not burned fuel oil since prior to the 2001-2003 baseline period,
currently does not burn fuel oil, and that Entergy does not project to
burn fuel oil at the unit in the foreseeable future. Therefore,
Entergy's analysis \66\ addresses BART for the natural gas firing
scenario and does not consider emissions from fuel oil firing.
Entergy's analysis states that if conditions change such that it
becomes economic to burn fuel oil, the facility will submit a BART five
factor analysis for the fuel oil firing scenario to the State to be
submitted to us as a SIP revision, and that fuel oil combustion will
not take place until final EPA approval of BART for the fuel oil firing
scenario. We concur with this commitment.\67\ Before fuel oil firing is
allowed to take place at Lake Catherine Unit 4, revised BART
determinations must be promulgated for all pollutants for the fuel oil
firing scenario through a FIP and/or through our action upon and
approval of revised BART

determinations submitted by the State as a SIP revision. We approved
Arkansas' BART determinations for Lake Catherine Unit 4 for
SO2 and PM for the natural gas firing scenario in our March
12, 2012 final action (77 FR 14604). Therefore, the only BART
determination that remains to be addressed for the natural gas firing
scenario is NOX BART.
---------------------------------------------------------------------------

    \65\ See ``Revised BART Five Factor Analysis Lake Catherine
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated
May 2014, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc. A copy of this BART analysis is found in the
docket for our proposed rulemaking.
    \66\ See ``Revised BART Five Factor Analysis Lake Catherine
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated
May 2014, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc. A copy of this BART analysis is found in the
docket for our proposed rulemaking.
    \67\ As stated in the regulatory text for this proposed
rulemaking, if Lake Catherine Unit 4 decides to begin burning fuel
oil, we will complete a BART analysis for each pollutant for the
fuel oil firing scenario after receiving notification that the
source will begin burning fuel oil and we will revise the FIP as
necessary in accordance with Regional Haze Rule requirements,
including the BART provisions in 40 CFR 51.308(e). Alternatively, if
the State submits a SIP revision with BART determinations for the
fuel oil firing scenario, we will take action on the State's
submittal.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for Lake
Catherine Unit 4. The SO2 and NOX baseline
emission rates are the highest actual 24-hour emission rates based on
CAMD data from 2001-2003 for natural gas burning. The PM10
emission rate reflects the breakdown of the filterable and condensable
PM10 determined from AP-42 Table 1.4-2 Combustion of Natural
Gas.

                          Table 39--Entergy Lake Catherine Unit 4 (Natural Gas Firing): Baseline Maximum 24-Hour Emission Rates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           SO2 (lb/    NOX (lb/   Total PM10   SO4 (lb/    PMc (lb/    PMf (lb/    SOA (lb/
                         Source                               hr)         hr)       (lb/hr)       hr)         hr)         hr)         hr)     EC (lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 4..................................................        3.1     2,456.4        44.3         1.5         0.0         0.0        31.8        11.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy modeled the baseline emission rates using the CALPUFF
dispersion model to determine the baseline visibility impairment
attributable to Lake Catherine Unit 4 at the four Class I areas
impacted by emissions from BART sources in Arkansas. These Class I
areas are the Caney Creek Wilderness Area, Upper Buffalo Wilderness
Area, Hercules-Glades Wilderness Area, and Mingo National Wildlife
Refuge. The baseline (i.e., existing) visibility impairment
attributable to the source at each Class I area is summarized in the
table below.

   Table 40--Baseline Visibility Impairment Attributable to Entergy Lake Catherine Unit 4--Natural Gas Firing
                                                   [2001-2003]
----------------------------------------------------------------------------------------------------------------
                                                                                Hercules-
                      Unit                          Caney Creek    Upper Buffalo      Glades           Mingo
----------------------------------------------------------------------------------------------------------------
Unit 4 (SN-01):
    Maximum ([Delta]dv).........................           3.480           2.044           1.016           0.763
    98th Percentile ([Delta]dv).................           1.371           0.489           0.387           0.429
----------------------------------------------------------------------------------------------------------------

    a. Proposed NOX BART Analysis and Determination. Entergy identified
all available control technologies, eliminated options that are not
technically feasible, and evaluated the control effectiveness of the
remaining control options for Lake Catherine Unit 4. Each technically
feasible control option was then evaluated in terms of a five factor
BART analysis.
    For NOX BART, the Entergy BART analysis evaluated both
combustion and post-combustion controls. The combustion controls
evaluated consisted of Burners out of Service (BOOS), FGR, SOFA, and
LNB. The post-combustion controls evaluated consisted of SCR and SNCR.
In its evaluation, Entergy noted that SNCR combined with LNB/SOFA was
being evaluated as a control option for Lake Catherine Unit 4, but SNCR
is not adaptable to all gas-fired boilers. All other available
NOX control options were identified as technically feasible.
    The baseline NOX emission rate Entergy used in the
analysis is 0.48 lb/MMBtu. Entergy relied on literature control ranges
and efficiencies and vendor estimates in arriving at the expected
controlled emission rates for Lake Catherine Unit 4. BOOS is a staged
combustion technique in which fuel is introduced through operational
burners in the lower furnace zone to create fuel-rich conditions, while
not introducing fuel to other burners. The removal of fuel from certain
zones reduces the temperature and the production of thermal
NOX. Additional air is then supplied to the non-operational
burners to complete combustion. Based on a NOX control study
developed by Sargent & Lundy on behalf of Entergy (Sargent & Lundy
NOX Control Study), the estimated controlled NOX
level for Unit 4 while operating BOOS at maximum load is 0.24 lb/
MMBtu.\68\ Based on the level of control expected to be achieved by
BOOS and the expected utilization levels at Unit 4, Entergy believes
that an emission rate of 0.22 lb/MMBtu is achievable on a 30 boiler-
operating-day rolling average basis. Entergy estimated the controlled
NOX level for Unit 4 operating with FGR to be 0.19 lb/MMBtu.
Entergy estimated that when operated without additional controls, SOFA
results in NOX emissions for gas fired boilers of 0.2--0.4
lb/MMBtu. When operated without additional controls, the estimated
controlled NOX emission rate for gas fired boilers operating
with LNB is approximately 0.25 lb/MMBtu, and when combined with SOFA,
the estimated controlled NOX emission rate is 0.19 lb/MMBtu.
When SNCR is combined with LNB/SOFA it is estimated that the controlled
NOX emission rate is 0.14 lb/MMBtu, and when SCR is combined
with LNB/SOFA it is estimated that the controlled NOX
emission rate is 0.03 lb/MMBtu.
---------------------------------------------------------------------------

    \68\ See ``NOX Control Technology Cost and
Performance Study,'' Final Report, Rev. 4, dated May 16, 2013,
prepared by Sargent & Lundy. A copy of this report is included as
Attachment D to Entergy's BART Five Factor Analysis for Lake
Catherine Unit 4, which can be found in the docket for this proposed
rulemaking.
---------------------------------------------------------------------------

