----------------------------------------------------------------------------------------------------------------
* Proposed FIP controls under BART requirements will result in emission reductions.

    Because in our March 12, 2012 final partial approval and partial
disapproval of the 2008 Arkansas RH SIP we made a finding that Arkansas
did not complete a reasonable progress analysis and did not properly
demonstrate that additional controls were not reasonable under 40 CFR
51.308(d)(1)(i)(A) and we disapproved the RPGs it established for Caney
Creek and Upper Buffalo, we are required to complete the reasonable
progress analysis and establish revised RPGs, unless we first approve a
SIP revision that corrects the disapproved portions of the SIP
submittal. As Arkansas has not as yet submitted a revised SIP following
our partial disapproval, we must now complete the reasonable progress
analysis and establish revised RPGs for Caney Creek and Upper Buffalo.
We believe it is appropriate that our evaluation of the reasonable
progress factors focuses on the Entergy Independence Power Plant

because it is a significant source of SO2 and
NOX, as it is the second largest point source for both
NOX and SO2 point source emissions in the State.
    We believe it is appropriate to evaluate Entergy Independence even
though Arkansas Class I areas and those outside of Arkansas most
significantly impacted by Arkansas sources are projected to meet the
URP for the first planning period. This is because we believe that in
determining whether reasonable progress is being achieved, it would be
unreasonable to ignore a source representing more than a third of the
State's SO2 emissions and a significant portion of
NOX point source emissions. The preamble to the Regional
Haze Rule also states that the URP does not establish a ``safe harbor''
for the state in setting its progress goals.\117\ If the state
determines that the amount of progress identified through the URP
analysis is reasonable based upon the statutory factors, the state, or
us in the case of a FIP, should identify this amount of progress as its
reasonable progress goal for the first long-term strategy, unless it
determines that additional progress beyond this amount is also
reasonable. If the state or we determine that additional progress is
reasonable based on the statutory factors, that amount of progress
should be adopted as the goal for the first long-term strategy.
---------------------------------------------------------------------------

    \117\ See 64 FR 35732.
---------------------------------------------------------------------------

    In this proposed rulemaking, we are proposing controls for the
largest and third largest point sources for both NOX and
SO2 emissions in Arkansas under the BART requirements. As
these two BART sources combined with Independence make up a large
majority of the SO2 point source emissions (84%) and a large
proportion of the NOX point source emissions (55%) in
Arkansas, we believe that a sufficient amount of point source emissions
in the State would be addressed in this first regional haze planning
period by addressing the Independence facility in our reasonable
progress analysis, which as we note above is the second largest source
of both SO2 and NOX. We are proposing under
Option 1 to control Entergy Independence for the first planning period
for both SO2 and NOX. Alternatively, under Option
2, for the first planning period, we are proposing to control Entergy
Independence only for SO2. The fourth largest SO2
and NOX point sources in Arkansas are the Future Fuel
Chemical Company, with emissions of 3,421 SO2 tpy, and the
Natural Gas Pipeline Company of America #308, with emissions of 3,194
NOX tpy (2011 NEI). In comparison to the emissions of the
top three sources, emissions from these two facilities are relatively
small. Therefore, we are not proposing controls in this first planning
period for these two facilities because we believe it is appropriate to
defer the consideration of any additional sources besides Independence
to future regional haze planning periods. For Independence, however,
under Option 1, in combination with the BART sources we would be
addressing 84% of the SO2 point source emissions in the
State and over 55% of the NOX point source emissions. Under
Option 2, we would be deferring the consideration of additional
NOX controls to future regional haze planning periods. In
the next section, we describe our consideration of the four reasonable
progress factors for the Entergy Independence Plant as well as the
CALPUFF modeling we conducted to assess the potential visibility
benefits of controls.\118\
---------------------------------------------------------------------------

    \118\ While visibility is not an explicitly listed factor to
consider when determining whether additional controls are
reasonable, the purpose of the four-factor analysis is to determine
what degree of progress toward natural visibility conditions is
reasonable. Therefore, it is appropriate to consider the projected
visibility benefit of the controls when determining if the controls
are needed to make reasonable progress.
---------------------------------------------------------------------------

1. Entergy Independence Plant Units 1 and 2
    a. Reasonable Progress Analysis for SO2 Controls--Costs of
Compliance: The Entergy Independence Plant is an electric generating
station with two nearly identical coal-fired units (Units 1 and 2) with
a nameplate capacity of 900 MW each. Units 1 and 2 are tangentially-
fired boilers that burn sub-bituminous coal as their primary fuel and
No. 2 fuel oil or Bio-diesel as the start-up fuel. To verify that the
White Bluff and Independence Plants are sister facilities, we have
constructed a master spreadsheet \119\ that contains information
concerning ownership, location, boiler type, environmental controls and
other pertinent information on these facilities. The spreadsheet
includes information contained within EIA Forms 860 and 923. According
to EIA,\120\ the boilers were manufactured by Combustion Engineering
with installation dates of 1974 for White Bluff, and 1983 and 1984 for
Independence. The two units at White Bluff and the two units at
Independence are tangentially firing boilers having nameplate
capacities of 900 MW and similar gross ratings. All four units burn
coal from the Powder River Basin (PRB) of Wyoming with similar
characteristics. All four units employ cold side ESPs for particulate
collection. Other pertinent characteristics are similar. The layout of
the White Bluff and Independence facilities are also very similar.\121\
Due to the similarity of these facilities, we applied the total
annualized dry FGD and wet FGD costs we developed for the White Bluff
units to the Independence units. However, we adjusted the cost-
effectiveness ($/ton) due to the differing baseline SO2
emissions from the units.
---------------------------------------------------------------------------

    \119\ This spreadsheet, entitled ``EIA Consolidated Data_WB and
Ind_Y2012.xlsx,'' is located in the docket for our proposed
rulemaking.
    \120\ See ``EIA Consolidated Data_WB and IND_Y2012.xlsx.''
    \121\ See ``Technical Support Document for the SDA Control Cost
Analysis for the Entergy White Bluff and Independence Facilities
Arkansas Regional Haze Federal Implementation Plan (SO2
Cost TSD),'' Figures 1 and 2.
---------------------------------------------------------------------------

    Consistent with the cost estimate we developed for White Bluff, we
estimated a total annual cost for dry FGD at Independence of
approximately $31,981,230 at each unit.\122\ We expect dry FGD to
achieve a controlled emission level of 0.06 lb/MMBtu, and estimate that
the annual emissions reductions at Unit 1 would be 12,912
SO2 tpy, assuming baseline emissions \123\ of 14,269
SO2 tpy (see table below). The average cost-effectiveness of
dry FGD at Unit 1 is estimated to be $2,477 per SO2 ton
removed. For Unit 2, we estimate that the annual emissions reductions
would be 13,990 SO2 tpy, assuming baseline emissions of
15,511 SO2 tpy. The average cost-effectiveness of dry FGD at
Unit 2 is estimated to be $2,286 per SO2 ton removed.
---------------------------------------------------------------------------

    \122\ See ``Technical Support Document for the SDA Control Cost
Analysis for the Entergy White Bluff and Independence Facilities
Arkansas Regional Haze Federal Implementation Plan (SO2
Cost TSD).'' A copy of this TSD is found in the docket for our
proposed rulemaking.
    \123\ Baseline emissions were determined by examining annual
SO2 emissions for the years 2009-2013, eliminating the
year with the highest emissions and the year with the lowest
emissions, and obtaining the average of the three remaining years.

                                        Table 60--Summary of Dry FGD Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (SO2   Total annual cost  effectiveness ($/
                                                             rate (SO2 tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1...................................................             14,269               0.06             12,912        $31,981,230             $2,477
Unit 2...................................................             15,511               0.06             13,990         31,981,230              2,286
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Because our proposed BART determination for the White Bluff
facility is that dry FGD is more cost-effective (lower $/ton) than wet
FGD, and that the additional visibility benefits obtained as a result
of the greater level of control wet FGD offers over dry FGD are not
worth the additional cost of wet FGD, we expect that the same would
apply to Independence Units 1 and 2. Therefore, our evaluation of
SO2 controls for Independence Units 1 and 2 focuses on dry
FGD. Nevertheless, we have calculated the cost-effectiveness of wet FGD
for Independence Units 1 and 2 using the total annualized cost estimate
provided by Entergy for White Bluff Units 1 and 2, with certain
adjustments we made to the cost estimate provided by the facility.\124\
Consistent with our estimate for White Bluff, we estimated a total
annual cost for wet FGD at Independence of approximately $49,526,167 at
each unit.\125\ We expect wet FGD to achieve a controlled emission
level of 0.04 lb/MMBtu, and estimate that the annual emissions
reductions at Unit 1 would be 13,364 SO2 tpy, assuming
baseline emissions \126\ of 14,269 SO2 tpy (see table
below). The average cost-effectiveness of wet FGD at Unit 1 is
estimated to be $3,706 per SO2 ton removed. For Unit 2, we
estimate that the annual emissions reductions would be 14,497
SO2 tpy, assuming baseline emissions of 15,511
SO2 tpy. The average cost-effectiveness of wet FGD at Unit 2
is estimated to be $3,416 per SO2 ton removed.
---------------------------------------------------------------------------

    \124\ See our discussion above of the cost analysis for
SO2 BART for White Bluff Units 1 and 2, under section
III.C.4 of this proposed rulemaking.
    \125\ See our Cost Analysis TSD titled ``Technical Support
Document for the SDA Control Cost Analysis for the Entergy White
Bluff and Independence Facilities Arkansas Regional Haze Federal
Implementation Plan (SO2 Cost TSD).'' The TSD is found in
the docket for our proposed rulemaking.
    \126\ Baseline emissions were determined by examining annual
SO2 emissions for the years 2009-2013, eliminating the
year with the highest emissions and the year with the lowest
emissions, and obtaining the average of the three remaining years.

