
result of the FIP action is that EPA is proposing emission controls on 
the indurating furnaces at seven taconite facilities and none of these 
sources are owned by small entities, and therefore are not small 
entities.

D. Unfunded Mandates Reform Act (UMRA)

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

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces 
Executive Orders 12612 (Federalism) and 12875 (Enhancing the 
Intergovernmental Partnership). Executive Order 13132 requires EPA to 
develop an accountable process to ensure ``meaningful and timely input 
by State and local officials in the development of regulatory policies 
that have federalism implications.'' ``Policies that have federalism 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.'' Under Executive Order 13132, EPA may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the federal government provides the funds necessary to pay the direct 
compliance costs incurred by State and local governments, or EPA 
consults with State and local officials early in the process of 
developing the proposed regulation. EPA also may not issue a regulation 
that has federalism implications and that preempts State law unless the 
Agency consults with State and local officials early in the process of 
developing the proposed regulation.
    This rule will not have substantial direct effects on the States, 
on the relationship between the national government and the States, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132, because it 
merely addresses the State not fully meeting its obligation to prohibit 
emissions from interfering with other states measures to protect 
visibility established in the CAA. Thus, Executive Order 13132 does not 
apply to this action. In the spirit of Executive Order 13132, and 
consistent with EPA policy to promote communications between EPA and 
State and local governments, EPA specifically solicits comment on this 
proposed rule from State and local officials.

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

    Executive Order 13175, entitled Consultation and Coordination with 
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA 
to develop an accountable process to ensure ``meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' This proposed rule does not have 
tribal implications, as specified in Executive Order 13175. It will not 
have substantial direct effects on tribal governments. Thus, Executive 
Order 13175 does not apply to this rule. However, EPA did discuss this 
action in a June 28 conference call with the Michigan and Minnesota 
Tribes.

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

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

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

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22,

[[Page 49336]]

2001)), because it is not a significant regulatory action under 
Executive Order 12866.

I. National Technology Transfer and Advancement Act

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

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

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

List of Subjects in 40 CFR Part 52

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

    Dated: July 13, 2012.
Susan Hedman,
Regional Administrator, Region 5.
    40 CFR part 52, as proposed to be amended at 77 FR 46912, August 6, 
2012, is proposed to be amended as follows:

PART 52--[AMENDED]

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

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

    2. Section 52.1183 is amended by adding paragraphs (j), (k), (l), 
(m), and (n) to read as follows:

Sec.  52.1183  Visibility protection.

     * * *
    (j) The requirements of section 169A of the Clean Air Act are not 
met because the regional haze plan submitted by the state on November 
5, 2010, does not meet the requirements of 40 CFR 51.308(e) with 
respect to NOX and SO2 emissions from Tilden 
Mining Company L.C. of Ishpeming, Michigan. The requirements for this 
facility are satisfied by complying with Sec.  52.1183(k-n).
    (k)(1) NOX Emission Limits. An emission limit of 1.20 lb 
NOX/MMBtu at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the indurating furnace, Grate Kiln Line 1 
(EUKILN1), beginning 1 year and 6 months from the effective date of 
this rule.
    (2) SO2 Emission Limits. A fuel sulfur content limit of 
no greater than 1.20 percent sulfur content by weight shall apply to 
fuel combusted in Process Boiler 1 (EUBOILER1) and Process 
Boiler 2 (EUBOILER2) beginning 3 months from the effective 
date of this rule. A fuel sulfur content limit of no greater than 1.50 
percent sulfur content by weight shall apply to fuel combusted in the 
Line 1 Dryer (EUDRYER1) beginning 3 months from the effective date of 
this rule.
    (3) The owner or operator of the facility must comply with either 
(3)(i) or (3)(ii) for the Grate Kiln Line 1 (EUKILN1) beginning 2 years 
from the effective date of this rule. The selection must be identified 
in the initial notification of compliance required by this rule.
    (i) An emission limit of 5 ppmv SO2 at 7 percent oxygen, 
based on a 30-day rolling average, shall apply to the Grate Kiln Line 1 
(EUKILN1).
    (ii) A 95.0 percent or greater SO2 removal efficiency by 
the wet/dry FGD, based on a 30-day rolling average, shall apply to the 
Grate Kiln Line 1 (EUKILN1).
    (l) Testing and Monitoring.
    (1) No later than the compliance date of this regulation, the owner 
or operator shall install, certify, calibrate, maintain and operate a 
Continuous Emissions Monitoring System (CEMS) for NOX on 
Tilden Mining Company unit EUKILN1 in accordance with 40 CFR63.8, and 
Appendices B and F of Part 60. The owner or operator shall install, 
certify, calibrate, maintain and operate a continuous diluent monitor 
(O2 or CO2) and continuous flow rate monitor on 
Tilden Mining Company unit EUKILN1 to allow conversion of the 
NOX concentration to units of the standard (lbs/MMBtu). 
Compliance with the emission limits for NOX shall be 
determined using data from the CEMS corrected to 7 percent oxygen.
    (2) No later than the compliance date of this regulation, the owner 
or operator shall install, certify, calibrate, maintain and operate one 
or more CEMS for SO2 on Tilden Mining Company unit EUKILN1 
in accordance with 40 CFR 63.8, and Appendices B and F of Part 60. The 
owner or operator shall install, certify, calibrate, maintain and 
operate one or more continuous diluent monitor(s) (O2 or 
CO2) and continuous flow rate monitor(s) on Tilden Mining 
Company unit EUKILN1 to allow conversion of the SO2 
concentration to units of the standard (ppmv). The number of monitors 
is dependent on the emission standard selected (5 ppmv or a minimum of 
95 percent removal efficiency). Compliance with the emission standard 
selected for SO2 shall be determined using data from the 
CEMS corrected to 7 percent oxygen.
    (3) Except for CEMS breakdowns, out-of-control periods, repairs, 
maintenance periods, calibration checks, and zero and high-level drift 
adjustments, all CEMS required by this rule shall be in continuous 
operation and meet minimum frequency of operation requirements at 
(l)(3)(i-viii) during all periods of process operation of the 
indurating furnaces, including periods of process unit startup, 
shutdown, and malfunction.
    (i) Continuous monitoring systems for measuring the pollutant, 
NOX or SO2, and diluent gas shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (ii) Hourly averages shall be computed using at least one data 
point in each fifteen-minute quadrant of an hour. Notwithstanding this 
requirement, an hourly average may be computed from at least two data 
points separated by a minimum of 15 minutes (where the unit operates 
for more than one quadrant in an hour) if data are unavailable as a 
result of performance of calibration, quality assurance, preventive 
maintenance activities, or backups of data from data acquisition and 
handling system, and recertification events.