    In its evaluation, Entergy noted that the Sargent & Lundy
NOX Control Study estimated that FGR would result in the
same controlled emission level as LNB/SOFA, but at a higher cost.
Therefore, Entergy's evaluation did not further consider FGR. The
remainder of the analysis focused on four control scenarios: (1) BOOS;
(2) LNB/SOFA; (3) the combination of LNB/SOFA + SNCR; and (4) the
combination of LNB/SOFA + SCR. Entergy estimated the capital costs,
operating costs, and cost- effectiveness of these four control
scenarios based on cost estimates provided by Sargent & Lundy.\69\ The
capital cost of each NOX control was annualized over a 30-
year period and

then added to the annual operating costs to obtain the total annualized
costs.\70\ The annual emissions reductions associated with each
NOX control option were determined by subtracting the
estimated controlled annual emission rate from the baseline annual
emission rate. The baseline annual emission rate was calculated using
the baseline emission level of 0.48 lb/MMBtu and an annual heat input
reflecting a 10% capacity factor.\71\ Entergy assumed a 10% capacity
factor because the annual capacity factor of the unit during each of
the years from 2003-2011 was under 10%, and Entergy anticipates that
future annual capacity factors are expected to be comparable to those
experienced by the unit in 2003-2011. We agree that assuming a 10%
capacity factor is consistent with the BART Guidelines, which provide
that the baseline emission rate should represent a realistic depiction
of anticipated annual emissions for the source.\72\
---------------------------------------------------------------------------

    \69\ The capital and operating cost estimates for each control
option are found in Appendix A to Entergy's BART Five Factor
Analysis for Lake Catherine Unit 4, which can be found in the docket
for this proposed rulemaking.
    \70\ Based on Entergy's evaluation, it is anticipated that BOOS
can be implemented at Unit 4 without any capital expenditures, but
there are one-time costs associated with BOOS implementation. To
provide an ``apples-to-apples'' comparison with the other
NOX control options, these one-time additional costs were
treated as if they were a capital expenditure in calculating the
cost effectiveness.
    \71\ The annual heat input reflecting a 10% annual capacity
factor is 5,124,600 MMBtu/yr (5,850 MMBtu/hr * 8760 hrs/yr * 10% =
5,124,600 MMBtu/yr).
    \72\ 40 CFR Appendix Y to Part 51--Guidelines for BART
Determinations Under the Regional Haze Rule, section IV.D.4.d.
---------------------------------------------------------------------------

    The controlled annual emission rates were based on the lb/MMBtu
levels believed to be achievable from the control technologies
multiplied by the annual heat input. The average cost-effectiveness of
NOX controls was calculated by dividing the total annual
cost of each control option by the estimated annual NOX
emissions reductions. The incremental cost-effectiveness of controls
when compared to BOOS was also calculated. The table below summarizes
the cost of NOX controls for Lake Catherine Unit 4. Based on
Entergy's analysis, the average cost-effectiveness of BOOS at a
NOX controlled emission rate of 0.22 lb/MMBtu is estimated
to be $138 per ton of NOX removed, while the average cost-
effectiveness of LNB/SOFA is estimated to be $1,596 per ton of
NOX removed. The average cost-effectiveness of a combination
of LNB/SOFA + SNCR is estimated to be $3,827 per ton of NOX
removed, while the average cost-effectiveness of the combination of
LNB/SOFA + SCR is estimated to be $6,223 per ton of NOX
removed.
    We disagree with two aspects of Entergy's cost analysis.\73\ First,
Entergy's cost estimates for LNB/SOFA, LNB/SOFA + SNCR, and LNB/SOFA +
SCR include capital suspense as a line item under the capital costs.
However, we do not believe capital suspense should be included in the
cost analysis because those costs have not been documented by Entergy
and do not appear to be valid costs under the Control Cost Manual
methodology. Second, Entergy's cost estimates for these controls also
include Allowance for Funds Used During Construction (AFUDC). AFUDC is
the cost of capital that is incurred to finance a project during the
construction period, and is not a valid cost under the methodology in
the EPA Control Cost Manual. The exclusion of capital suspense and
AFUDC from the capital cost estimates results in lower total annual
costs and improved average cost-effectiveness (i.e., less dollars per
NOX ton removed) for the aforementioned NOX
control options compared to what is estimated in Entergy's evaluation.
In the table below, we have revised the cost-effectiveness of
NOX controls for Unit 4 to reflect our adjustments to
Entergy's cost estimates.\74\
---------------------------------------------------------------------------

    \73\ See ``Revised BART Five Factor Analysis Lake Catherine
Steam Electric Station Malvern, Arkansas (AFIN 30-00011),'' dated
May 2014, prepared by Trinity Consultants Inc. in conjunction with
Entergy Services Inc. Entergy's NOX control cost
estimates are found in Appendices A and D of the BART analysis. A
copy of the BART analysis, including the appendices, is found in the
docket for our proposed rulemaking.
    \74\ See the spreadsheet titled ``EPA NOX Control
Cost revisions_Lake Catherine.xlsx.'' A copy of this spreadsheet is
found in the docket for our proposed rulemaking.

                                            Table 41--Summary of NOX Control Costs for Lake Catherine Unit 4
                                                                  [Natural gas firing]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Baseline     Controlled    Controlled      Annual                                                 Incremental
                                          emission      emission      emission      emissions   Capital cost  Total annual   Average cost       cost
                                         rate  (NOX    level  (lb/   rate  (NOX     reduction        ($)      cost  ($/yr)  effectiveness  effectiveness
                                            tpy)         MMBtu)         tpy)        (NOX tpy)                                   ($/ton)        ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
BOOS..................................         1,236          0.22           564           673       893,000        92,964            138
LNB/SOFA..............................         1,236          0.19           495           742    10,508,863     1,075,905          1,450         14,246
LNB/SOFA/SNCR.........................         1,236          0.14           371           865    26,015,863     3,047,525          3,523         16,029
LNB/SOFA/SCR..........................         1,236          0.03            77          1159    70,370,863     6,506,935          5,614         11,767
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Entergy did not identify any energy or non-air quality
environmental impacts associated with the use of BOOS, LNB, or SOFA. As
for SCR and SNCR, we are not aware of any unusual circumstances at the
facility that could create non-air quality environmental impacts
associated with the operation of these controls greater than
experienced elsewhere and that may therefore provide a basis for their
elimination as BART (40 CFR part 51, Appendix Y, section IV.D.4.i.2.).
Therefore, we do not believe there are any energy or non-air quality
environmental impacts associated with the operation of NOX
controls at Entergy Lake Catherine Unit 4 that would affect our
proposed BART determination.
    Lake Catherine Unit 4 is not currently equipped with any
NOX pollution control equipment. The baseline emission rates
used in the cost calculations and visibility modeling reflects this.
    Entergy assessed the visibility improvement associated with
NOX controls by modeling the NOX emission rates
associated with each control option using CALPUFF, and then comparing
the visibility impairment associated with the baseline emission rate to
the visibility impairment associated with the controlled emission rates
as measured by the 98th percentile modeled visibility impact. The table
below shows a comparison of the baseline (i.e., existing) visibility
impacts and the visibility impacts associated with NOX
controls.