                                        Table 61--Summary of Wet FGD Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (SO2   Total annual cost  effectiveness ($/
                                                             rate (SO2 tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1...................................................             14,269               0.04             13,463        $49,526,167             $3,706
Unit 2...................................................             15,511               0.04             14,532         49,526,167              3,416
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Time Necessary for Compliance: As is generally the case for
installation of scrubber controls on EGUs, we expect that 5 years from
the date of our final action would be sufficient time for Independence
to install and operate either dry or wet FGD controls at Units 1 and 2
and to comply with the associated emission limits.
    Energy and Non-Air Quality Environmental Impacts of Compliance: The
installation and operation of wet FGD at Independence Units 1 and 2
would require greater energy usage and reagent usage compared to dry
FGD. The cost of this additional energy usage and reagent usage has
already been factored into the cost analysis. Non-air quality
environmental impacts associated with wet FGD systems include increased
water usage and the generation of large volumes of wastewater and solid
waste/sludge that must be treated or stabilized before landfilling.
Because the facility is not located in an exceptionally arid region, we
do not anticipate that there would be water-availability issues that
would affect the feasibility of wet FGD. Lastly, wet FGD systems have
the potential for increased particulate and sulfuric acid mist releases
that contribute to regional haze, which we are taking into
consideration through an evaluation of the visibility benefits of each
control option.
    Remaining Useful Life: Independence Units 1 and 2 were installed in
1983 and 1984. Unit 1 was placed into operation in 1983 and Unit 2 was
placed into operation in 1985. As there is no enforceable shut-down
date for Units 1 and 2, we assume an equipment life of 30 years.\127\
---------------------------------------------------------------------------

    \127\ As we note in our Oklahoma FIP, we typically assume a 30
year equipment life for scrubbers, as we do here. Please see
Response to Technical Comments for Sections E. through H. of the
Federal Register Notice for the Oklahoma Regional Haze and
Visibility Transport Federal Implementation Plan, Docket No. EPA-
R06-OAR-2010-0190. Page 35.
---------------------------------------------------------------------------

    Degree of Improvement in Visibility: While visibility is not an
explicitly listed factor to consider when determining whether
additional controls are reasonable under the reasonable progress
requirements, the purpose of the four-factor analysis is to determine
what degree of progress toward natural visibility conditions is
reasonable. Therefore, it is appropriate to consider the projected
visibility benefit of the controls when determining if the controls are
needed to make reasonable progress.\128\ There are four Class I areas
within 300 km of the Entergy Independence Plant. We conducted CALPUFF
modeling to determine the visibility improvement of SO2
controls at these Class I areas, based on the 98th percentile
visibility impacts.\129\ As shown in the tables below, both dry FGD and
wet FGD are projected to result in considerable visibility improvement
from the baseline at each modeled Class I area. For Unit 1, dry FGD is
projected to result in almost 0.5 dv of visibility improvement at each
modeled Class I area, and for Unit 2 it is projected to result in
almost or slightly greater than

0.5 dv of visibility improvement at each Class I area. The incremental
visibility improvement of wet FGD over dry FGD is projected to be
minimal, ranging from 0.008-0.028 dv at each Class I area for Unit 1
and 0.009-0.022 dv for Unit 2.
---------------------------------------------------------------------------

    \128\ See 79 FR at 74838, 74840, and 74874.
    \129\ See Appendix C to the TSD, titled ``Technical Support
Document for Visibility Modeling Analysis for Entergy Independence
Generating Station,'' for a detailed discussion of the visibility
modeling protocol and model inputs. A copy of the TSD and its
appendices is found in the docket for this proposed rulemaking.

                          Table 62--Entergy Independence Unit 1: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        1.133        0.657         0.64        0.476        0.493        0.017
Upper Buffalo................................................          180        0.845        0.385        0.377        0.460        0.468        0.008
Hercules-Glades..............................................          173        0.793        0.295        0.267        0.498        0.526        0.028
Mingo........................................................          174        0.739        0.298        0.284        0.441        0.455        0.014
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........         3.51        1.635        1.568        1.875        1.942        0.067
--------------------------------------------------------------------------------------------------------------------------------------------------------

                          Table 63--Entergy Independence Unit 2: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        1.412        0.865        0.843        0.547        0.569        0.022
Upper Buffalo................................................          180        0.997        0.509        0.499        0.488        0.498         0.01
Hercules-Glades..............................................          173        0.977        0.364        0.355        0.613        0.622        0.009
Mingo........................................................          174        0.883        0.388        0.374        0.495        0.509        0.014
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........        4.269        2.126        2.071        2.143        2.198        0.055
--------------------------------------------------------------------------------------------------------------------------------------------------------

                     Table 64--Entergy Independence: EPA Modeled 98th Percentile Visibility Impacts of SO2 Controls (Facility-wide)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impact ([Delta]dv)       Visibility improvement   Incremental
                                                                           ---------------------------------------    over baseline (dv)      visibility
                         Class I area                            Distance                                         -------------------------- improvement
                                                                   (km)       Baseline     Dry FGD      Wet FGD                               of wet FGD
                                                                                Dry FGD      Wet FGD    vs. dry FGD
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................................................          277        2.412        1.474        1.442        0.938         0.97        0.032
Upper Buffalo................................................          180        1.764        0.876         0.86        0.888        0.904        0.016
Hercules-Glades..............................................          173        1.704        0.648        0.608        1.056        1.096         0.04
Mingo........................................................          174        1.547        0.676        0.649        0.871        0.898        0.027
                                                              ------------------------------------------------------------------------------------------
    Total....................................................  ...........        7.427        3.674        3.559        3.753        3.868        0.115
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Proposed RP Determination for SO2: Based on our analysis
of the four RP factors, as well as the considerable projected
visibility improvement, we propose to require compliance with an
emission limit of 0.06 lb/MMBtu for Independence Units 1 and 2 based on
a 30 boiler-operating-day rolling average basis. We propose to find
that this emission limit, which is based on the installation and
operation of dry FGD, is cost-effective at $2,477 per SO2
ton removed for Unit 1 and $2,286 per SO2 ton removed for
Unit 2, and would result in significant visibility benefits at the
Caney Creek and Upper Buffalo Wilderness Areas and the two Class I
areas in Missouri. Under either Option 1 or 2, we are proposing
SO2 controls on Independence Units 1 and 2 for the first
planning period. We note that more recent emission data show an overall
increase in SO2 emissions from the facility. Therefore
anticipated visibility improvement from controls would be anticipated
to be larger and the $/SO2 ton reduced would be smaller had
we used a more recent time period for the baseline emissions modeled.
We found that in this instance, the cost of wet FGD on a dollars per
ton removed basis is higher than that of dry FGD. We found the cost of
wet FGD to be $3,706 and $3,416 per ton of SO2 removed at
Units 1 and 2, respectively. We found the cost of dry FGD to be $2,477
and $2,286 per ton of SO2 removed for Units 1 and 2,
respectively. We do not believe that the minimal amount of incremental
visibility improvement projected to result from wet FGD justifies the
higher cost compared to dry FGD. We are proposing to require compliance
with an emission limit of 0.06 lb/MMBtu based on a 30 boiler-operating-
day rolling average basis for Independence Units 1 and 2 no later than
5 years from the effective date of the final rule, based on the
installation and operation of dry FGD. We are proposing that the
facility demonstrate compliance with this emission limit using the
existing CEMS. We are also proposing regulatory text that includes
monitoring, reporting, and recordkeeping requirements associated with
this emission limit.
    b. Reasonable Progress Analysis for NOX controls. As
noted previously, monitoring data as well as CENRAP's CAMx source
apportionment modeling results for 2002 and 2018 show that visibility
impairment is not projected to be significantly impacted by nitrate on
the 20% worst days at Caney Creek or Upper Buffalo. Point source
emissions of NOX are projected to contribute to

less than 5% of the total impairment on the 20% worst days in both 2002
and 2018. The CENRAP CAMx source apportionment modeling does not
provide visibility impairment estimates for individual facilities.
    As part of our analysis for Independence, we performed modeling
using CALPUFF to assess the facility's individual visibility impact and
the visibility benefit of controls, as was done for the subject-to-BART
units discussed above including the sister facility, White Bluff.
CALPUFF is the recommended model \130\ for visibility impact analysis
for BART determinations and other single source visibility modeling
where the Class I areas of interest are within 300 km of the source.
This modeling provided information on the total visibility impairment
from emissions from the source, including impacts from SO2
and NOX emissions. The primary goal of this modeling was to
assess the potential visibility benefit of SO2 controls,
given the relatively large emissions of SO2 from the
facility and that SO2 emissions are the primary cause of
visibility impairment on the 20% worst days at the Class I areas of
interest. The results of this analysis of SO2 controls are
discussed in the section above. These CALPUFF results also indicated
that impacts from NOX emissions can be significant on some
days, and as discussed further below, NOX emission controls
can be anticipated to result in a sizeable reduction in the maximum
impacts from the facility. The analysis of the sister facility, Entergy
Independence, revealed similar results.
---------------------------------------------------------------------------