[[Page 49337]]

    (iii) When valid pollutant emission data in pounds per hour or 
pounds per million BTU are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA, and incorporated into the 
monitoring plan, to provide emission data for a minimum of 18 hours in 
each 24 hour period and at least 22 out of 30 successive unit operating 
days.
    (iv) Data substitution must not be used for purposes of determining 
compliance under this regulation.
    (v) All CEMS (and emission testing) data shall be reduced and 
reported in units of the applicable standard.
    (vi) A Quality Control Program Plan must be developed and 
implemented for all CEMS required by this rule. The plan will include, 
at a minimum, the information described at 40 CFR 63.8(d), including 
calibration checks, calibration drift adjustments, preventative 
maintenance, data collection, recording and reporting, accuracy audits/
procedures, periodic performance evaluations, and a corrective action 
program for CEMS problems and excess emission events.
    (vii) The owner or operator must develop and implement a written 
startup, shutdown, and malfunction plan for NOX and 
SO2 according to the provisions in Sec.  63.6(e)(3).
    (viii) Performance evaluation of continuous monitoring systems. 
When required by a relevant standard the owner or operator of an 
affected source being monitored with continuous emission monitoring 
equipment shall conduct a performance evaluation of the CEMS. Such 
performance evaluation shall be conducted according to the applicable 
specifications and procedures described in 40 CFR 63.8(e) and 
incorporated into the Quality Control Program Plan.
    (4) No later than the compliance date of this regulation, the owner 
or operator of EUKILN1 shall conduct initial performance testing for 
NOX and SO2, in accordance with the requirements 
of 40 CFR 63.7 and Appendix A of Part 60 to determine compliance with 
applicable emission limits/standards. Specific testing shall be 
described in the intent to test form submitted in accordance with the 
rule. The general reference methods to be used for initial testing will 
include: Methods 1-4, 6-6C, and 7-7E. Performance testing for 
demonstrating compliance with NOX and SO2 
emission limits (if the 5 ppmv emission standard is selected) shall 
include testing emissions after exiting the control device. Performance 
testing for demonstrating compliance with the SO2 removal 
efficiency standard shall include measurement of SO2 
concentrations at the inlet to the control device and in the duct/stack 
after emissions exit the control device.
    (m) Recordkeeping Requirements
    (1)(i) Records must be in a form suitable and readily available for 
expeditious review, according to Sec.  63.10(b)(1).
    (ii) As specified in Sec.  63.10(b)(1), records must be kept for 5 
years following the date of each occurrence, measurement, maintenance, 
corrective action, report, or record.
    (iii) Records must be kept on site for at least 2 years after the 
date of each occurrence, measurement, maintenance, report, or record 
according to Sec.  63.10(b)(1). Records may be kept offsite for the 
remaining 3 years.
    (2) Records listed in paragraphs (2)(i) through (iv) of this 
section must be kept for a period of five years.
    (i) A copy of each notification and report submitted to comply with 
this subpart, including all documentation supporting any initial 
notification or notification of compliance status submitted, according 
to the requirements in 40 CFR 63.10(b)(2)(xiv).
    (ii) The records in 40 CFR 63.6(e)(3)(iii) through (v) related to 
startup, shutdown, and malfunction.
    (iii) Records of performance tests and performance evaluations as 
required in 40 CFR 63.10(b)(2)(viii).
    (iv) Records of all major maintenance conducted on emission units, 
pollution control equipment, and CEMS.
    (3) For each CEMS, the records specified in paragraphs (3)(i) 
through (vii) of this section must be kept.
    (i) Records described in 40 CFR 63.10(b)(2)(vi) through (xi).
    (ii) Previous (that is, superceded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (iii) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (iv) All CEMS data including the date, place, and time of sampling 
or measurement, parameters sampled or measured, and results.
    (v) Records of quality assurance and quality control activities for 
emissions measuring systems including, but not limited to, any records 
required by 40 CFR part 60, appendix B, Performance Specification 2, 
Procedure 1 or 40 CFR part 75.
    (vi) All records required by 40 CFR part 60, appendix F, Procedure 
1 or 40 CFR part 75.
    (vii) Records of the NOX emissions in the units of the 
standard. The owner or operator shall convert the monitored data into 
the appropriate unit of the emission limitation using an appropriate 
conversion factors and F-factors. F-factors used for purposes of this 
rule shall be documented in the monitoring plan and developed in 
accordance with 40 CFR part 60, appendix A, Method 19. The owner or 
operator may use an alternate method to calculate the NOX 
emissions upon written approval from EPA.
    (n) Reporting Requirements
    (1) Unless otherwise stated all requests, reports, submittals, 
notifications, and other communications to the Regional Administrator 
required by this section shall be submitted, unless instructed 
otherwise, to the Office of Enforcement and Compliance Assurance, U.S. 
Environmental Protection Agency, Region 5 (E-19J), at 77 West Jackson 
Boulevard, Chicago, Illinois 60604.
    (2)(i) If the owner or operator is required to conduct a 
performance test, a notification of intent to conduct a performance 
test must be submitted at least 60 calendar days before the performance 
test is scheduled to begin, as required in 40 CFR 63.7(b)(1).
    (ii) If the owner or operator is required to conduct a performance 
test or other initial compliance demonstration, a notification of 
compliance status must be submitted according to 40 CFR 63.9(h)(2)(ii). 
The initial notification of compliance status must be submitted by the 
dates specified in paragraphs (2)(ii)(A) through (B) of this section.
    (A) For each initial compliance demonstration that does not include 
a performance test, notification of compliance status must be submitted 
before the close of business on the 30th calendar day following 
completion of the initial compliance demonstration.
    (B) For each initial compliance demonstration that does include a 
performance test, notification of compliance status, including the 
performance test results, must be submitted before the close of 
business on the 60th calendar day following the completion of the 
performance test according to Sec.  63.10(d)(2).
    (3) The recordkeeping requirements for CEMS performance testing are 
found in 40 CFR 60.7(c) and (d). All emission data shall be reported in 
the units of the standard.
    (4) The recordkeeping requirements for non-continuous performance 
testing are found in 40 CFR 60.7(b). The owner or operator shall submit 
a written report of the results from all required non-CEMS performance 
tests to EPA within

