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.

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

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.

      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

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

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

  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

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-

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,

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.

    (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

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);

    (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.

    (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/

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

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

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