    \130\ 70 FR 39104.
---------------------------------------------------------------------------

    In evaluating CALPUFF modeling results for BART, the 98th
percentile ranked impact (H8H) was used consistent with our guideline
techniques in conducting the CALPUFF modeling. CALPUFF modeling
provides an assessment of the near maximum (98th percentile) visibility
impairment on nearby Class I areas from the source of interest based on
the facility's maximum short term emissions modeled over a three year
period. It is important to note that a specific facility's maximum
impact on a Class I area may not correlate with the same meteorological
conditions or days when visibility is most impaired at a particular
Class I area since CALPUFF modeling is only for one facility and does
not include other facilities and emissions sources. Because of the
nature of visibility impairment, we consider it appropriate to assess
visibility impacts from a single source against a natural background.
Visibility impairment on the 20% worst days may be driven by impacts
from other facilities and different meteorological conditions.
Identification of the 20% worst days is determined by IMPROVE monitor
data during the baseline period at each Class I area. The source
apportionment results for the 20% worst days are then based on CAMx
modeling using a single year of meteorological data (2002) and using
estimates of actual emissions from 2002 and projected to 2018 for all
emission sources in the modeling domain (continental U.S.). Due in
large part to the difference in metrics between the maximum impact as
modeled by CALPUFF and the average impact during the 20% worst days,
the CALPUFF modeling results discussed below indicate a more
significant impact than suggested by the source apportionment CAMx
results. We also note that differences in the metrics examined (maximum
98th percentile impact versus average impact during the 20% worst
days), emissions modeled (single-source maximum 24-hour actual
emissions versus actual emissions from all emission sources \131\), and
differences in chemistry models result in CAMx visibility analysis
results for a source or group of sources being much lower in magnitude
than visibility impacts as modeled by CALPUFF.
---------------------------------------------------------------------------

    \131\ Emissions used in CALPUFF modeling represented the maximum
24-hour emission rate. Based on evaluation of some sources that had
both annual and maximum 24-hour actual data, EPA recommended that
sources could use an emission rate that was double the annual
emission rate (used in CAMx) to approximate the maximum 24-hour
actual emission rates for some sources for CALPUFF modeling when
there was not enough data to generate a maximum 24-hr actual
emission rate.
---------------------------------------------------------------------------

    The single source CALPUFF modeling shows that sizeable reductions
to the maximum 98th percentile visibility impact from the Independence
facility may be achieved through NOX controls. We recognize,
however, that at this time, point source NOX emissions are
not the main contributors to visibility impairment on the 20% worst
days at Arkansas' Class I areas, as projected by CAMx source
apportionment modeling. Also, Arkansas Class I areas are projected to
achieve progress greater than that needed to meet the URP. Because our
assessment of the Independence facility indicates that it is
potentially one of the largest single contributors to visibility
impairment at Class I areas in Arkansas, we believe that it is
appropriate to evaluate the appropriateness of NOX controls
during this planning period.
    As discussed above, due to the similarity of these facilities, we
applied the total annualized LNB/SOFA cost developed by Entergy for
White Bluff Units 1 and 2, with one line item revision made by us, to
Independence Units 1 and 2.\132\ However, we adjusted the cost-
effectiveness ($/ton) due to the differing NOX emissions
from the units. Since our proposed BART determination for the White
Bluff facility is that LNB/SOFA is more cost effective (lower $/ton)
than SNCR or SCR, and that the additional visibility benefits obtained
as a result of the greater level of control SNCR and SCR offer over
combustion controls are not worth the additional cost of SNCR or SCR,
we expect that the same would apply to Independence Units 1 and 2.
Therefore, our evaluation of NOX controls for Independence
Units 1 and 2 will focus solely on LNB/SOFA.
---------------------------------------------------------------------------

    \132\ See our discussion above of the cost analysis for
NOX BART for White Bluff Units 1 and 2, under section
III.C.4 of this proposed rulemaking.
---------------------------------------------------------------------------

    Consistent with the cost estimate developed for White Bluff, we
estimated a total annual cost for LNB/SOFA at Independence of
approximately $1,085,904 at Unit 1 and $1,403,376 at Unit 2.\133\ We
expect LNB/SOFA to achieve a controlled emission level of 0.15 lb/
MMBtu, and estimate that the annual emissions reductions at Unit 1
would be 2,710 NOX tpy, assuming baseline emissions \134\ of
6,329 NOX tpy (see table below). The average cost-
effectiveness of LNB/SOFA at Unit 1 is estimated to be $401 per
NOX ton removed. For Unit 2, we estimate that the annual
emissions reductions would be 3,217 NOX tpy, assuming
baseline emissions of 6,384 NOX tpy. The average cost-
effectiveness of LNB/SOFA at Unit 2 is estimated to be $436 per
NOX ton removed.
---------------------------------------------------------------------------

    \133\ See the spreadsheet titled ``Independence Cost
Spreadsheet_LNB-SOFA.'' A copy of this spreadsheet is found in the
docket for our proposed rulemaking.
    \134\ Baseline emissions were determined by examining annual
NOX emissions for the years 2009-2013, eliminating the
year with the highest emissions and the year with the lowest
emissions, and obtaining the average of the three remaining years.

                                       Table 65--Summary of LNB/SOFA Costs for Entergy Independence Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Controlled      Annual emissions                        Average cost
                           Unit                            Baseline emission    emission level    reductions (NOX   Total annual cost  effectiveness ($/
                                                             rate (NOX tpy)       (lb/MMBtu)            tpy)              ($/yr)              ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1                                                                 6,329               0.15              2,710         $1,085,904               $401
Unit 2                                                                 6,384               0.15              3,217          1,403,376                436
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Time Necessary for Compliance: As is generally the case for
installation of NOX controls on EGUs, we expect that 3 years
from the date of our final action would be sufficient time for
Independence to install and operate LNB/SOFA controls at Units 1 and 2
and to comply with the associated emission limits.
    Energy and Non-Air Quality Environmental Impacts of Compliance: We
are not aware of any energy or non-air quality environmental impacts
that would preclude LNB/SOFA from consideration at Independence Units 1
and 2.
    Remaining Useful Life: Independence Units 1 and 2 were installed in
1983 and 1984. Unit 1 was placed into operation in 1983 and Unit 2 was
placed into operation in 1985. As there is no enforceable shut-down
date for Units 1 and 2, we presume that the units would continue to
operate for greater than 30 years and fully amortize the cost of
controls. In our analysis of the cost of controls we have assumed an
equipment life of 30 years.
    Degree of Improvement in Visibility: While visibility is not an
explicitly listed factor to consider when determining whether
additional controls are reasonable under the reasonable progress
requirements, the purpose of the four-factor analysis is to determine
what degree of progress toward natural visibility conditions is
reasonable. Therefore, it is appropriate to consider the projected
visibility benefit of the controls when determining if the controls are
needed to make reasonable progress.\135\ There are four Class I areas
within 300 km of the Entergy Independence Plant. We conducted CALPUFF
modeling to determine the visibility improvement of NOX
controls at these Class I areas, based on the 98th percentile
visibility impacts.\136\ As shown in the table below, LNB/SOFA is
projected to result in a visibility improvement from the baseline at
each modeled Class I area.\137\ On a facility-wide basis, the
installation and operation of LNB/SOFA on Units 1 and 2 is projected to
result in 0.461 dv in visibility improvement at Caney Creek, while the
projected visibility improvement at each of the other modeled Class I
areas ranges from 0.213-0.264 dv. We also conducted a modeling run of
both LNB/OFA and dry FGD, which shows projected visibility benefits
ranging from 1.18-1.48 dv at each Class I area.\138\ As discussed
above, more recent emission data show an overall increase in
SO2 emissions from the facility. Therefore anticipated
visibility improvement from controls would be anticipated to be larger
and there would be an improvement in the cost-effectiveness (i.e.,
lower dollars per ton removed) of controls had we used a more recent
time period for the baseline emissions modeled.
---------------------------------------------------------------------------

    \135\ See 79 FR at 74838, 74840, and 74874.
    \136\ See Appendix C to the TSD, titled ``Technical Support
Document for Visibility Modeling Analysis for Entergy Independence
Generating Station,'' for a detailed discussion of the visibility
modeling protocol and model inputs. A copy of the TSD and its
appendices is found in the docket for this proposed rulemaking.
    \137\ Id.
    \138\ This is discussed in more detail in Appendix C to the TSD,
titled ``Technical Support Document for Visibility Modeling Analysis
for Entergy Independence Generating Station.''