[[Page 49338]]

90 calendar days of the completion of the performance test.
    (5) Compliance Reports. Unless the Administrator has approved a 
different schedule, a semiannual compliance report must be submitted, 
according to the paragraphs (5)(i) through (iv) of this section.
    (i) The first compliance report must cover the beginning period on 
the compliance date that is specified for the affected source and ended 
on June 30 or December 31, whichever date comes first after the 
compliance date that is specified for the affected source.
    (ii) The first compliance report must be postmarked or delivered no 
later than July 31 or January 31, whichever comes first after the first 
compliance report is due.
    (iii) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (iv) Each subsequent compliance report must be postmarked or 
delivered no later than July 31 or January 31, whichever date comes 
first after the end of the semiannual reporting period.
    (6) Compliance report contents. Each compliance report must include 
the information in paragraphs (6)(i) through (iii) of this section and, 
as applicable, in paragraphs (6)(iv) through (viii) of this section.
    (i) Company name and address.
    (ii) Statement by a responsible official, with the official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (iii) Date of report and beginning and ending dates of the 
reporting period.
    (iv) If the source had a startup, shutdown, or malfunction during 
the reporting period and the owner or operator took actions consistent 
with the source's startup, shutdown, and malfunction plan, the 
compliance report must include the information in Sec.  63.10(d)(5)(i).
    (v) If there were no deviations from the continuous NOX 
and SO2 compliance requirements that apply to the affected 
source, then a statement that there were no deviations from the 
emission limitations during the reporting period must be provided.
    (vi) If there were no periods during which a continuous monitoring 
system was out-of-control as specified in Sec.  63.8(c)(7), then a 
statement that there were no periods during which a continuous 
monitoring system was out-of-control during the reporting period must 
be provided.
    (vii) For each deviation from a NOX and SO2 
emission limitation occurring at an affected source where a continuous 
monitoring system is being used to comply with the emission limitation 
in this subpart, the information in paragraphs (6)(i) through (iv) of 
this section and the information in paragraphs (6)(vii)(A) through (K) 
of this section must be included. This includes periods of startup, 
shutdown, and malfunction.
    (A) The date and time that each malfunction started and stopped.
    (B) The date and time that each continuous monitoring system was 
inoperative, except for zero (low-level) and high-level checks.
    (C) The date, time, and duration that each continuous monitoring 
system was out-of-control, including the information in Sec.  
63.8(c)(8).
    (D) The date and time that each deviation started and stopped, and 
whether each deviation occurred during a period of startup, shutdown, 
or malfunction or during another period.
    (E) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (F) A breakdown of the total duration of the deviations during the 
reporting period including those that are due to startup, shutdown, 
control equipment problems, process problems, other known causes, and 
other unknown causes.
    (G) A summary of the total duration of continuous monitoring system 
downtime during the reporting period and the total duration of 
continuous monitoring system downtime as a percent of the total source 
operating time during the reporting period.
    (H) A brief description of the process units.
    (I) A brief description of the continuous monitoring system.
    (J) The date of the latest continuous monitoring system 
certification or audit.
    (K) A description of any changes in continuous monitoring systems, 
processes, or controls since the last reporting period.
    (7) Immediate startup, shutdown, and malfunction report. If the 
affected source had a startup, shutdown, or malfunction during the 
semiannual reporting period that was not consistent with the startup, 
shutdown, and malfunction plan, an immediate startup, shutdown, and 
malfunction report must be submitted according to the requirements in 
Sec.  63.10(d)(5)(ii).
    (8) Notification of performance evaluation. (i) The owner or 
operator shall notify the Administrator in writing of the date of the 
performance evaluation simultaneously with the notification of the 
performance test date required under Sec.  63.7(b) or at least 60 days 
prior to the date the performance evaluation is scheduled to begin if 
no performance test is required.
    (ii)(A) Submission of site-specific performance evaluation test 
plan. Before conducting a required CEMS performance evaluation, the 
owner or operator of an affected source shall develop and submit a 
site-specific performance evaluation test plan to the Administrator for 
approval upon request. The performance evaluation test plan shall 
include the evaluation program objectives, an evaluation program 
summary, the performance evaluation schedule, data quality objectives, 
and both an internal and external QA program. Data quality objectives 
are the pre-evaluation expectations of precision, accuracy, and 
completeness of data.
    (B) The internal QA program shall include, at a minimum, the 
activities planned by routine operators and analysts to provide an 
assessment of CEMS performance. The external QA program shall include, 
at a minimum, systems audits that include the opportunity for on-site 
evaluation by the Administrator of instrument calibration, data 
validation, sample logging, and documentation of quality control data 
and field maintenance activities.
    (C) The owner or operator of an affected source shall submit the 
site-specific performance evaluation test plan to the Administrator (if 
requested) at least 60 days before the performance test or performance 
evaluation is scheduled to begin, or on a mutually agreed upon date, 
and review and approval of the performance evaluation test plan by the 
Administrator will occur with the review and approval of the site-
specific test plan (if review of the site-specific test plan is 
requested).
    (D) The Administrator may request additional relevant information 
after the submittal of a site-specific performance evaluation test 
plan.
    (E) In the event that the Administrator fails to approve or 
disapprove the site-specific performance evaluation test plan within 
the time period specified in Sec.  63.7(c)(3), the following conditions 
shall apply:
    (1) If the owner or operator intends to demonstrate compliance 
using the monitoring method(s) specified in the relevant standard, the 
owner or operator shall conduct the performance evaluation within the 
time specified in this subpart using the specified method(s);