               Table 42--Entergy Lake Catherine Unit 4: Summary of 98th Percentile Visibility Impacts and Improvement due to NOX Controls
                                                                  [Natural gas firing]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         BOOS                     LNB/SOFA               LNB/SOFA + SNCR             LNB/SOFA + SCR
                                             -----------------------------------------------------------------------------------------------------------
                                   Baseline                 Visibility                 Visibility                 Visibility                 Visibility
          Class I area            visibility   Visibility   improvement   Visibility   improvement   Visibility   improvement   Visibility   improvement
                                    impact       impact        from         impact        from         impact        from         impact        from
                                 ([Delta]dv)  ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline    ([Delta]dv)    baseline
                                                            ([Delta]dv)                ([Delta]dv)                ([Delta]dv)                ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek....................       1.371        0.775          0.596       0.683          0.688       0.529          0.842       0.163          1.208
Upper Buffalo..................       0.532        0.284          0.248       0.25           0.282       0.193          0.339       0.057          0.475
Hercules-Glades................       0.387        0.212          0.175       0.185          0.202       0.141          0.246       0.043          0.344
Mingo..........................       0.429        0.233          0.196       0.204          0.225       0.154          0.275       0.042          0.387
Cumulative Visibility            ...........  ...........         1.215  ...........         1.397  ...........         1.702  ...........         2.414
 Improvement ([Delta]dv).......
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of BOOS
is projected to result in visibility improvement of up to 0.596 dv at
any single Class I area (based on the 98th percentile modeled
visibility impacts), while LNB/SOFA is projected to result in
visibility improvement of up to 0.688 dv. The installation and
operation of the combination of LNB/SOFA + SNCR is projected to result
in visibility improvement of up to 0.842 dv at any single Class I area,
while the combination of LNB/SOFA + SCR is projected to result in
visibility improvement of up to 1.208 dv. The installation and
operation of LNB/SOFA is projected to result in 0.092 dv of incremental
visibility benefit over BOOS at Caney Creek, and much lower incremental
visibility benefit over BOOS at the other Class I areas. The
combination of LNB/SOFA + SNCR is projected to result in 0.154 dv of
incremental visibility benefit over LNB/SOFA at Caney Creek, and 0.057
dv or less incremental visibility benefit at the other affected Class I
areas. The combination of LNB/SOFA + SCR is projected to result in
0.366 dv of incremental visibility benefit over LNB/SOFA + SNCR at
Caney Creek, 0.136 dv at Upper Buffalo, 0.098 [Delta]dv at Hercules-
Glades, and 0.112 dv at Mingo.
    Our Proposed NOX BART Determination: Taking into consideration the
five factors, we are proposing to determine that NOX BART
for Lake Catherine Unit 4 for the natural gas firing scenario is an
emission limit of 0.22 lb/MMBtu on a 30 boiler-operating-day rolling
average based on the installation and operation of BOOS. The operation
of BOOS is projected to result in visibility improvement ranging from
0.175 to 0.596 dv at each affected Class I area (98th percentile
basis). The cumulative visibility improvement across the four affected
Class I areas is projected to be 1.215 dv. The operation of BOOS is
estimated to have an average cost-effectiveness of $138 per ton of
NOX removed, which we consider to be very cost-effective. By
comparison, the installation and operation of LNB/SOFA is estimated to
have an average cost-effectiveness of $1,450 per ton of NOX
removed, which is still very cost-effective. However, the incremental
cost-effectiveness of LNB/SOFA over BOOS is $14,246 per ton of
NOX ton removed, while the incremental visibility benefits
are only 0.027 to 0.092 dv (depending on the Class I area). As
discussed in the preceding paragraph, the operation of a combination of
LNB/SOFA + SNCR is projected to result in visibility improvement over
the baseline ranging from 0.246 to 0.842 dv at each affected Class I
area and an incremental visibility improvement over LNB/SOFA ranging
from 0.05 to 0.154 dv at each Class I area. However, the combination of
LNB/SOFA + SNCR has an average cost-effectiveness of $3,523 per ton of
NOX removed and an incremental cost-effectiveness compared
to LNB/SOFA of $16,029 per ton of NOX removed. We believe
that the high incremental costs of the combination of LNB/SOFA + SNCR
when compared to LNB/SOFA do not justify the amount of incremental
visibility benefit projected at the affected Class I areas. The
operation of a combination of LNB/SOFA + SCR is projected to result in
considerable visibility improvement over the baseline, ranging from
0.344 to 1.208 dv at each affected Class I area. The incremental
visibility benefit of the combination of LNB/SOFA + SCR over LNB/SOFA +
SNCR ranges from 0.098 to 0.366 dv at each Class I area. However, the
combination of LNB/SOFA + SCR has an average cost-effectiveness of
$5,614 per ton of NOX removed and an incremental cost-
effectiveness (compared to the combination of LNB/SOFA + SNCR) of
$11,767 per ton of NOX removed. While the incremental
visibility benefit is considerable, we do not consider the average and
the incremental cost-effectiveness values of the combination of LNB/
SOFA + SCR to be cost-effective. Therefore, we are proposing to
determine that NOX BART for Lake Catherine Unit 4 for the
natural gas firing scenario is an emission limit of 0.22 lb/MMBtu on a
30 boiler-operating-day rolling average based on the installation and
operation of BOOS. We are proposing to require compliance with this
requirement no later than 3 years from the effective date of the final
rule, consistent with our regional haze regulations.\75\ We are
proposing to require that compliance be demonstrated using the unit's
existing CEMS. We are inviting public comment specifically on whether
this proposed NOX emission limit is appropriate or whether
an emission limit based on more stringent NOX controls would
be appropriate. We are also proposing regulatory text that includes
monitoring, reporting, and recordkeeping requirements associated with
this emission limit.
---------------------------------------------------------------------------

    \75\ 40 CFR 51.308(e)(1)(iv).
---------------------------------------------------------------------------

6. Domtar Ashdown Paper Mill
    The Domtar Ashdown Paper Mill Power Boilers No. 1 and 2 are subject
to BART. As mentioned previously, we disapproved Arkansas' BART
determinations for SO2 and NOX for Power Boiler
No. 1 and the BART determination for SO2, NOX,
and PM for the No. 2 Power Boiler in our March 12, 2012 final action
(77 FR 14604). The No. 1 Power Boiler has a heat input rating of 580
MMBtu/hr and an average steam generation rate of approximately 120,000
lb/hr. The No. 1 Power Boiler combusts primarily bark, but is also
permitted to burn wood waste, tire-

derived fuel (TDF), municipal yard waste, pelletized paper fuel (PPF),
fuel oil, reprocessed fuel oil, and natural gas. It is equipped with a
traveling grate, a combustion air system, and a wet ESP. The No. 2
Power Boiler has a heat input rating of 820 MMBtu/hr and an average
steam generation rate of approximately 600,000 lb/hr. The No. 2 Power
Boiler combusts primarily pulverized bituminous coal, but is also
permitted to burn bark, PPF, TDF, municipal yard waste, fuel oil, used
oil, natural gas, petroleum coke, and reprocessed fuel oil. It is
equipped with a traveling grate, combustion air system including OFA,
multiclones for particulate removal, and two venturi scrubbers in
parallel for removal of remaining particulates and SO2.
Domtar hired a consultant to perform a BART five-factor analysis for
the Domtar Ashdown Mill Power Boilers No. 1 and 2 (Domtar's 2014 BART
analysis).\76\ In this proposal, we also refer to certain parts of the
Domtar BART evaluation submitted by the State in the 2008 Arkansas RH
SIP, which we are hereafter referring to as the ``2006/2007 Domtar BART
analysis.'' \77\ Although we already took action on that SIP submittal,
we reference the 2006/2007 Domtar BART analysis as it contains the best
available information we have related to certain NOX
controls for Power Boilers No. 1 and 2.
---------------------------------------------------------------------------