 Table 66--Entergy Independence Units 1 and 2 (Facility-Wide): EPA Modeled 98th Percentile Visibility Impacts of
                                                    LNB/SOFA
----------------------------------------------------------------------------------------------------------------
                                                                  Visibility impact  ([Delta]dv)    Visibility
                                                                 --------------------------------   improvement
                  Class I area                    Distance  (km)                                    of LNB/SOFA
                                                                  Baseline \139\     LNB/SOFA      over baseline
                                                                                (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................................             277           2.054           1.593           0.461
Upper Buffalo...................................             180           1.724           1.476           0.248
Hercules-Glades.................................             173           1.482           1.218           0.264
Mingo...........................................             174           1.492           1.279           0.213
                                                 ---------------------------------------------------------------
    Total.......................................  ..............           6.752           5.566           1.186
----------------------------------------------------------------------------------------------------------------

    Proposed RP Determination for NOX: As discussed above, based on the
CENRAP's CAMx modeling, sulfate from point sources is the driver of
regional haze at Caney Creek and Upper Buffalo on the 20% worst days in
both 2002 and 2018. Nitrate from point sources is not considered a
driver of regional haze at these Class I areas on the 20% worst days,
contributing only approximately 3% of the total light extinction. The
Regional Haze Rule requires that the established RPGs provide for an
improvement in visibility for the most impaired days (i.e., the 20%
worst days) over the period of the implementation plan and ensure no
degradation in visibility for the least impaired days over the same
period (40 CFR 51.308(d)(1)). Because of the small contribution of
nitrate from point sources to the total light extinction at Caney Creek
and Upper Buffalo on the most impaired days, we do not expect that
NOX controls under the reasonable progress requirements
would offer as much improvement on the most impaired days compared to
SO2 controls. However, upon evaluation of the four
reasonable progress factors, we found that the installation and
operation of LNB/SOFA at Independence Units 1 and 2 is estimated to
cost $401/NOX ton

removed at Unit 1 and $436/NOX ton removed at Unit 2, which
we consider to be very cost-effective. These NOX controls
are also projected to result in significant visibility improvements at
Arkansas and Missouri Class I areas, based on CALPUFF modeling using
the 98th percentile modeled visibility impacts. Therefore, under Option
1, for the first planning period, we are proposing both an
SO2 emission limit as described above and a NOX
emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day averaging
basis based on the installation and operation of LNB/SOFA, in light of
their cost-effectiveness and visibility benefit based on CALPUFF
modeling, even though nitrate from point sources is projected to
contribute a very small proportion of the total light extinction at
Caney Creek and Upper Buffalo on the 20% worst days in 2018. Based on
our visibility modeling of both LNB/OFA and dry FGD, proposed Option 1
is projected to have visibility benefits ranging from 1.18--1.48 dv at
each Class I area.\140\ Under Option 2, we are proposing only
SO2 controls for Independence Units 1 and 2 under the
reasonable progress requirements. Based on our visibility modeling of
dry FGD, proposed Option 2 is projected to have visibility benefits
ranging from 0.87--1.06 dv at each Class I area. We specifically
solicit public comment on this proposed alternative approach.
---------------------------------------------------------------------------

    \139\ Baseline NOX emissions were updated to the
maximum 24-hr emissions from 2011-2013 for the evaluation of the
anticipated benefit from NOX controls.
    \140\ See Appendix C to the TSD, titled ``Technical Support
Document for Visibility Modeling Analysis for Entergy Independence
Generating Station,'' for a detailed discussion of the visibility
modeling protocol and model inputs. A copy of the TSD and its
appendices is found in the docket for this proposed rulemaking.
---------------------------------------------------------------------------

    In addition to options 1 and 2, we also solicit public comment on
any alternative SO2 and NOX control measures that
would address the regional haze requirements for Entergy White Bluff
Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning
period. This includes, but is not limited to, a combination of early
unit shutdowns and other emissions control measures that would achieve
greater reasonable progress than the BART and reasonable progress
requirements we have proposed for these four units in this rulemaking.

B. Reasonable Progress Goals

    We propose RPGs for Caney Creek and Upper Buffalo that are
consistent with the combination of control measures from the approved
portion of the 2008 Arkansas RH SIP and our proposed Arkansas RH FIP.
In total, these final and proposed controls to meet the BART and RP
requirements will result in higher emissions reductions and
commensurate visibility improvements beyond what was in the 2008
Arkansas RH SIP. Development of refined numerical RPGs for Arkansas'
Class I areas would require photochemical grid modeling of a multistate
area, involving thousands of emission sources, unlike the comparatively
simple single-source CALPUFF modeling used for individual BART
assessments. In order to accurately reflect all emissions reductions
expected to occur during this planning period, the new photochemical
modeling would require an update of the emissions inventory for
Arkansas and the surrounding states to include not just the actions
under this FIP, but all EPA and state regulatory actions on point,
area, and mobile sources. After the inventory is developed and reviewed
by the affected states for accuracy, it must be converted to a model-
ready format before air quality modeling can be used to estimate the
future visibility levels at the Class I areas. This modeling would
require specialized and extensive computing hardware and expertise.
Developing all of the necessary input files, running the photochemical
model, and post-processing the model outputs would take several months
at a minimum. Therefore, we are not conducting new photochemical grid
modeling to establish revised numeric RPGs for Caney Creek and Upper
Buffalo.
    In order to provide RPGs that account for emission reductions from
the FIP controls, we have used a method similar to the one used in our
Regional Haze FIP for Hawaii \141\ and Arizona,\142\ which is based on
a scaling of visibility extinction components in proportion to emission
changes. To determine the new RPGs for Caney Creek and Upper Buffalo,
we started with the 2018 projection of extinction components from the
CENRAP's CAMx photochemical modeling with source apportionment. The
2018 CAMx emission scenario included some assumptions of state BART
determinations and other SIP controls, as well as projected emissions
from other point, area, and mobile sources. We scaled the modeled
visibility extinction components for sulfate (SO4) and
nitrate (NO3) from point sources in Arkansas in proportion
to the FIP's emission reductions for SO2 and NOX,
respectively. The sulfate scaling factor was the 2018 CENRAP emission
inventory for Arkansas point source SO2 emissions with FIP
controls for BART and RP sources in place, divided by the original 2018
CENRAP emission inventory for Arkansas point source SO2
emissions. We conducted the same scaling exercise with nitrate and
NOX. The scaled sulfate and nitrate extinctions were added
to the unscaled extinctions for organic mass and other components to
get total extinction, and then this was used to calculate post-FIP RPGs
in deciviews. Although we recognize that this method is not refined, it
allows us to translate the emission reductions contained in this
proposed FIP into quantitative RPGs, based on modeling previously
performed by the CENRAP. These RPGs reflect rates of progress that are
faster than the rates projected by Arkansas. The revised RPGs for the
first planning period for the 20% worst days are 22.27 dv for Caney
Creek and 22.33 dv for Upper Buffalo. The results of our analysis are
shown in the table below.\143\ The RPG calculation was performed for
both our proposed Options 1 and 2. Under Option 1 we are proposing to
control Entergy Independence Units 1 and 2 for the first planning
period for both SO2 and NOX. Alternatively, under
Option 2, we are proposing to control Entergy Independence Units 1 and
2 only for SO2 for the first planning period. Due to the
small impact from all Arkansas point source NOx emissions combined on
the 20% worst days and the scaling approach utilized to estimate the
adjustment to the RPG, the difference between the two proposed options
results in a very small difference in the calculated RPGs for Caney
Creek and Upper Buffalo (less than 0.003 dv). We note that some FIP
controls will not be in place by 2018, however, for the purpose of this
calculation, we included reductions from all FIP controls. Arkansas
will have to re-evaluate during the next regional haze planning period
what BART and reasonable progress controls are in place and re-
calculate the RPGs for the next planning period as needed. We also note
that RPGs, unlike the emission limits that apply to specific RP
sources, are not directly enforceable.\144\ Rather, they are an
analytical framework considered by us in evaluating whether measures in
the implementation plan are sufficient to

achieve reasonable progress.\145\ Arkansas may choose to use these RPGs
for purposes of its progress report, or may develop new RPGs for
approval by us along with its progress report, based on new modeling or
other appropriate techniques, in accordance with the requirements of 40
CFR 51.308(d)(1).
---------------------------------------------------------------------------

    \141\ See 77 FR 31692, 31708.
    \142\ See 79 FR 52420, 52468.
    \143\ Please see Appendix C to the TSD, titled ``Technical
Support Document for Visibility Modeling Analysis for Entergy
Independence Generating Station,'' and the RPG calculation
spreadsheet for additional details on calculations. These documents
are found in the docket for our proposed rulemaking.
    \144\ 40 CFR 51.308(d)(1)(v).
    \145\ 64 FR 35733 and 40 CFR 51.308(d)(1)(v).