[[Page 49339]]

    (2) If the owner or operator intends to demonstrate compliance by 
using an alternative to a monitoring method specified in the relevant 
standard, the owner or operator shall refrain from conducting the 
performance evaluation until the Administrator approves the use of the 
alternative method. If the Administrator does not approve the use of 
the alternative method within 30 days before the performance evaluation 
is scheduled to begin, the performance evaluation deadlines specified 
in paragraph (5)(iv) of this section may be extended such that the 
owner or operator shall conduct the performance evaluation within 60 
calendar days after the Administrator approves the use of the 
alternative method. Notwithstanding the requirements in the preceding 
two sentences, the owner or operator may proceed to conduct the 
performance evaluation as required in this section (without the 
Administrator's prior approval of the site-specific performance 
evaluation test plan) if he/she subsequently chooses to use the 
specified monitoring method(s) instead of an alternative.
    (F) Neither the submission of a site-specific performance 
evaluation test plan for approval, nor the Administrator's approval or 
disapproval of a plan, nor the Administrator's failure to approve or 
disapprove a plan in a timely manner shall--
    (1) Relieve an owner or operator of legal responsibility for 
compliance with any applicable provisions of this part or with any 
other applicable Federal, State, or local requirement; or
    (2) Prevent the Administrator from implementing or enforcing this 
part or taking any other action under the Act.
    (iii) Conduct of performance evaluation and performance evaluation 
dates. The owner or operator of an affected source shall conduct a 
performance evaluation of a required CEMS during any performance test 
required under Sec.  63.7 in accordance with the applicable performance 
specification as specified in the relevant standard. If a performance 
test is not required, or the requirement for a performance test has 
been waived under Sec.  63.7(h), the owner or operator of an affected 
source shall conduct the performance evaluation not later than 180 days 
after the appropriate compliance date for the affected source, as 
specified in Sec.  63.7(a), or as otherwise specified in the relevant 
standard.
    (iv) Reporting performance evaluation results. The owner or 
operator shall furnish the Administrator a copy of a written report of 
the results of the performance evaluation simultaneously with the 
results of the performance test required under Sec.  63.7 or within 60 
days of completion of the performance evaluation if no test is 
required, unless otherwise specified in a relevant standard. The 
Administrator may request that the owner or operator submit the raw 
data from a performance evaluation in the report of the performance 
evaluation results.
    3. Section 52.1235 is amended by adding paragraphs (a), (b), (c), 
(d) and (e) to read as follows:

Sec.  52.1235  Regional Haze.

    (a) The requirements of section 169A of the Clean Air Act are not 
met because the regional haze plan submitted by the state on December 
30, 2009, and on May 8, 2012, does not meet the requirements of 40 CFR 
51.308(e) with respect to NOX and SO2 emissions 
from United States Steel Corporation, Keetac of Keewatin, Minnesota; 
Hibbing Taconite Company of Hibbing, Minnesota; United States Steel 
Corporation, Minntac of Mountain Iron, Minnesota; United Taconite, LLC 
of Forbes, Minnesota; ArcelorMittal Minorca Mine, Inc. near Virginia, 
Minnesota; and Northshore Mining Company--Silver Bay of Silver Bay, 
Minnesota. The requirements for these facilities are satisfied by 
complying with the requirements of Sec.  52.1235.
    (b)(1) NOX Emission Limits.
    (i) United States Steel Corporation, Keetac: An emission limit of 
1.2 lb NOX/MMBtu at 7 percent oxygen, based on a 30-day 
rolling average, shall apply to the Grate Kiln pelletizing furnace 
(EU030), beginning 1 year and 6 months from the effective date of this 
rule.
    (ii) Hibbing Taconite Company: An emission limit of 1.2 lb 
NOX/MMBtu at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the Line 1 pelletizing furnace (EU020) 
beginning 1 year and 6 months from the effective date of this rule. An 
emission limit of 1.2 lb NOX/MMBtu at 7 percent oxygen, 
based on a 30-day rolling average, shall apply to the Line 2 
pelletizing furnace (EU021) beginning 3 years and 6 months from the 
effective date of this rule. An emission limit of 1.2 lb 
NOX/MMBtu at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the Line 3 pelletizing furnace (EU022) 
beginning 2 years and 6 months from the effective date of this rule.
    (iii) United States Steel Corporation, Minntac: An emission limit 
of 1.2 lb NOX/MMBtu at 7 percent oxygen, based on a 30-day 
rolling average, shall apply to each of the five indurating furnaces 
(EU225, EU261, EU282, EU315, and EU334). The owner or operator shall 
comply with this NOX emission limits beginning 4 years and 
11 months from the effective date of this rule for the Line 3 
indurating furnace (EU225), beginning 3 years from the effective date 
of this rule for the Line 4 indurating furnace (EU261), beginning 4 
years from the effective date of this rule for the Line 5 indurating 
furnace (EU282), beginning 1 year from the effective date of this rule 
for the Line 6 indurating furnace (EU315), and beginning 2 years from 
the effective date of this rule for the Line 7 indurating furnace 
(EU334).
    (iv) United Taconite: An emission limit of 1.2 lb NOX/
MMBtu at 7 percent oxygen, based on a 30-day rolling average, shall 
apply to the Line 1 pellet furnace (EU040) beginning 2 years and 6 
months from the effective date of this rule. An emission limit of 1.2 
lb NOX/MMBtu at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the Line 2 pellet furnace (EU046) beginning 1 
year and 6 months from the effective date of this rule.
    (v) ArcelorMittal Minorca Mine: An emission limit of 1.2 lb 
NOX/MMBtu at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the indurating furnace (EU026) beginning 1 year 
and 6 months from the effective date of this rule.
    (vi) Northshore Mining Company--Silver Bay: An emission limit of 
1.2 lb NOX/MMBtu at 7 percent oxygen, based on a 30-day 
rolling average, shall apply to Furnace 11 (EU100/EU104) beginning 1 
year and 6 months from the effective date of this rule. An emission 
limit of 1.2 lb NOX/MMBtu at 7 percent oxygen, based on a 
30-day rolling average, shall apply to Furnace 12 (EU110/114) beginning 
2 years and 6 months from the effective date of this rule. An emission 
limit of 0.085 lb/hr at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to Process Boiler 1 (EU003) and Process 
Boiler 2 (EU004) beginning 5 years from the effective date of 
this rule. The 0.085 lb/hr emission limit for each process boiler 
applies at all times a unit is operating, including periods of start-
up, shut-down and malfunction.
    (2) SO2 Emission Limits.
    (i) United States Steel Corporation, Keetac: An emission limit of 
225 lb SO2/hr at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the Grate Kiln pelletizing furnace (EU030). The 
owner or operator shall also operate its wet scrubber for EU030 to 
achieve a minimum SO2 control efficiency of 57.0 percent and 
to achieve a hydrogen ion concentration (pH) in the scrubber liquid at 
or above 7.5. Compliance with all SO2 emission limits, 
control efficiency and pH standards for EU030 is required beginning 90 
days from the effective date of this rule.