    \76\ See ``Supplemental BART Determination Information Domtar
A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated June 28,
2013 and revised on May 16, 2014, prepared by Trinity Consultants
Inc. in conjunction with Domtar A.W. LLC. A copy of this BART
analysis is found in the docket for our proposed rulemaking.
    \77\ See ``Best Available Retrofit Technology Determination
Domtar Industries Inc., Ashdown Mill (AFIN 41-00002),'' originally
dated October 31, 2006 and revised on March 26, 2007, prepared by
Trinity Consultants Inc. This BART analysis is part of the 2008
Arkansas RH SIP, upon which EPA took final action on March 12, 2012
(77 FR 14604). A copy of this BART analysis is found in the docket
for this proposed rulemaking.
---------------------------------------------------------------------------

    The table below summarizes the baseline emission rates for Power
Boilers No. 1 and 2. The SO2 baseline emission rate for
Power Boiler No. 1 used in Domtar's 2014 BART analysis is the highest
actual 24-hour emission rate estimated using maximum 24-hour fuel usage
rates during 2009-2011 and sulfur content values for each fuel
type.\78\ The 2009-2011 period was used as the baseline in Domtar's
evaluation for Power Boiler No. 1 because a wet ESP was installed on
Power Boiler No. 1 in 2007 to meet the Maximum Achievable Control
Technology (MACT) standards under CAA section 112, resulting in a
reduction in PM and SO2 emissions from Power Boiler No. 1.
Therefore, we believe that the 2009-2011 period is more representative
of the boiler's current emissions than 2001-2003. We believe the use of
2009-2011 as the new baseline period for Power Boiler No. 1 is
consistent with the BART Guidelines, which provide that the baseline
emissions rate should represent a realistic depiction of anticipated
annual emissions for the source.\79\ The NOX and PM baseline
emission rates used for Power Boiler No. 1 are the highest actual 24-
hour emission rates estimated using the maximum heat input from 2009-
2011 and emission factors developed from the analysis of stack testing
the facility had previously conducted. For Power Boiler No. 2, the
baseline emission rates are the highest actual 24-hour emission rates
based on a combination of 2001-2003 CEMS data, source-specific stack
testing results, and emission factors from AP-42.
---------------------------------------------------------------------------

    \78\ In Domtar's 2014 BART analysis, 2009-2011 was used as the
baseline period for Power Boiler No. 1 because a wet ESP was
installed on Power Boiler No. 1 in 2007. The installation of the wet
ESP resulted in a reduction in PM and SO2 emissions from
Power Boiler No. 1. Therefore, 2009-2011 is more representative of
the boiler's emissions than 2001-2003.
    \79\ 40 CFR part 51, Appendix Y, section IV.D.4.c.

                     Table 43--Domtar Ashdown Mill: Baseline Maximum 24-Hour Emission Rates
----------------------------------------------------------------------------------------------------------------
                                                         NOX Emissions (lb/ SO2 Emissions (lb/      PM10/PMf
                  Subject to BART unit                          hr)                hr)         Emissions (lb/hr)
----------------------------------------------------------------------------------------------------------------
Power Boiler No. 1.....................................              207.4               21.0               30.4
Power Boiler No. 2.....................................              526.8              788.2               81.6
----------------------------------------------------------------------------------------------------------------

    Domtar modeled the baseline emission rates using the CALPUFF
dispersion model to determine the baseline visibility impairment
attributable to the Domtar Ashdown Mill's Power Boilers No. 1 and 2 at
the four Class I areas impacted by emissions from BART sources in
Arkansas. These Class I areas are the Caney Creek Wilderness Area,
Upper Buffalo Wilderness Area, Hercules-Glades Wilderness Area, and
Mingo National Wildlife Refuge. The baseline visibility impairment
attributable to the source at each Class I area is summarized in the
table below.

                Table 44--Baseline Visibility Impairment Attributable to the Domtar Ashdown Mill
----------------------------------------------------------------------------------------------------------------
                                                                                Hercules-
                  Emission unit                     Caney Creek    Upper Buffalo      Glades           Mingo
----------------------------------------------------------------------------------------------------------------
Power Boiler No. 1:
    Maximum ([Delta]dv).........................           0.476           0.090           0.077           0.060
    98th Percentile ([Delta]dv).................           0.335           0.038           0.020           0.014
Power Boiler No. 2:
    Maximum ([Delta]dv).........................           1.603           0.381           0.329           0.246
    98th Percentile ([Delta]dv).................           0.844           0.146           0.105           0.065
----------------------------------------------------------------------------------------------------------------

    a. Proposed SO2 BART Analysis and Determination for Power Boiler
No. 1. The table above shows that the baseline visibility impairment
attributable to Power Boiler No. 1 is relatively low based on the 98th
percentile visibility impacts, ranging from 0.014-0.335 dv at each
Class I area. An examination of the species contribution to the 98th
percentile visibility impacts shows that SO2 emissions
contribute a very small portion of the visibility impairment

attributable to Power Boiler No. 1 (see the table below). The
SO4 species contributes only 2.23--4.03% of the visibility
impairment attributable to Power Boiler No. 1 at the modeled Class I
areas. We also note that Power Boiler No. 1 combusts primarily bark,
which results in very low SO2 emissions due to the low
sulfur content of bark.

                      Table 45--Baseline Visibility Impairment and Species Contribution for Domtar Ashdown Mill--Power Boiler No. 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               98th         Species contribution to 98th percentile visibility impacts
                                                                            Percentile   ---------------------------------------------------------------
              Emissions unit                        Class I area            visibility         98th            98th            98th            98th
                                                                           impacts (dv)    Percentile %    Percentile %    Percentile %    Percentile %
                                                                               \80\             SO4             NO3            PM10             NO2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Power Boiler No. 1........................  Caney Creek.................           0.335            2.23           85.26            6.68            5.83
                                            Upper Buffalo...............           0.038            2.75           85.89            8.03            3.32
                                            Hercules-Glades.............           0.020            2.70           91.82            3.94            1.55
                                            Mingo.......................           0.014            4.03           90.06            5.13            0.78
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As noted above, we believe that the BART Rule provides that states,
or EPA in this case, can adopt a more streamlined approach to making
BART determinations where appropriate.\81\ Considering the very low
baseline visibility impairment that is due to SO2 emissions
from Power Boiler No. 1 and the fact that the boiler combusts primarily
bark, which has a low sulfur content, we believe that any visibility
improvement that could be achieved as a result of emissions reductions
associated with the installation and operation of SO2
controls would be negligible, and that the cost of those controls could
not be justified. Therefore, we are proposing that the SO2
baseline emission rate of 21.0 lb/hr satisfies SO2 BART for
Power Boiler No. 1. We are proposing this SO2 emission rate
on a 30 boiler-operating-day averaging basis, where in this particular
case 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. Power Boiler No. 1 is
not currently equipped with a CEMS. To demonstrate compliance with this
SO2 BART emission limit we are proposing to require the
facility to use a site-specific curve equation,\82\ provided to us by
the facility, to calculate the SO2 emissions from Power
Boiler No. 1 when combusting bark, and to confirm the curve equation
using stack testing.\83\ We are also proposing that to calculate the
SO2 emissions from fuel oil combustion, the facility must
assume that the SO2 inlet is equal to the SO2
being emitted at the stack. We are inviting public comment on whether
this method of demonstrating compliance with the proposed BART emission
limit is appropriate. Since this proposed BART determination does not
require the installation of control equipment, we are proposing that
this SO2 emission limit be complied with by the effective
date of the final action.
---------------------------------------------------------------------------