                                             Table 67--Proposed Reasonable Progress Goals for 20% Worst Days
                                                                     [In Deciviews]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                2018
                      Class I area                           2000-2004     2064 Natural      2018 URP      Projection by   Estimated FIP   Estimated FIP
                                                             Baseline       conditions                        CENRAP          effect         2018 RPG
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................................           26.36           11.58           22.91           22.48           -0.21           22.27
Upper Buffalo...........................................           26.27           11.57           22.84           22.52           -0.19           22.33
--------------------------------------------------------------------------------------------------------------------------------------------------------

V. Our Proposed Long-Term Strategy

    Section 169A(b) of the CAA and 40 CFR 51.308(d)(3) require that
states include in their SIP a 10 to 15-year strategy, referred to as
the long-term strategy, for making reasonable progress for each Class I
area within their state. This long-term strategy is the compilation of
all control measures a state will use during the implementation period
of the specific SIP submittal to meet any applicable RPGs for a
particular Class I area. The long-term strategy must include
``enforceable emissions limitations, compliance schedules, and other
measures as necessary to achieve the reasonable progress goals'' for
all Class I areas within, or affected by emissions from, the
state.\146\
---------------------------------------------------------------------------

    \146\ 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------

    Section 51.308(d)(3)(v) requires that a state consider certain
factors (the long-term strategy factors) in developing its long-term
strategy for each Class I area. These factors are the following: (1)
Emission reductions due to ongoing air pollution control programs,
including measures to address RAVI; (2) measures to mitigate the
impacts of construction activities; (3) emissions limitations and
schedules for compliance to achieve the reasonable progress goal; (4)
source retirement and replacement schedules; (5) smoke management
techniques for agricultural and forestry management purposes including
plans as currently exist within the state for these purposes; (6)
enforceability of emissions limitations and control measures; and (7)
the anticipated net effect on visibility due to projected changes in
point, area, and mobile source emissions over the period addressed by
the long-term strategy. Since states are required to consider emissions
limitations and schedules of compliance to achieve the RPGs for each
Class I area, the BART emission limits that are in the state's regional
haze SIP are an element of the state's long-term strategy (40 CFR
51.308(d)(3)) for each Class I area. In our March 11, 2012 final action
on the 2008 Arkansas RH SIP, since we disapproved a portion of
Arkansas' BART determinations and both RPGs for Arkansas' two Class I
areas, we also disapproved these elements and approved all other
elements of Arkansas' long-term strategy. The BART limits and two RPGs
for Arkansas' Class I areas that are in this proposed FIP address our
March 11, 2011 disapproval of Arkansas' BART limits and two RPGs. We
propose to find that the proposed BART limits and two RPGs that are in
this proposed FIP also correct the deficiency in Arkansas' long-term
strategy for each of its Class I areas.

VI. Our Proposal for Interstate Visibility Transport

    We received the Arkansas Interstate Visibility Transport SIP that
addresses the interstate visibility transport requirements of CAA
section 110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and
PM2.5 NAAQS on April 2, 2008. In its Interstate Visibility
Transport SIP, Arkansas stated that its regional haze regulation, the
APC&E Commission Regulation 19, chapter 15, codifying its Regional Haze
SIP, satisfies the requirement of section 110(a)(2)(D)(i)(II) regarding
the protection of visibility, and that it was not possible to assess
whether there is any interference with measures in the applicable SIP
for another state designed to protect visibility for the 8-hour ozone
and PM2.5 NAAQS in other states until Arkansas submits and
we approve the 2008 Arkansas RH SIP. In our March 12, 2012 final
action, we partially approved and partially disapproved the Arkansas
Interstate Visibility Transport SIP because we partially approved and
partially disapproved the 2008 Arkansas RH SIP. In particular, we
disapproved a large portion of Arkansas' BART determinations, and as a
result, the corresponding emissions reductions other states had relied
upon in their RPG demonstrations under the RHR would not take place.
Therefore, we made a finding that Arkansas' SIP does not fully ensure
that emissions from sources in Arkansas do not interfere with other
states' visibility programs as required by section 110(a)(2)(D)(i)(II)
of the CAA. Our proposed regional haze FIP would address all
disapproved BART determinations for sources in Arkansas as well as all
other disapproved portions of the 2008 Arkansas RH SIP. Our proposed
regional haze FIP together with our prior approval of portions of the
Arkansas Regional Haze SIP would ensure that the emissions reductions
other sates relied upon in their RPG demonstrations take place.
Therefore, we propose to find that the deficiencies we identified in
our prior disapproval action on the Arkansas Interstate Visibility
Transport SIP are addressed by our proposed regional haze FIP along
with our prior approval of portions of the Arkansas Regional Haze SIP.
We are also proposing to find that the requirements of CAA section
110(a)(2)(D)(i)(II) with respect to visibility transport for the 1997
8-hour ozone and PM2.5 NAAQS will be satisfied by the
combination of the emission control measures in this proposed regional
haze FIP and the previously approved portion of the Arkansas Interstate
Visibility Transport SIP.

VII. Summary of Proposed Actions

A. Regional Haze

    We propose to promulgate a FIP to address those portions of
Arkansas' regional haze SIP that we disapproved on March 12, 2012,
which include requirements for BART, reasonable progress, and the long-
term strategy.\147\ The FIP we are proposing includes BART emission
limits for sources in Arkansas to reduce emissions that contribute to
regional haze in Arkansas' two Class I areas and other nearby Class I
areas and make reasonable progress for

the first regional haze planning period for Arkansas' two Class I
areas. This includes more stringent SO2 emission limits in
comparison to what the 2008 Arkansas RH SIP contained for the AECC Carl
E. Bailey Generating Station Unit 1, the AECC John L McClellan
Generating Station Unit 1, the AEP Flint Creek Power Plant Unit 1,
Entergy White Bluff Plant Units 1 and 2, and the Domtar Ashdown Paper
Mill Power Boiler No. 2. We are also proposing in the alternative two
options for addressing the reasonable progress requirements for this
first planning period by controlling the Entergy Independence Power
Plant for both the Caney Creek and Upper Buffalo Class I areas. Under
Option 1, we propose to require SO2 and NOX
emission reductions from the Entergy Independence Power Plant under the
reasonable progress requirements. Under Option 2, we are also proposing
only SO2 controls for Independence Units 1 and 2 under the
reasonable progress requirements. In particular, we are inviting public
comment on the alternate proposed Options 1 and 2. We also solicit
public comment on any alternative control measures for Entergy White
Bluff Units 1 and 2 and Independence Units 1 and 2 that would address
the regional haze requirements for these four units for this planning
period. We also propose to find that the proposed BART and reasonable
progress limits and RPGs that are in this proposed FIP correct the
deficiency in Arkansas' long-term strategy for both Class I areas. Our
proposed FIP, once finalized, along with the previously approved
portion of the Arkansas regional haze SIP, will constitute Arkansas'
regional haze program for the first planning period that ends in 2018.
---------------------------------------------------------------------------

    \147\ 77 FR 14604.
---------------------------------------------------------------------------

B. Interstate Visibility Transport

    We propose to find that the deficiencies we identified in our prior
disapproval action on the Arkansas Interstate Visibility Transport SIP
to address the requirement of CAA section 110(a)(2)(D)(i)(II) with
respect to visibility transport for the 1997 8-hour ozone and 1997
PM2.5 NAAQS will be remedied by our proposed Arkansas
Regional Haze FIP along with our March 2, 2012 partial approval of
certain elements of the 2008 Arkansas RH SIP. In its Interstate
Visibility Transport SIP, Arkansas stated that its regional haze
regulation, the APC&E Commission Regulation 19, chapter 15, codifying
the Arkansas Regional Haze SIP, satisfies the requirement of section
110(a)(2)(D)(i)(II) regarding the protection of visibility, and that it
was not possible to assess whether there is any interference with
measures in the applicable SIP for another state designed to protect
visibility for the 8-hour ozone and PM2.5 NAAQS in other
states until Arkansas submits and we approve the 2008 Arkansas RH SIP.
Since our FIP addresses the portions of Arkansas Regional Haze SIP that
we previously disapproved, we propose to find that the requirements of
CAA section 110(a)(2)(D)(i)(II) with respect to visibility transport
for the 1997 8-hour ozone and PM2.5 NAAQS will be satisfied
by the combination of this proposed regional haze FIP and the
previously approved portion of the Arkansas Interstate Visibility
Transport SIP.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Overview

    This proposed action is not a ``significant regulatory action''
under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993)
and is therefore not subject to review under Executive Orders 12866 and
13563 (76 FR 3821, January 21, 2011). The proposed FIP would not
constitute a rule of general applicability, because it only proposes
source specific requirements for particular, identified facilities (six
total).