[[Page 49340]]

    (ii) Hibbing Taconite Company: Emission limits of 56.0 lb 
SO2/hr at 7 percent oxygen shall apply to Line 1 (EU020), 
63.0 lb SO2/hr at 7 percent oxygen shall apply to Line 2 
(EU021), and 64.0 lb SO2/hr at 7 percent oxygen shall apply 
to Line 3 (EU022). The SO2 emission limits for these three 
pelletizing furnaces are based on a 30-day rolling average and do not 
apply when a unit is combusting fuel oil. Compliance with the emission 
limits is required beginning 3 months from the effective date of this 
rule.
    (iii) United States Steel Corporation, Minntac: The emission limits 
for the five indurating furnaces are 71.3 lb SO2/hr at 7 
percent oxygen for Line 3 (EU225), 56.1 lb SO2/hr at 7 
percent oxygen for Line 4 (EU261), 67.9 lb SO2/hr at 7 
percent oxygen for Line 5 (EU282), 64.5 lb SO2/hr at 7 
percent oxygen for Line 6 (EU315), and 67.1 lb SO2/hr at 7 
percent oxygen for Line 7 (EU334). The SO2 emission limits 
are based on a 30-day rolling average and apply to each of the five 
indurating furnaces, beginning 3 months from the effective date of this 
rule.
    (iv) United Taconite: An emission limit of 5 ppmv SO2 at 
7 percent oxygen shall apply to the Line 1 pellet furnace (EU040) 
beginning 4 years from the effective date of this rule. As an 
alternate, the owner or operator may select to comply with a 95.0 
percent or greater SO2 removal efficiency, based on a 30-day 
rolling average, on the control device for the Line 1 pellet furnace 
(EU040) beginning 4 years from the effective date of this rule. An 
emission limit of 5 ppmv SO2 at 7 percent oxygen shall apply 
to the Line 2 pellet furnace (EU042) beginning 2 years from the 
effective date of this rule. As an alternate, the owner or operator may 
select to comply with a 95.0 percent or greater SO2 removal 
efficiency, based on a 30-day rolling average, on the control device 
for the Line 2 pellet furnace (EU042) beginning 2 years from the 
effective date of this rule.
    (v) ArcelorMittal Minorca Mine: An emission limit of 23.0 lb 
SO2/hr at 7 percent oxygen, based on a 30-day rolling 
average, shall apply to the indurating furnace (EU026) beginning 3 
months from the effective date of this rule. This limit shall not apply 
when the unit is combusting fuel oil.
    (vi) Northshore Mining Company--Silver Bay: An emission limit of 
16.3 lb SO2/hr at 7 percent oxygen, based on a 30-day 
rolling average, shall apply to Furnace 11 (EU100/EU104). An emission 
limit of 17.1 lb SO2/hr at 7 percent oxygen, based on a 30-
day rolling average, shall apply to Furnace 12 (EU110/EU114). The owner 
or operator shall also operate its control device for EU100/EU104 and 
EU110/EU114 to achieve a minimum SO2 control efficiency of 
80.0 percent. The owner or operator shall comply with the 
SO2 emission limits/standards beginning 6 months from the 
effective date of this rule. These limits shall not apply when the 
subject unit is combusting fuel oil.
    (c) Testing and Monitoring.
    (1) No later than the compliance date of this regulation, the owner 
or operator of the respective facility shall install, certify, 
calibrate, maintain and operate Continuous Emissions Monitoring Systems 
(CEMS) for NOX on United States Steel Corporation, Keetac 
unit EU030; Hibbing Taconite Company units EU020, EU021, and EU022; 
United States Steel Corporation, Minntac units EU225, EU261, EU282, 
EU315, and EU334; United Taconite units EU040 and EU042; ArcelorMittal 
Minorca Mine unit EU026; and Northshore Mining Company--Silver Bay 
units Furnace 11 (EU100/EU104) and Furnace 12 (EU110/EU114). All 
NOX CEMS must be installed, certified, calibrated, 
maintained and operated in accordance with 40 CFR 63.8, and Appendices 
B and F of Part 60. The owner or operator shall install, certify, 
calibrate, maintain and operate a continuous diluent monitor 
(O2 or CO2) and continuous flow rate monitor on 
each unit identified by this rule to allow conversion of the 
NOX concentration to units of the standard (lbs/MMBtu). 
Compliance with the emission limits for NOX shall be 
determined using data from the CEMS corrected to 7 percent oxygen.
    (2) No later than the compliance date of this regulation, the owner 
or operator shall install, certify, calibrate, maintain and operate one 
or more CEMS for SO2 on United States Steel Corporation, 
Keetac unit EU030; Hibbing Taconite Company units EU020, EU021, and 
EU022; United States Steel Corporation, Minntac units EU225, EU261, 
EU282, EU315, and EU334; United Taconite units EU040 and EU042; 
ArcelorMittal Minorca Mine unit EU026; and Northshore Mining Company--
Silver Bay units Furnace 11 (EU100/EU104) and Furnace 12 (EU110/EU114). 
All SO2 CEMS must be installed, certified, calibrated, 
maintained and operated in accordance with 40 CFR 63.8, and Appendices 
B and F of Part 60. The owner or operator shall install, certify, 
calibrate, maintain and operate a continuous diluent monitor 
(O2 or CO2) and continuous flow rate monitor on 
each unit identified by this rule to allow conversion of the 
SO2 concentration to units of the standard (lb/hr, ppmv or a 
minimum of 95 percent removal efficiency). The number of monitors is 
dependent on the emission standard selected for purposes of 
demonstrating compliance. Compliance with the emission standard 
selected for SO2 shall be determined using data from the 
CEMS corrected to 7 percent oxygen.
    (3) Except for CEMS breakdowns, out-of-control periods, repairs, 
maintenance periods, calibration checks, and zero and high-level drift 
adjustments, all CEMS required by this rule shall be in continuous 
operation and meet minimum frequency of operation requirements at 
(c)(3)(i-viii) during all periods of process unit operation, including 
periods of process unit startup, shutdown, and malfunction.
    (i) Continuous monitoring systems for measuring the pollutant, 
NOX or SO2, and diluent gas shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (ii) Hourly averages shall be computed using at least one data 
point in each fifteen-minute quadrant of an hour. Notwithstanding this 
requirement, an hourly average may be computed from at least two data 
points separated by a minimum of 15 minutes (where the unit operates 
for more than one quadrant in an hour) if data are unavailable as a 
result of performance of calibration, quality assurance, preventive 
maintenance activities, or backups of data from data acquisition and 
handling system, and recertification events.
    (iii) When valid pollutant emission data in pounds per hour or 
pounds per million BTU are not obtained because of continuous 
monitoring system breakdowns, repairs, calibration checks, or zero and 
span adjustments, emission data must be obtained by using other 
monitoring systems approved by the EPA, and incorporated into the 
monitoring plan, to provide emission data for a minimum of 18 hours in 
each 24 hour period and at least 22 out of 30 successive unit operating 
days.
    (iv) Data substitution must not be used for purposes of determining 
compliance under this regulation.
    (v) All CEMS (and emission testing) data shall be reduced and 
reported in units of the applicable standard.
    (vi) A Quality Control Program Plan must be developed and 
implemented for all CEMS required by this rule. The plan will include, 
at a minimum, the information described at 40 CFR 63.8(d), including 
calibration checks, calibration drift adjustments, preventative 
maintenance, data collection, recording and reporting, accuracy audits/