    \80\ The visibility impact shown represents the highest 98th
percentile value among the three modeled years.
    \81\ 70 FR 39116.
    \82\ The curve equation is Y = 0.4005 * X - 0.2645, where Y =
pounds of sulfur emitted per ton dry fuel feed to the boiler and X =
pounds of sulfur input per ton of dry bark. The purpose of this
equation is to factor in the degree of SO2 scrubbing
provided by the combustion of bark.
    \83\ Background information and an explanation of the site
specific curve equation provided by Domtar can be found in the
documents titled ``Site Specific Curve Equation Background_Domtar PB
No1,'' and ``1PB SO2 Emissions from Curve.'' Copies of
these documents can be found in the docket for this proposed
rulemaking.
---------------------------------------------------------------------------

    b. Proposed NOX BART Analysis and Determination for Power Boiler
No. 1. For NOX BART, Domtar's 2014 BART analysis evaluated
SNCR and Methane de-NOX (MdN). In the 2006/2007 Domtar BART
analysis, which was submitted in the 2008 Arkansas RH SIP, other
NOX controls were also evaluated but found by Arkansas to be
either already in use or not technically feasible for use at Power
Boiler No. 1. Fuel blending, boiler operational modifications, and
boiler tuning/optimization are already in use at the source, while FGR,
LNB, Ultra Low NOX Burners (ULNB), OFA, and SCR were
determined to be technically infeasible for use at Power Boiler No. 1.
Domtar did not further evaluate these NOX controls in its
2014 BART analysis for Power Boiler No. 1, focusing instead on SNCR and
MdN.
    MdN utilizes the injection of natural gas together with
recirculated flue gases to create an oxygen-rich zone above the
combustion grate. Air is then injected at a higher furnace elevation to
burn the combustibles. In response to comments provided by us regarding
Domtar's 2014 BART analysis, Domtar stated that discussions regarding
the technical infeasibility of MdN in the 2006/2007 Domtar BART
analysis, submitted as part of the 2008 Arkansas RH SIP, remain
correct.\84\ The 2006/2007 Domtar BART analysis submitted in the 2008
Arkansas RH SIP discussed that MdN has not been fully demonstrated for
this source type and incorporates FGR, which is technically infeasible
for use at Power Boiler No. 1. Domtar also stated it recently completed
additional research and found that since the 2006/2007 Domtar BART
analysis, MdN has not been placed into operation in power boilers at
paper mills or any comparable source types. We are also not aware of
any power boilers at paper mills that operate MdN for NOX
control, and agree that this control can be considered technically
infeasible for use at Power Boiler No. 1 and do not further consider it
in this evaluation. Domtar also questioned the technical feasibility of
SNCR for bark fired boilers and boilers with high load swings such as
Power Boiler No. 1, but in response to our comments, SNCR was evaluated
for Power Boiler No. 1 in Domtar's 2014 BART analysis.
---------------------------------------------------------------------------

    \84\ See the document titled ``Domtar Responses to ADEQ
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 10. A copy
of this document can be found in the docket for our proposed
rulemaking.
---------------------------------------------------------------------------

    Domtar's 2014 BART analysis evaluated SNCR at removal efficiencies
of 20%, 32.5%, and 45% for Power Boiler No. 1. The estimated 32.5% and
45% removal efficiencies were based on equipment vendor estimates that
came from the vendor's proposal,\85\ which according to the facility,
is not an appropriations request level quote and

therefore needs further refinement.\86\ For example, Domtar's 2014 BART
analysis discusses that for a base loaded pulp mill boiler with steady
flue gas flow patterns and temperature distribution across the flue gas
pathway, SNCR can achieve a 45% removal efficiency. However, Power
Boiler No. 1 is not a base loaded boiler. Domtar's 2014 BART analysis
states that for pulp mill boilers with fluctuating loads (i.e., high
load swing), such as Power Boiler No. 1, SNCR is used primarily for
polishing purposes (i.e., < 20 to 30% NOX reduction) and it
is uncertain whether higher removal efficiencies are achievable on a
long-term basis. The facility believes that 20% removal efficiency,
which has been demonstrated at a similar bark fired power boiler at
another paper mill, is the most reasonable estimate of the removal
efficiency of SNCR for Power Boiler No. 1.
---------------------------------------------------------------------------

    \85\ Fuel Tech Proposal titled ``Domtar Paper Ashdown,
Arkansas--NOX Control Options, Power Boilers 1 and 2,''
dated June 29, 2012. A copy of the vendor proposal is included under
Appendix D to the ``Supplemental BART Determination Information
Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated
June 28, 2013 and revised on May 16, 2014, prepared by Trinity
Consultants Inc. in conjunction with Domtar A.W. LLC. A copy of this
BART analysis and its appendices is found in the docket for our
proposed rulemaking.
    \86\ See the document titled ``Domtar Responses to ADEQ
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 9. A copy
of this document can be found in the docket for our proposed
rulemaking.
---------------------------------------------------------------------------

    In Domtar's 2014 BART analysis, the capital costs, operating costs,
and cost-effectiveness of SNCR were calculated based on methods and
assumptions found in our Control Cost Manual, and supplemented with
mill-specific cost information for water, fuels, and ash disposal and
urea solution usage estimates from the equipment vendor. The capital
cost was annualized over a 30-year period and then added to the annual
operating cost to obtain the total annualized costs. The annual
emissions reductions associated with each NOX control option
were determined by subtracting the estimated controlled annual emission
rate from the baseline annual emission rate. The baseline annual
emissions used in the calculations are the uncontrolled actual
emissions from the 2009-2011 baseline period. The average cost-
effectiveness was calculated by dividing the total annual cost by the
estimated annual NOX emissions reductions. The table below
summarizes the cost of NOX controls for Power Boiler No. 1.

                                            Table 46--Summary of Cost of NOX Controls for Power Boiler No. 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Annual
                                         Baseline       NOX Control       emissions     Capital cost    Total annual    Average cost   Incremental cost-
       NOX Control  scenarios          emission rate   efficiency (%)  reduction (NOX        ($)         cost ($/yr)    effectiveness  effectiveness ($/
                                         (NOX tpy)                          tpy)                                           ($/ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR--20%...........................             440             20                88       2,152,365       1,118,178          12,700  .................
SNCR--32.5%.........................             440             32.5             143       2,423,587       1,144,103           7,996                471
SNCR--45%...........................             440             45               198       2,707,431       1,513,602           7,640              6,718
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Domtar's 2014 BART analysis did not identify any energy or non-air
quality environmental impacts associated with the use of SNCR. We are
not aware of any unusual circumstances at the facility that create
greater non-air quality environmental impacts than experienced
elsewhere that may provide a basis for the elimination of these control
options as BART (40 CFR part 51, Appendix Y, section IV.D.4.i.2.).
Therefore, we do not believe there are any energy or non-air quality
environmental impacts associated with the operation of NOX
controls at Power Boiler No. 1 that would affect our proposed BART
determination.
    Consideration of the presence of existing pollution control
technology at the source is reflected in the BART analysis in two ways:
First, in the consideration of available control technologies, and
second, in the development of baseline emission rates for use in cost
calculations and visibility modeling. Power Boiler No. 1 is currently
equipped with a combustion air system to optimize boiler combustion
efficiency, which has the co-benefit of reducing emissions. The
baseline emission rate used in the cost calculations and visibility
modeling reflects the use of the existing combustion air system.
    In the 2014 BART analysis, Domtar assessed the visibility
improvement associated with SNCR by modeling the NOX
emission rates associated with each control option using CALPUFF, and
then comparing the visibility impairment associated with the baseline
emission rate to the visibility impairment associated with the
controlled emission rates as measured by the 98th percentile modeled
visibility impact. The table below shows a comparison of the baseline
(i.e., existing) visibility impacts and the visibility impacts
associated with SNCR.