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. Because it does not contain any information collection
activities, the Paperwork Reduction Act does not apply. See 5 CFR
1320(c).

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to conduct a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements 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 not-for-profit enterprises, and small governmental
jurisdictions. For purposes of assessing the impacts of today's 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 today's proposed rule on small entities, I certify that this
action will not have a significant impact on a substantial number of
small entities. In making this determination, the impact of concern is
any significant adverse economic impact on small entities. An agency
may certify that a rule will not have a significant economic impact on
a substantial number of small entities if the rule relieves regulatory
burden, has no net burden or otherwise has a positive economic effect
on the small entities subject to the rule. This rule does not impose
any requirements or create impacts on small entities. This proposed SIP
action under Section 110 of the CAA will not in-and-of itself create
any new requirements on small entities but simply approves or
disapproves certain state requirements for inclusion into the SIP.
Accordingly, it affords no opportunity for the EPA to fashion for small
entities less burdensome compliance or reporting requirements or
timetables or exemptions from all or part of the rule. The fact that
the CAA prescribes that various consequences (e.g., emission
limitations) may or will flow from this action does not mean that the
EPA either can or must conduct a regulatory flexibility analysis for
this action. We have therefore concluded that, this action will have no
net regulatory burden for all directly regulated small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on state, local, and Tribal
governments and the private sector. Under Section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to state, local, and Tribal governments, in
the aggregate, or to the private sector, of $100 million or more
(adjusted for inflation) in any 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.
    EPA has determined that Title II of UMRA does not apply to this
proposed rule. In 2 U.S.C. Section 1502(1) all terms in Title II of
UMRA have the meanings set forth in 2 U.S.C. Section 658, which further
provides that the terms ``regulation'' and ``rule'' have the meanings
set forth in 5 U.S.C. Section 601(2). Under 5 U.S.C. Section 601(2),
``the term `rule' does not include a rule of particular applicability
relating to . . . facilities.'' Because this proposed rule is a rule of
particular applicability relating to six named facilities, EPA has
determined that it is not a ``rule'' for the purposes of Title II of
UMRA.

E. Executive Order 13132: Federalism

    This proposed action does not have federalism implications. It 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.

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

    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 rulemaking.

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 \148\ 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 Executive Order 13045
because it is not economically significant as defined in Executive
Order 12866, and because the EPA does not believe the environmental
health or safety risks addressed by this action present a
disproportionate risk to children. 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 SO2, NOX, and PM, the rule will have
a beneficial effect on children's health by reducing air pollution.
---------------------------------------------------------------------------

    \148\ 62 FR 19885 (Apr. 23, 1997).
---------------------------------------------------------------------------

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

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

I. National Technology Transfer and Advancement Act

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

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

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

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Nitrogen dioxide, Ozone,
Particulate matter, Reporting and recordkeeping requirements, Sulfur
dioxides, Visibility, Interstate transport of pollution, Regional haze,
Best available control technology.

    Dated: March 6, 2015.
Samuel Coleman, P.E.
Acting Regional Administrator, Region 6.

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

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

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

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

Subpart E--Arkansas

0
2. Section 52.173 is amended by adding paragraphs (c) and (d) to read
as follows:

Sec.  52.173  Visibility protection.

* * * * *
    (c) Requirements for AECC Carl E. Bailey Unit 1; AECC John L.
McClellan Unit 1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1,
2, and Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown
Paper Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1
and 2 affecting visibility.
    (1) Applicability. The provisions of this section shall apply to
each owner

or operator, or successive owners or operators, of the sources
designated as: AECC Carl E. Bailey Unit 1; AECC John L. McClellan Unit
1; AEP Flint Creek Unit 1; Entergy White Bluff Units 1, 2, and
Auxiliary Boiler; Entergy Lake Catherine Unit 4; Domtar Ashdown Paper
Mill Power Boilers No. 1 and 2; and Entergy Independence Units 1 and 2.
    (2) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the Clean Air Act and in parts 51
and 60 of CFR title 40. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12
midnight.
    Air pollution control equipment includes selective catalytic
control units, baghouses, particulate or gaseous scrubbers, and any
other apparatus utilized to control emissions of regulated air
contaminants which would be emitted to the atmosphere.
    Boiler-operating-day for electric generating units listed under
paragraph (c)(1) of this section means any 24- hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time at the steam generating unit. For power boilers
listed under paragraph (c)(1) of this section, we define boiler-
operating-day as any 24-hour period between 12:00 midnight and the
following midnight during which any fuel is fed into and/or combusted
at any time in the Power Boiler.
    Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the units or power boilers listed under
paragraph (c)(1) of this section.
    Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
    Unit means one of the natural gas, fuel oil, or coal fired boilers
covered under paragraph (c) of this section.
    (3) Emissions limitations for AECC Bailey Unit 1 and AECC McClellan
Unit 1. The individual SO2, NOX, and PM emission
limits for each unit shall be as listed in the following table.

----------------------------------------------------------------------------------------------------------------
                 Unit                     SO2 Emission limit       NOX Emission limit       PM Emission limit
----------------------------------------------------------------------------------------------------------------
AECC Bailey Unit 1...................  Use of fuel with a       887 lb/hr..............  Use of fuel with a
                                        sulfur content limit                              sulfur content limit
                                        of 0.5% by weight.                                of 0.5% by weight.
AECC McClellan Unit 1................  Use of fuel with a       869.1 lb/hr (Natural     Use of fuel with a
                                        sulfur content limit     Gas firing).             sulfur content limit
                                        of 0.5% by weight.      705.8 lb/hr (Fuel Oil     of 0.5% by weight.
                                                                 firing).
----------------------------------------------------------------------------------------------------------------

    (4) Compliance dates for AECC Bailey Unit 1 and AECC McClellan
Unit. The owner or operator of each unit shall comply with the
SO2 and PM requirements listed in paragraph (c)(3) of this
section within 5 years of the effective date of this rule. As of the
effective date of this rule, the owner/operator of each unit shall not
purchase fuel for combustion at the unit that does not meet the sulfur
content limit in paragraph (c)(3) of this section. Five years from the
effective date of the rule only fuel that meets the sulfur content
limit in paragraph (c)(3) of this section shall be burned at each unit.
The owner/operator of each unit shall comply with the NOX
emission limits in paragraph (c)(3) of this section as of the effective
date of this rule.
    (5) Compliance determinations for AECC Bailey Unit 1 and AECC
McClellan Unit--(i) SO2 and PM. To determine compliance with the
SO2 and PM requirements listed in paragraph (c)(3) of this
section, the owner/operator shall sample and analyze each shipment of
fuel to determine the sulfur content, except for natural gas shipments.
A ``shipment'' is considered delivery of the entire amount of each
order of fuel purchased. Fuel sampling and analysis may be performed by
the owner or operator of an affected unit, an outside laboratory, or a
fuel supplier.
    (ii) NOX. To determine compliance with the NOX emission
limits of paragraph (c)(3) of this section, the owner/operator shall
determine the average emissions (arithmetic average of three contiguous
one hour periods) of NOX as measured by a CEMS and converted
to pounds per hour using corresponding average (arithmetic average of
three contiguous one hour periods) stack gas flow rates.
    (iii) The owner or operator shall continue to maintain and operate
a CEMS for NOX on the units listed in paragraph (c)(3) of
this section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h),
and appendix B of part 60. The owner or operator shall comply with the
quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission limits for NOX shall be
determined by using data from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(3) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring NOX
and diluent gas shall complete a minimum of one cycle of operation
(sampling, analyzing, and data recording) for each successive 15-minute
period. 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. When valid NOX
pounds per hour emission data 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 to provide emission data for a
minimum of 18 hours in each 24 hour period and at least 22 out of 30
successive boiler operating days.
    (6) Emissions limitations for AEP Flint Creek Unit 1 and Entergy
White Bluff Units 1 and 2. The individual SO2 and
NOX emission limits for each unit shall be as listed in the
following table in pounds per million British thermal units (lb/MMBtu)
as averaged over a rolling 30 boiler-operating-day period.