[[Page 49341]]

procedures, periodic performance evaluations, and a corrective action 
program for CEMS problems and excess emission events.
    (vii) The owner or operator must develop and implement a written 
startup, shutdown, and malfunction plan for NOX and 
SO2 according to the provisions in Sec.  63.6(e)(3).
    (viii) Performance evaluation of continuous monitoring systems. 
When required by a relevant standard the owner or operator of an 
affected source being monitored with continuous emission monitoring 
equipment shall conduct a performance evaluation of the CEMS. Such 
performance evaluation shall be conducted according to the applicable 
specifications and procedures described in 40 CFR 63.8(e) and 
incorporated into Quality Control Program Plan.
    (4) No later than the compliance date of this regulation, the owner 
or operator of each unit identified in this rule shall conduct initial 
performance testing for NOX and SO2, in 
accordance with the requirements of 40 CFR 63.7 and Appendix A of Part 
60 to determine compliance with applicable emission limits/standards. 
Specific testing shall be described in the intent to test form 
submitted in accordance with the rule. The general reference methods to 
be used for initial testing will include: Methods 1-4, 6-6C, and 7-7E. 
Performance testing for demonstrating compliance with NOX 
and SO2 emission limits (lb/MMBtu, lb/hr, or ppmv) shall 
include testing emissions after exiting the control device. Performance 
testing for demonstrating compliance with the SO2 removal 
efficiency standard shall include measuring SO2 
concentrations at the inlet to the control device and in the duct/stack 
after emissions exit the control device.
    (5) No later than the compliance date of this regulation, owners or 
operators utilizing a wet scrubber to control SO2 shall 
include in the performance testing an evaluation of compliance with the 
pH limits established by this rule. The pH evaluation shall be 
performed in accordance with the requirements of 40 CFR 163.3 using EPA 
Method 150.2.
    (d) Recordkeeping Requirements.
    (1)(i) Records must be in a form suitable and readily available for 
expeditious review, according to Sec.  63.10(b)(1).
    (ii) As specified in Sec.  63.10(b)(1), records must be kept for 5 
years following the date of each occurrence, measurement, maintenance, 
corrective action, report, or record.
    (iii) Records must be kept on site for at least 2 years after the 
date of each occurrence, measurement, maintenance, report, or record 
according to Sec.  63.10(b)(1). Records may be kept offsite for the 
remaining 3 years.
    (2) Records listed in paragraphs (2)(i) through (iv) of this 
section must be kept for a period of five years.
    (i) A copy of each notification and report submitted to comply with 
this subpart, including all documentation supporting any initial 
notification or notification of compliance status submitted, according 
to the requirements in 40 CFR 63.10(b)(2)(xiv).
    (ii) The records in 40 CFR 63.6(e)(3)(iii) through (v) related to 
startup, shutdown, and malfunction.
    (iii) Records of performance tests and performance evaluations as 
required in 40 CFR 63.10(b)(2)(viii).
    (iv) Records of all major maintenance conducted on emission units, 
pollution control equipment, and CEMS.
    (3) For each CEMS, the records specified in paragraphs (3)(i) 
through (vii) of this section must be kept.
    (i) Records described in 40 CFR 63.10(b)(2)(vi) through (xi).
    (ii) Previous (that is, superceded) versions of the performance 
evaluation plan as required in 63.8(d)(3).
    (iii) Records of the date and time that each deviation started and 
stopped, and whether the deviation occurred during a period of startup, 
shutdown, or malfunction or during another period.
    (iv) All CEMS data including the date, place, and time of sampling 
or measurement, parameters sampled or measured, and results.
    (v) Records of quality assurance and quality control activities for 
emissions measuring systems including, but not limited to, any records 
required by 40 CFR part 60, appendix B, Performance Specification 2, 
Procedure 1 or 40 CFR part 75.
    (vi) All records required by 40 CFR part 60, appendix F, Procedure 
1 or 40 CFR part 75.
    (vii) Records of the NOX emissions in the units of the 
standard. The owner or operator shall convert the monitored data into 
the appropriate unit of the emission limitation using an appropriate 
conversion factor and F-factors. F-factors used for purposes of this 
rule shall be documented in the monitoring plan and developed in 
accordance with 40 CFR part 60, appendix A, Method 19. The owner or 
operator may use an alternate method to calculate the NOX 
emissions upon written approval from EPA.
    (e) Reporting Requirements.
    (1) Unless otherwise stated all requests, reports, submittals, 
notifications, and other communications to the Regional Administrator 
required by this section shall be submitted, unless instructed 
otherwise, to the Office of Enforcement and Compliance Assurance, U.S. 
Environmental Protection Agency, Region 5 (E-19J), at 77 West Jackson 
Boulevard, Chicago, Illinois 60604.
    (2)(i) If the owner or operator is required to conduct a 
performance test, a notification of intent to conduct a performance 
test must be submitted at least 60 calendar days before the performance 
test is scheduled to begin, as required in 40 CFR 63.7(b)(1).
    (ii) If the owner or operator is required to conduct a performance 
test or other initial compliance demonstration, a notification of 
compliance status must be submitted according to 40 CFR 63.9(h)(2)(ii). 
The initial notification of compliance status must be submitted by the 
dates specified in paragraphs (2)(ii)(A) through (B) of this section.
    (A) For each initial compliance demonstration that does not include 
a performance test, notification of compliance status must be submitted 
before the close of business on the 30th calendar day following 
completion of the initial compliance demonstration.
    (B) For each initial compliance demonstration that does include a 
performance test, notification of compliance status, including the 
performance test results, must be submitted before the close of 
business on the 60th calendar day following the completion of the 
performance test according to Sec.  63.10(d)(2).
    (3) The recordkeeping requirements for CEMS performance testing are 
found in 40 CFR 60.7(c) and (d). All emission data shall be reported in 
the units of the standard.
    (4) The recordkeeping requirements for non-continuous performance 
testing are found in 40 CFR 60.7(b). The owner or operator shall submit 
a written report of the results from all required non-CEMS performance 
tests to EPA within 90 calendar days of the completion of the 
performance test.
    (5) Compliance Reports. Unless the Administrator has approved a 
different schedule, a semiannual compliance report must be submitted, 
according to the paragraphs (5)(i) through (iv) of this section.
    (i) The first compliance report must cover the beginning period on 
the compliance date that is specified for the affected source and ended 
on June 30 or December 31, whichever date comes first after the 
compliance date that is specified for the affected source.
    (ii) The first compliance report must be postmarked or delivered no 
later than July 31 or January 31, whichever comes

[[Page 49342]]