             Table 47--Domtar Ashdown Mill Power Boiler No. 1: Summary of the 98th Percentile Visibility Impacts and Improvement Due to SNCR
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            SNCR--20%                   SNCR--32.5%                   SNCR--45%
                                                        Baseline  --------------------------------------------------------------------------------------
                                                       visibility                 Visibility                   Visibility                   Visibility
                     Class I area                        impact     Visibility    improvement    Visibility    improvement    Visibility    improvement
                                                          (dv)        impact     from baseline     impact     from baseline     impact     from baseline
                                                                   ([Delta]dv)    ([Delta]dv)   ([Delta]dv)    ([Delta]dv)   ([Delta]dv)    ([Delta]dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..........................................       0.335       0.274            0.061       0.237            0.098       0.199            0.136
Upper Buffalo........................................       0.038       0.031            0.007       0.027            0.011       0.023            0.015
Hercules-Glades......................................       0.020       0.017            0.003       0.014            0.006       0.012            0.008
Mingo................................................       0.014       0.011            0.003       0.009            0.005       0.008            0.006
Cumulative Visibility Improvement ([Delta]dv)........  ..........  ...........           0.074  ...........            0.12  ...........           0.165
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of SNCR
is projected to result in visibility improvements of up to 0.136 dv at
any single Class I area when operated at 45% removal efficiency, 0.098
dv when operated at 32.5% removal efficiency, and 0.061 dv when
operated at 20%

removal efficiency (based on the 98th percentile modeled visibility
impacts).
    Our Proposed NOX BART Determination: Taking into consideration the
five factors, we are proposing to determine that NOX BART
for the Domtar Ashdown Mill Power Boiler No. 1 is an emission limit of
207.4 lb/hr on a 30 boiler-operating-day rolling average, where 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. This emission limit is based
on the boiler's NOX baseline emission rate and therefore
represents current operating conditions. MdN was determined to be not
technically feasible for use at Power Boiler No. 1 because it has not
been fully demonstrated for this source type and incorporates FGR,
which is technically infeasible for use at the boiler. The installation
and operation of SNCR is projected to result in some visibility
improvement at the Class I areas. As discussed in more detail above, we
concur with Domtar's position that 20% removal efficiency is the most
reasonable estimate of the level of NOX control SNCR can
achieve at Power Boiler No. 1. When operated at 20% removal efficiency,
SNCR is projected to result in visibility improvement of up to 0.061 dv
at any single Class I area and is estimated to cost $12,700 per ton of
NOX removed. We do not believe this high cost justifies the
modest visibility improvement projected from the installation and
operation of SNCR at 20% removal efficiency. Although there is
uncertainty as to whether SNCR can achieve a long term removal
efficiency of 45% or even 32.5% at Power Boiler No. 1, we believe that
the associated costs are also too high to justify the small projected
visibility benefits. Installation and operation of SNCR at a 45%
removal efficiency is projected to result in a visibility improvement
of up to 0.136 dv at any single Class I area and is estimated to cost
$7,640 per ton of NOX removed. The operation of SNCR at a
32.5% removal efficiency is projected to result in visibility
improvement of up to 0.098 dv at any single Class I area and is
estimated to cost $7,996 per ton of NOX removed. Therefore,
we are proposing to determine that NOX BART for Power Boiler
No. 1 is no additional control and are proposing that an emission limit
of 207.4 lb/hr on a 30 boiler-operating-day rolling average satisfies
NOX BART. In this particular case, we are defining boiler-
operating-day 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. Power Boiler No. 1 is not currently equipped with
a CEMS. To demonstrate compliance with this NOX BART
emission limit we are proposing to require annual stack testing. We are
inviting public comment on the appropriateness of this method for
demonstrating compliance with the NOX BART emission limit
for Power Boiler No. 1. Since this proposed BART determination does not
require the installation of control equipment, we are proposing that
this NOX emission limit be complied with by the effective
date of the final action. We are also proposing regulatory text that
includes monitoring, reporting, and recordkeeping requirements
associated with this proposed BART determination.
    c. Proposed SO2 BART Analysis and Determination for Power Boiler
No. 2. Power Boiler No. 2 is currently equipped with two venturi wet
scrubbers in parallel for removal of particulates and SO2.
Domtar's 2014 BART analysis evaluated upgrades to the existing venturi
wet scrubbers and new add-on spray scrubbers for Power Boiler No.
2.\87\ Domtar's analysis explains that it contracted with a vendor to
evaluate upgrades to the existing venturi scrubbers and provide a quote
for a new add-on spray scrubber system that would be installed
downstream of the existing venturi scrubbers.\88\ Domtar's analysis
states that the existing venturi scrubbers achieve an SO2
control efficiency of approximately 90% and notes that this is within
the normal range for the highest control efficiency achieved by
SO2 control technologies. Domtar's analysis indicates that
the upgrades it considered for the existing venturi scrubbers include:
(1) The elimination of bypass reheat, (2) the installation of liquid
distribution rings, (3) the installation of perforated trays, (4)
improvements to the auxiliary system requirement, and (5) a redesign of
spray header and nozzle configuration. Domtar's analysis states that
any additional control that could potentially be achieved from
implementation of such upgrades would be marginal, but the facility was
unable to quantify the potential additional control. Therefore, it was
determined that the installation of new add-on spray scrubbers to
operate downstream of the existing scrubbers was more feasible than any
upgrade option. The remainder of Domtar's analysis focused on the add-
on spray scrubber option. Based on the information provided to Domtar
by the vendor, the add-on spray scrubbers would utilize sodium
hydroxide (NaOH), bleach plant EO filtrate (i.e., bleaching filtrate),
and water as the scrubbing reagent. The add-on spray scrubbers are
estimated to achieve 90% control efficiency above the SO2
removal the existing venturi scrubbers are currently achieving. In
Domtar's analysis, it is estimated that a controlled SO2
emission rate of 78.8 lb/hr would be achieved by the operation of add-
on spray scrubbers installed downstream of the existing venturi
scrubbers.
---------------------------------------------------------------------------