----------------------------------------------------------------------------------------------------------------
                                                                SO2 Emission limit (lb/  NOX Emission limit (lb/
                             Unit                                        MMBtu)                   MMBtu)
----------------------------------------------------------------------------------------------------------------
AEP Flint Creek Unit 1........................................                     0.06                     0.23
Entergy White Bluff Unit 1....................................                     0.06                     0.15
Entergy White Bluff Unit 2....................................                     0.06                     0.15
----------------------------------------------------------------------------------------------------------------

    (7) Compliance dates for AEP Flint Creek Unit 1 and Entergy White
Bluff Units 1 and 2. The owner or operator of each unit shall comply
with the SO2 emission limit listed in paragraph (c)(6) of
this section within 5 years of the effective date of this rule and the
NOX emission limit within 3 years of the effective date of
this rule.
    (8) Compliance determination for AEP Flint Creek Unit 1 and Entergy
White Bluff Units 1 and 2. (i) For each unit, SO2 and
NOX emissions for each calendar day shall be determined by
summing the hourly emissions measured in pounds of SO2 or
pounds of NOX. For each unit, heat input for each boiler-
operating-day shall be determined by adding together all hourly heat
inputs, in millions of BTU. Each boiler-operating-day of the thirty-day
rolling average for a unit shall be determined by adding together the
pounds of SO2 or NOX from that day and the
preceding 29 boiler-operating-days and dividing the total pounds of
SO2 or NOX by the sum of the heat input during
the same 30 boiler-operating-day period. The result shall be the 30
boiler-operating-day rolling average in terms of lb/MMBtu emissions of
SO2 or NOX. If a valid SO2 or
NOX pounds per hour or heat input is not available for any
hour for a unit, that heat input and SO2 or NOX
pounds per hour shall not be used in the calculation of the 30 boiler-
operating-day rolling average for SO2 or NOX.
    (ii) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(6) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and Appendix B of Part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all
periods of operation of the units listed in paragraph (c)(6) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
SO2 and NOX and diluent gas shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period. 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. When valid SO2 or NOX
pounds per hour emission data 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 to provide emission data for a
minimum of 18 hours in each 24 hour period and at least 22 out of 30
successive boiler operating days.
    (9) Emissions limitations for Entergy White Bluff Auxiliary Boiler.
The individual SO2, NOX, and PM emission limits
for the unit shall be as listed in the following table in pounds per
hour (lb/hr).

----------------------------------------------------------------------------------------------------------------
                                       SO2 Emission limit (lb/  NOX Emission limit (lb/   PM Emission limit (lb/
                 Unit                            hr)                      hr)                      hr)
----------------------------------------------------------------------------------------------------------------
Entergy White Bluff Auxiliary Boiler.                    105.2                     32.2                      4.5
----------------------------------------------------------------------------------------------------------------

    (10) Compliance dates for Entergy White Bluff Auxiliary Boiler. The
owner or operator of the unit shall comply with the SO2,
NOX, and PM emission limits listed in paragraph (c)(9) of
this section as of the effective date of this rule.
    (11) Emissions limitations for Entergy Lake Catherine Unit 4. The
individual NOX emission limit for the unit for natural gas
firing shall be as listed in the following table in pounds per million
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. The unit shall not burn fuel oil until BART
determinations are promulgated for the unit for SO2,
NOX, and PM for the fuel oil firing scenario through a FIP
and/or through EPA action upon and approval of revised BART
determinations submitted by the State as a SIP revision.

------------------------------------------------------------------------
                                                          NOX Emission
                                                         limit--natural
                         Unit                           gas firing (lb/
                                                             MMBtu)
------------------------------------------------------------------------
Entergy Lake Catherine Unit 4........................               0.22
------------------------------------------------------------------------

    (12) Compliance dates for Entergy Lake Catherine Unit 4. The owner
or operator of the unit shall comply with the NOX emission
limit listed in paragraph (c)(11) of this section within 3 years of the
effective date of this rule.
    (13) Compliance determination for Entergy Lake Catherine Unit 4.
(i) NOX emissions for each calendar day shall be determined
by summing the hourly emissions measured in pounds of NOX.
The heat input for each boiler-operating-day shall be determined by
adding together all hourly heat inputs, in millions of BTU. Each
boiler-operating-day of the thirty-day rolling average for the unit
shall be determined by adding together the pounds of NOX
from that day and the preceding 29 boiler-operating-days and dividing
the total pounds of NOX by the sum of the heat input during
the same 30 boiler-operating-day period. The result shall be the 30
boiler-operating-day rolling average in terms of lb/MMBtu emissions of
NOX. If a valid NOX pounds per hour or heat input
is not available for any hour for the unit, that heat input and
NOX pounds per hour shall not be used in the calculation of
the 30 boiler-operating-day rolling average for NOX.
    (ii) The owner or operator shall continue to maintain and operate a
CEMS for NOX on the unit listed in paragraph (c)(11) of this
section in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and
appendix B of

part 60. The owner or operator shall comply with the quality assurance
procedures for CEMS found in 40 CFR part 75. Compliance with the
emission limit for NOX shall be determined by using data
from a CEMS.
    (iii) Continuous emissions monitoring shall apply during all
periods of operation of the unit listed in paragraph (c)(11) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
NOX and diluent gas shall complete a minimum of one cycle of
operation (sampling, analyzing, and data recording) for each successive
15-minute period. 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. When valid
NOX pounds per hour emission data 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 to provide emission
data for a minimum of 18 hours in each 24 hour period and at least 22
out of 30 successive boiler operating days.
    (14) Emissions limitations for Domtar Ashdown Paper Mill Power
Boiler No.1. The individual SO2 and NOX emission
limits for the power boiler shall be as listed in the following table
in pounds per hour (lb/hr) as averaged over a rolling 30 boiler-
operating-day period. For this power boiler, boiler-operating-day is
defined as a 24-hour period between 12 midnight and the following
midnight during which any fuel is fed into and/or combusted at any time
in the power boiler.

----------------------------------------------------------------------------------------------------------------
                                                                SO2 Emission limit (lb/  NOX Emission limit (lb/
                             Unit                                         hr)                      hr)
----------------------------------------------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 1..................                     21.0                    207.4
----------------------------------------------------------------------------------------------------------------

    (15) Compliance dates for Domtar Ashdown Mill Power Boiler No. 1.
The owner or operator of the power boiler shall comply with the
SO2 and NOX emission limits listed in paragraph
(c)(14) of this section as of the effective date of this rule.
    (16) Compliance determination for Domtar Ashdown Paper Mill Power
Boiler No. 1. (i) SO2 emissions for each calendar day shall
be determined by summing the hourly emissions measured in pounds of
SO2. SO2 emissions from combustion of bark shall
be determined by using the following site-specific curve equation,
which accounts for the SO2 scrubbing capabilities of bark
combustion:

Y= 0.4005 * X-0.2645

Where:

Y= pounds of sulfur emitted per ton of dry fuel feed to the boiler
X= pounds of sulfur input per ton of dry bark

The owner or operator shall confirm the site-specific curve equation
through stack testing. No later than 1 year after the effective date of
this rule, the owner or operator shall provide a report to EPA showing
confirmation of the site specific-curve equation accuracy. Stack
SO2 emissions from combustion of fuel oil shall be
determined by assuming that the SO2 inlet is equal to the
SO2 being emitted at the stack.
    (ii) To demonstrate compliance with the NOX emission
limit under paragraph (c)(14) of this section, the owner or operator
shall conduct annual stack testing.
    (iii) Each boiler-operating-day of the thirty-day rolling average
for the power boiler shall be determined by adding together the pounds
of SO2 or NOX from that day and the preceding 29
boiler-operating-days and dividing the total pounds of SO2
or NOX by the sum of the total number of hours during the
same 30 boiler-operating-day period. The result shall be the 30 boiler-
operating-day rolling average in terms of lb/hr emissions of
SO2 or NOX. If a valid SO2 or
NOX pounds per hour is not available for any hour for the
power boiler, that SO2 or NOX pounds per hour
shall not be used in the calculation of the applicable 30 boiler-
operating-day rolling average.
    (17) SO2 and NOX emissions limitations for Domtar Ashdown Paper
Mill Power Boiler No.2. The individual SO2 and
NOX emission limits for the power boiler shall be as listed
in the following table in pounds per hour (lb/hr) or pounds per million
British thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. For this power boiler, boiler-operating-day is
defined as a 24-hour period between 12 midnight and the following
midnight during which any fuel is fed into and/or combusted at any time
in the power boiler.