first after the first compliance report is due.
    (iii) Each subsequent compliance report must cover the semiannual 
reporting period from January 1 through June 30 or the semiannual 
reporting period from July 1 through December 31.
    (iv) Each subsequent compliance report must be postmarked or 
delivered no later than July 31 or January 31, whichever date comes 
first after the end of the semiannual reporting period.
    (6) Compliance report contents. Each compliance report must include 
the information in paragraphs (6)(i) through (iii) of this section and, 
as applicable, in paragraphs (6)(iv) through (viii) of this section.
    (i) Company name and address.
    (ii) Statement by a responsible official, with the official's name, 
title, and signature, certifying the truth, accuracy, and completeness 
of the content of the report.
    (iii) Date of report and beginning and ending dates of the 
reporting period.
    (iv) If the source had a startup, shutdown, or malfunction during 
the reporting period and the owner or operator took actions consistent 
with the source's startup, shutdown, and malfunction plan, the 
compliance report must include the information in Sec.  63.10(d)(5)(i).
    (v) If there were no deviations from the continuous NOX 
and SO2 compliance requirements that apply to the affected 
source, then a statement that there were no deviations from the 
emission limitations during the reporting period must be provided.
    (vi) If there were no periods during which a continuous monitoring 
system was out-of-control as specified in Sec.  63.8(c)(7), then a 
statement that there were no periods during which a continuous 
monitoring system was out-of-control during the reporting period must 
be provided.
    (vii) For each deviation from a NOX and SO2 
emission limitation occurring at an affected source where a continuous 
monitoring system is being used to comply with the emission limitation 
in this subpart, the information in paragraphs (6)(i) through (iv) of 
this section and the information in paragraphs (6)(vii)(A) through (K) 
of this section must be included. This includes periods of startup, 
shutdown, and malfunction.
    (A) The date and time that each malfunction started and stopped.
    (B) The date and time that each continuous monitoring system was 
inoperative, except for zero (low-level) and high-level checks.
    (C) The date, time, and duration that each continuous monitoring 
system was out-of-control, including the information in Sec.  
63.8(c)(8).
    (D) The date and time that each deviation started and stopped, and 
whether each deviation occurred during a period of startup, shutdown, 
or malfunction or during another period.
    (E) A summary of the total duration of the deviation during the 
reporting period and the total duration as a percent of the total 
source operating time during that reporting period.
    (F) A breakdown of the total duration of the deviations during the 
reporting period including those that are due to startup, shutdown, 
control equipment problems, process problems, other known causes, and 
other unknown causes.
    (G) A summary of the total duration of continuous monitoring system 
downtime during the reporting period and the total duration of 
continuous monitoring system downtime as a percent of the total source 
operating time during the reporting period.
    (H) A brief description of the process units.
    (I) A brief description of the continuous monitoring system.
    (J) The date of the latest continuous monitoring system 
certification or audit.
    (K) A description of any changes in continuous monitoring systems, 
processes, or controls since the last reporting period.
    (7) Immediate startup, shutdown, and malfunction report. If the 
affected source had a startup, shutdown, or malfunction during the 
semiannual reporting period that was not consistent with the startup, 
shutdown, and malfunction plan, an immediate startup, shutdown, and 
malfunction report must be submitted according to the requirements in 
Sec.  63.10(d)(5)(ii).
    (8) Notification of performance evaluation. (i) The owner or 
operator shall notify the Administrator in writing of the date of the 
performance evaluation simultaneously with the notification of the 
performance test date required under Sec.  63.7(b) or at least 60 days 
prior to the date the performance evaluation is scheduled to begin if 
no performance test is required.
    (ii)(A) Submission of site-specific performance evaluation test 
plan. Before conducting a required CEMS performance evaluation, the 
owner or operator of an affected source shall develop and submit a 
site-specific performance evaluation test plan to the Administrator for 
approval upon request. The performance evaluation test plan shall 
include the evaluation program objectives, an evaluation program 