    \87\ See ``Supplemental BART Determination Information Domtar
A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated June 28,
2013 and revised on May 16, 2014, prepared by Trinity Consultants
Inc. in conjunction with Domtar A.W. LLC. A copy of this BART
analysis is found in the docket for our proposed rulemaking.
    \88\ See ``Lundberg Budget Proposal Spray Scrubber--Domtar
Industries, Ashdown, AR,'' dated April 17, 2014. The vendor proposal
is found under Appendix D to Domtar's BART analysis titled
``Supplemental BART Determination Information Domtar A.W. LLC,
Ashdown Mill (AFIN 41-00002),'' originally dated June 28, 2013 and
revised on May 16, 2014, prepared by Trinity Consultants Inc. in
conjunction with Domtar A.W. LLC.
---------------------------------------------------------------------------

    Domtar's estimates of the capital and operating and maintenance
costs of add-on spray scrubbers for Power Boiler No. 2 were based on
the equipment vendor's budget proposal and on calculation methods from
our Control Cost Manual. Domtar annualized the capital cost of the add-
on spray scrubbers over a 30-year amortization period and then added
these to the annual operating costs to obtain the total annualized
cost.\89\ The average cost-effectiveness in dollars per ton removed was
calculated by dividing the total annualized cost by the annual
SO2 emissions reductions. The average cost-effectiveness of
the add-on spray scrubbers for Power Boiler No. 2 was estimated to be
$5,258 per ton of SO2 removed (see table below). Domtar's
analysis notes that because of constricted space, there is no existing
property or adequate structure to support the add-on spray scrubber
equipment. In our discussions with Domtar, the facility indicated that
the installation of add-on spray scrubbers would require construction
at the facility to accommodate the equipment, but an estimate of these
costs was not available and therefore not factored into the cost
estimates presented in Domtar's analysis.
---------------------------------------------------------------------------

    \89\ See Appendices B and D to the ``Supplemental BART
Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-
00002),'' originally dated June 28, 2013 and revised on May 16,
2014, prepared by Trinity Consultants Inc. in conjunction with
Domtar A.W. LLC.

                                       Table 48--Summary of Costs for Add-On Spray Scrubber for Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Baseline   Controlled                Annual                 Annual      Annual      Total
                                             emission    emission   Controlled   emissions   Capital   direct O&M   indirect     annual    Average cost
            Control technology               rate (SO2  level (lb/   emission   reductions    cost *    cost ($/    O&M cost    cost ($/   effectiveness
                                               tpy)         hr)     rate (tpy)   (SO2 tpy)     ($)         yr)       ($/yr)       yr)         ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Add-on Spray Scrubber.....................       2,078        78.8         208       1,870  7,175,000   8,833,382     421,789  9,833,378           5,258
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Capital cost does not include new construction to accommodate equipment.

    Domtar's 2014 BART analysis did not identify any energy or non-air
quality environmental impacts associated with the use of add-on spray
scrubbers. We are not aware of any unusual circumstances at the
facility that create non-air quality environmental impacts associated
with the use of add-on spray scrubbers greater than experienced
elsewhere that may therefore provide a basis for the elimination of
this control option as BART (40 CFR part 51, Appendix Y, section
IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-
air quality environmental impacts associated with this control option
at Power Boiler No. 2 that would affect our proposed BART
determination.
    Consideration of the presence of existing pollution control
technology at the source is reflected in the BART analysis in two ways:
First, in the consideration of available control technologies, and
second, in the development of baseline emission rates for use in cost
calculations and visibility modeling. Power Boiler No. 2 is equipped
with multiclones for particulate removal and two venturi scrubbers in
parallel for control of SO2 emissions. It is also equipped
with a combustion air system including overfire air to optimize boiler
combustion efficiency, which also helps control emissions. The baseline
emission rate used in the cost calculations and visibility modeling
reflects the use of these existing controls. As discussed above,
Domtar's analysis also evaluated upgrades to the existing venturi
scrubbers to potentially achieve greater SO2 control
efficiency. Another option we have identified to achieve greater
SO2 control efficiency of the existing scrubbers involves
using additional scrubbing reagent, but this was not considered in
Domtar's 2014 BART analysis. Our analysis of this control option is
presented below, following the analysis of add-on spray scrubbers.
    In the 2014 BART analysis, Domtar assessed the visibility
improvement associated with the add-on spray scrubbers by modeling the
controlled SO2 emission rate using CALPUFF, and then
comparing the visibility impairment associated with the controlled
emission rate to that of the baseline emission rate as measured by the
98th percentile modeled visibility impact. The table below shows a
comparison of the baseline (i.e., existing) visibility impacts and the
visibility impacts associated with the add-on spray scrubbers. The
installation and operation of add-on spray scrubbers is projected to
result in visibility improvement of 0.146 dv at Caney Creek. The
visibility improvement is projected to range from 0.026-0.053 dv at
each of the other Class I areas.

     Table 49--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and
                                    Improvement Due to Add-on Spray Scrubbers
----------------------------------------------------------------------------------------------------------------
                                                                                Add-on spray scrubbers
                                                                           -------------------------------------
                                                              Baseline                             Visibility
                      Class I area                       visibility impact  Visibility impact   improvement from
                                                             \90\ (dv)         ([Delta]dv)          baseline
                                                                                ([Delta]dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek............................................              0.844              0.698              0.146
Upper Buffalo..........................................              0.146              0.093              0.053
Hercules-Glades........................................              0.105              0.054              0.051
Mingo..................................................              0.065              0.039              0.026
Cumulative Visibility Improvement ([Delta]dv)..........  .................  .................              0.276
----------------------------------------------------------------------------------------------------------------

    As mentioned above, another option not evaluated in Domtar's 2014
BART analysis is the optimization of the existing venturi scrubbers to
achieve a higher SO2 control efficiency through the use of
additional scrubbing reagent. Following discussions between us and
Domtar, the facility provided additional information regarding the
existing venturi scrubbers, including a description of the internal
structure of the scrubbers, whether any scrubber upgrades have taken
place, the type of reagent used, how the facility determines how much
reagent to use, and the SO2 control efficiency.\91\ Domtar
confirmed that no upgrades to the scrubbers have ever been performed
and stated that 100% of the flue gas is treated by the scrubber
systems. The scrubbing solution used in the venturi scrubbers is made
up of three components: 15% caustic solution (i.e., NaOH), bleach plant
EO filtrate (typical pH above 9.0), and demineralizer anion rinse water
(approximately 2.5% NaOH). The bleach plant EO filtrate and
demineralizer anion rinse water are both waste byproducts from the
processes at the plant. The 15% caustic solution is added to adjust the
pH of the scrubbing solution and maintain it within the required range
to ensure that sufficient SO2 is removed from the flue gas
in the scrubber to meet the permitted SO2

emission limit of 1.20 lb/MMBtu on a three hour average. Each venturi
scrubber has a recirculation tank that is equipped with level control
systems to ensure that an adequate supply of the scrubbing solution is
maintained. There are pH controllers in place that provide signals for
the 15% caustic flow controllers to adjust the flow of the caustic
solution to bring the pH into the desired set point range. The pH
controllers are overridden in the event that SO2 levels
measured at the stack by the CEMS are above the operator set point of
0.86 lb/MMBtu on a two hour average (the SO2 permit limit is
1.20 lb/MMBtu on a three hour average). This allows additional caustic
feed to the scrubber solution to increase the pH and reduce the
SO2 measured at the stack. According to Domtar, the scrubber
systems operate in this manner to maintain continuous compliance with
permitted emission limits.
---------------------------------------------------------------------------