----------------------------------------------------------------------------------------------------------------
                                                                SO2 Emission limit (lb/  NOX Emission limit (lb/
                             Unit                                        MMBtu)                    hr)
----------------------------------------------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 2..................                     0.11                      345
----------------------------------------------------------------------------------------------------------------

    (18) SO2 and NOX compliance dates for Domtar Ashdown Mill Power
Boiler No. 2. The owner or operator of the power boiler shall comply
with the SO2 and NOX emission limits listed in
paragraph (c)(17) of this section within 3 year of the effective date
of this rule.
    (19) SO2 and NOX compliance determination for Domtar Ashdown Mill
Power Boiler No. 2. (i) SO2 emissions for each calendar day
shall be determined by summing the hourly emissions measured in pounds
of SO2. The heat input for each boiler-operating-day shall
be determined by adding together all hourly heat inputs, in millions of
BTU. Each boiler-operating-day of the thirty-day rolling average for a
unit shall be determined by adding together the pounds of
SO2 from that day and the preceding 29 boiler-operating-days
and dividing the total pounds of SO2 by the sum of the heat
input during the same 30 boiler-operating-day period. The result shall
be the 30 boiler-operating-day rolling average in terms of lb/MMBtu
emissions of SO2. If a valid SO2 pounds per hour
or heat input is not available for any hour for a unit, that heat input
and SO2 pounds per hour shall not be used in the calculation
of the 30 boiler-operating-day rolling average for SO2.

    (ii) NOX emissions for each calendar day shall be
determined by summing the hourly emissions measured in pounds of
NOX. Each boiler-operating-day of the thirty-day rolling
average for the power boiler shall be determined by adding together the
pounds of NOX from that day and the preceding 29 boiler-
operating-days and dividing the total pounds of NOX by the
sum of the total number of hours during the same 30 boiler-operating-
day period. The result shall be the 30 boiler-operating-day rolling
average in terms of lb/hr emissions of NOX. If a valid
NOX pounds per hour is not available for any hour for the
power boiler, that NOX pounds per hour shall not be used in
the calculation of the 30 boiler-operating-day rolling average for
NOX.
    (iii) The owner or operator shall continue to maintain and operate
a CEMS for SO2 and NOX on the power boiler listed
in paragraph (c)(17) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and Appendix B of Part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.
    (iv) Continuous emissions monitoring shall apply during all periods
of operation of the units listed in paragraph (c)(17) of this section,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring SO2
and NOX and diluent gas shall complete a minimum of one
cycle of operation (sampling, analyzing, and data recording) for each
successive 15-minute period. 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. When
valid SO2 or NOX pounds per hour emission data
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 to provide emission data for a minimum of 18 hours in each 24 hour
period and at least 22 out of 30 successive boiler operating days.
    (20) PM Emissions limitations for Domtar Ashdown Paper Mill Power
Boiler No.2. The individual particulate matter emission limit for the
power boiler shall be as listed in the following table in pounds per
million British thermal units (lb/MMBtu).

------------------------------------------------------------------------
                                                      PM Emission limit
                       Unit                              (lb/MMBtu)
------------------------------------------------------------------------
Domtar Ashdown Paper Mill Power Boiler No. 2......                  0.44
------------------------------------------------------------------------

    (21) PM compliance dates for Domtar Ashdown Mill Power Boiler No.
2. The owner or operator of the power boiler shall comply with the PM
emission limit listed in paragraph (c)(20) of this section as of the
effective date of this rule.
    (22) PM compliance determination for Domtar Ashdown Paper Mill
Power Boiler No.2. Compliance with the PM emission limit listed in
paragraph (c)(20) of this section shall be determined by maintaining
the 30-day rolling average wet scrubber pressure drop and the 30-day
rolling average wet scrubber liquid flow rate at or above the lowest
one-hour average pressure drop and the lowest one-hour average liquid
flow rate, respectively, measured during the most recent performance
test demonstrating compliance with the PM emission limit according to
40 CFR 63.7530(b) and Table 7 to subpart DDDDD of part 63. The pressure
drop and liquid flow rate monitoring system data shall be collected
according to 40 CFR 63.7525 and 63.7535; data shall be reduced to 30-
day rolling averages; and the 30-day rolling average pressure drop and
liquid flow-rate shall be maintained at or above the operating limits
established during the performance test according to 40 CFR 63.7530(b).
    (23) Emissions limitations for Entergy Independence Units 1 and 2.
The individual emission limits for each unit shall be as listed in the
following table in pounds per million British thermal units (lb/MMBtu)
as averaged over a rolling 30 boiler-operating-day period. EPA is
taking comment on two possible options. Under Option 1, the
SO2 and a NOX emission limits as listed in the
following table shall apply to each unit. Under Option 2, only the
SO2 emission limit as listed in the following table shall
apply to each unit. EPA expects only to finalize one of these options.

----------------------------------------------------------------------------------------------------------------
Unit                                                                    SO2 Emission limit    NOX Emission limit
                                                                                (lb/MMBtu)            (lb/MMBtu)
----------------------------------------------------------------------------------------------------------------
Option 1.............................  Entergy Independence Unit 1                    0.06                  0.15
                                        and 2.
Option 2.............................  Entergy Independence Unit 1                    0.06  ....................
                                        and 2.
----------------------------------------------------------------------------------------------------------------

    (24) Compliance dates for Entergy Independence Units 1 and 2. The
owner or operator of each unit shall comply with the SO2
emission limit in paragraph (c)(23) of this section within 5 years of
the effective date of this rule and the NOX emission limit
within 3 years of the effective date of this rule.
    (25) Compliance determination for Entergy Independence Units 1 and
2. (i) For each unit, SO2 and NOX emissions for
each calendar day shall be determined by summing the hourly emissions
measured in pounds of SO2 or pounds of NOX. For
each unit, heat input for each boiler-operating-day shall be determined
by adding together all hourly heat inputs, in millions of BTU. Each
boiler-operating-day of the thirty-day rolling average for a unit shall
be determined by adding together the pounds of SO2 or
NOX from that day and the preceding 29 boiler-operating-days
and dividing the total pounds of SO2 or NOX by
the sum of the heat input during the same 30 boiler-operating-day
period. The result shall be the 30 boiler-operating-day rolling average
in terms of lb/MMBtu emissions of SO2 or NOX. If
a valid SO2 or NOX pounds per hour or heat input
is not available for any hour for a unit, that heat input and
SO2 or NOX pounds per hour shall not be used in
the calculation of the applicable 30 boiler-operating-day rolling
average.
    (ii) The owner or operator shall continue to maintain and operate a
CEMS for SO2 and NOX on the units listed in
paragraph (c)(23) of this section in accordance with 40 CFR 60.8 and
60.13(e), (f), and (h), and appendix B of part 60. The owner or
operator shall comply with the quality assurance procedures for CEMS
found in 40 CFR part 75. Compliance with the emission limits for
SO2 and NOX shall be determined by using data
from a CEMS.

    (iii) Continuous emissions monitoring shall apply during all
periods of operation of the units listed in paragraph (c)(23) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
SO2 and NOX and diluent gas shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period. 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. When valid SO2 or NOX
pounds per hour emission data 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 to provide emission data for a
minimum of 18 hours in each 24 hour period and at least 22 out of 30
successive boiler operating days.
    (26) Reporting and recordkeeping requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required under paragraph
(c) of this section shall be submitted, unless instructed otherwise, to
the Director, Multimedia Planning and Permitting Division, U.S.
Environmental Protection Agency, Region 6, to the attention of Mail
Code: 6PD, at 1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733.
For each unit subject to the emissions limitation under paragraph (c)
of this section, the owner or operator shall comply with the following
requirements:
    (i) For each emissions limit under paragraph (c) of this section
where compliance shall be determined by using data from a CEMS, comply
with the notification, reporting, and recordkeeping requirements for
CEMS compliance monitoring in 40 CFR 60.7(c) and (d).
    (ii) For each day, provide the total SO2 emitted that
day by AEP Flint Creek Unit 1, Entergy White Bluff Units 1 and 2,
Domtar Ashdown Mill Power Boilers No. 1 and 2, and Entergy Independence
Units 1 and 2. For each day, provide the total NOX emitted
that day by AECC Bailey Unit 1, AECC McClellan Unit 1, AEP Flint Creek
Unit 1, Entergy White Bluff Units 1 and 2, Entergy Lake Catherine Unit
4, Domtar Ashdown Mill Power Boiler No. 2, and Entergy Independence
Units 1 and 2. For any hours on any unit or power boiler where data for
hourly pounds or heat input is missing, identify the unit number and
monitoring device that did not produce valid data that caused the
missing hour.
    (27) Equipment operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
    (28) Enforcement. (i) Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation of any standard or applicable
emission limit in the plan.
    (ii) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
    (d) Measures addressing partial disapproval of portion of
Interstate Visibility Transport SIP for the 1997 8-hour ozone and
PM2.5 NAAQS. (1) The deficiencies identified in EPA's
partial disapproval of the portion of the SIP pertaining to adequate
provisions to prohibit emissions in Arkansas from interfering with
measures required in another state to protect visibility, submitted on
March 28, 2008, and supplemented on September 27, 2011 are satisfied by
Sec.  52.173.
    (2) [Reserved]

[FR Doc. 2015-06726 Filed 4-3-15; 11:15 am]
 BILLING CODE 6560-50-P