summary, the performance evaluation schedule, data quality objectives, 
and both an internal and external QA program. Data quality objectives 
are the pre-evaluation expectations of precision, accuracy, and 
completeness of data.
    (B) The internal QA program shall include, at a minimum, the 
activities planned by routine operators and analysts to provide an 
assessment of CEMS performance. The external QA program shall include, 
at a minimum, systems audits that include the opportunity for on-site 
evaluation by the Administrator of instrument calibration, data 
validation, sample logging, and documentation of quality control data 
and field maintenance activities.
    (C) The owner or operator of an affected source shall submit the 
site-specific performance evaluation test plan to the Administrator (if 
requested) at least 60 days before the performance test or performance 
evaluation is scheduled to begin, or on a mutually agreed upon date, 
and review and approval of the performance evaluation test plan by the 
Administrator will occur with the review and approval of the site-
specific test plan (if review of the site-specific test plan is 
requested).
    (D) The Administrator may request additional relevant information 
after the submittal of a site-specific performance evaluation test 
plan.
    (E) In the event that the Administrator fails to approve or 
disapprove the site-specific performance evaluation test plan within 
the time period specified in Sec.  63.7(c)(3), the following conditions 
shall apply:
    (1) If the owner or operator intends to demonstrate compliance 
using the monitoring method(s) specified in the relevant standard, the 
owner or operator shall conduct the performance evaluation within the 
time specified in this subpart using the specified method(s);
    (2) If the owner or operator intends to demonstrate compliance by 
using an alternative to a monitoring method specified in the relevant 
standard, the owner or operator shall refrain from conducting the 
performance evaluation until the Administrator approves the use of the 
alternative method. If the Administrator does not approve the use of 
the alternative method within 30 days before the performance evaluation 
is scheduled to begin, the performance evaluation deadlines specified 
in paragraph (5)(iv) of this section may be extended such that the 
owner or operator shall conduct the performance evaluation within 60 
calendar days after the Administrator approves the use of the 
alternative method. Notwithstanding

[[Page 49343]]

the requirements in the preceding two sentences, the owner or operator 
may proceed to conduct the performance evaluation as required in this 
section (without the Administrator's prior approval of the site-
specific performance evaluation test plan) if he/she subsequently 
chooses to use the specified monitoring method(s) instead of an 
alternative.
    (F) Neither the submission of a site-specific performance 
evaluation test plan for approval, nor the Administrator's approval or 
disapproval of a plan, nor the Administrator's failure to approve or 
disapprove a plan in a timely manner shall--
    (1) Relieve an owner or operator of legal responsibility for 
compliance with any applicable provisions of this part or with any 
other applicable Federal, State, or local requirement; or
    (2) Prevent the Administrator from implementing or enforcing this 
part or taking any other action under the Act.
    (iii) Conduct of performance evaluation and performance evaluation 
dates. The owner or operator of an affected source shall conduct a 
performance evaluation of a required CEMS during any performance test 
required under Sec.  63.7 in accordance with the applicable performance 
specification as specified in the relevant standard. If a performance 
test is not required, or the requirement for a performance test has 
been waived under Sec.  63.7(h), the owner or operator of an affected 
source shall conduct the performance evaluation not later than 180 days 
after the appropriate compliance date for the affected source, as 
specified in Sec.  63.7(a), or as otherwise specified in the relevant 
standard.
    (iv) Reporting performance evaluation results. The owner or 
operator shall furnish the Administrator a copy of a written report of 
the results of the performance evaluation simultaneously with the 
results of the performance test required under Sec.  63.7 or within 60 
days of completion of the performance evaluation if no test is 
required, unless otherwise specified in a relevant standard. The 
Administrator may request that the owner or operator submit the raw 
data from a performance evaluation in the report of the performance 
evaluation results.

[FR Doc. 2012-19789 Filed 8-14-12; 8:45 am]
BILLING CODE 6560-50-P
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