    \90\ The baseline visibility impacts reflect the operation of
the existing venturi scrubbers.
    \91\ See the following: Letters dated July 9, 2014; July 21,
2014; August 15, 2014; August 29, 2014; and September 12, 2014, from
Annabeth Reitter, Corporate Manager of Environmental Regulation,
Domtar, to Dayana Medina, U.S. EPA Region 6. Copies of these letters
and all attachments are found in the docket for our proposed
rulemaking.
---------------------------------------------------------------------------

    Domtar provided monthly average data for 2011, 2012, and 2013 on
monitored SO2 emissions from Power Boiler No. 2, mass of the
fuel burned for each fuel type, and the percent sulfur content of each
fuel type burned.\92\ Based on the information provided by Domtar, the
monthly average SO2 control efficiency of the existing
scrubbers for the 2011-2013 period ranged from 57% to 90%. The data
indicate that the monthly average control efficiency of the scrubbers
is usually below 90%. The information provided also indicates that the
facility could add more scrubbing solution to achieve greater
SO2 removal than what is necessary to meet permit limits. We
believe that it is feasible for the facility to use additional
scrubbing solution to consistently achieve at least a 90%
SO2 removal on a monthly average basis. To estimate the
SO2 annual emissions reductions expected from increasing the
control efficiency of the scrubbers through the use of additional
scrubbing solution, we calculated the annual average SO2
control efficiency of the existing scrubbers. Based on the monthly
average SO2 control efficiency data for the 2011-2013
period, we estimated the annual average SO2 control
efficiency for the three-year period to be approximately 69%.\93\
Considering the baseline annual emissions for Power Boiler No. 2 are
2,078 SO2 tpy, and assuming that the scrubbers currently
operate at an annual average control efficiency of 69%, we have
estimated that the uncontrolled annual emissions would be 6,769
SO2 tpy and that operating the scrubbers at 90% control
efficiency would result in controlled annual emissions of 677
SO2 tpy. By subtracting the controlled annual emission rate
of 677 SO2 tpy from the baseline annual emission rate of
2,078 SO2 tpy, we estimate that increasing the control
efficiency of the existing venturi scrubbers from current levels to 90%
control efficiency would result in annual emissions reductions of 1,401
SO2 tpy from baseline levels.\94\ Based on the cost
information provided by the facility, increasing the monthly average
SO2 control efficiency of the existing venturi scrubbers
from current levels to 90% control efficiency would require replacing
two scrubber pumps, which involves capital costs of $200,000.\95\ It
would also require additional scrubbing reagent, treatment of
additional wastewater, treatment of additional raw water, and
additional energy usage, which involves annual operation and
maintenance costs of approximately $1.96 million. Based on the
information provided by Domtar, we estimate the average cost-
effectiveness of using additional scrubbing reagent to increase the
SO2 control efficiency of the existing venturi scrubbers
from the current control efficiency (estimated to be 69%) to 90% is
$1,411 per ton of SO2 removed. The cost information is
presented in the table below. To determine the controlled emission rate
that corresponds to the operation of the existing venturi scrubbers at
a 90% removal efficiency, we first determined the SO2
emission rate that corresponds to the operation of the scrubbers at the
current control efficiency of 69%. Based on emissions data we obtained
from Domtar, we determined that the No. 2 Power Boiler's annual average
SO2 emission rate for the years 2009-2011 was 280.9 lb/
hr.\96\ This annual average SO2 emission rate corresponds to
the operation of the scrubbers at a 69% removal efficiency. We also
estimated that 100% uncontrolled emissions would correspond to an
emission rate of approximately 915 lb/hr. Application of 90% control
efficiency to this results in a controlled emission rate of 91.5 lb/hr,
or 0.11 lb/MMBtu based on the boiler's maximum heat input of 820
MMBtu.\97\
---------------------------------------------------------------------------

    \92\ August 29, 2014 letter from Annabeth Reitter, Corporate
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S.
EPA Region 6. A copy of this letter and an Excel file attachment
titled ``Domtar 2PB Monthly SO2 Data,'' are found in the
docket for our proposed rulemaking.
    \93\ See the spreadsheet titled ``Domtar 2PB Monthly
SO2 Data.'' This spreadsheet was included as an
attachment to the August 29, 2014 letter from Annabeth Reitter,
Corporate Manager of Environmental Regulation, Domtar, to Dayana
Medina, U.S. EPA Region 6. See also the spreadsheet titled ``Domtar
PB No2--Cost Effectiveness calculations.'' Copies of these documents
can be found in the docket for this proposed rulemaking.
    \94\ See the spreadsheet titled ``Domtar PB No2--Cost
Effectiveness calculations.'' A copy of this spreadsheet can be
found in the docket for this proposed rulemaking.
    \95\ September 30, 2014 letter from Annabeth Reitter, Corporate
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S.
EPA Region 6. See also the spreadsheet titled ``Domtar PB No2--Cost
of Using Additional Scrubbing Reagent. Copies of these documents can
be found in the docket for this proposed rulemaking.
    \96\ See the spreadsheet titled ``Domtar 2PB Monthly
SO2 Data.'' This spreadsheet was included as an
attachment to the August 29, 2014 letter from Annabeth Reitter,
Corporate Manager of Environmental Regulation, Domtar, to Dayana
Medina, U.S. EPA Region 6. See also the spreadsheet titled ``No2
Boiler_Monthly Avg SO2 emission rate and calculations.''
Copies of these documents can be found in the docket for this
proposed rulemaking.
    \97\ See the spreadsheet titled ``No2 Boiler_Monthly Avg
SO2 emission rate and calculations.'' A copy of this
spreadsheet can be found in the docket for this proposed rulemaking.
    \98\ The capital costs consist of two new pumps for the existing
scrubber system.
    \99\ The operation and maintenance costs consist of the
following costs: Additional scrubbing reagent, treatment of
additional wastewater, treatment of additional raw water, and
additional energy usage.

   Table 50--Summary of Cost of Using Additional Scrubbing Reagent To Increase Control Efficiency of Existing Venturi Scrubbers at Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Baseline                     Annual                 Operation &
                                                            emission     Controlled    emissions     Capital    maintenance     Total      Average cost
                     Control option                         rate (SO2     emission     reductions  costs \98\  cost \99\ ($/ annual cost   effectiveness
                                                              tpy)       rate (tpy)    (SO2 tpy)       ($)          yr)         ($/yr)        ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Use of Additional Scrubbing Reagent.....................         2,078           677        1,401     200,000     1,960,434    1,976,554           1,411
--------------------------------------------------------------------------------------------------------------------------------------------------------

Using the visibility modeling analysis of the baseline visibility
impacts from Power Boiler No. 2 and the visibility improvement
projected from the installation and operation of new add-on spray
scrubbers, we have extrapolated the visibility improvement projected as
a result of using additional scrubbing reagent to increase the
SO2 control efficiency of the existing venturi scrubbers
from the current control efficiency (estimated to be 69%) to 90%, or an
outlet emission rate of 0.11 lb/MMBtu. We have assumed that the maximum
24-hour baseline emission rate used in the visibility modeling
represents the operation of the existing venturi scrubbers at a 69%
control efficiency. We estimate that the visibility improvement of
using additional scrubbing reagent to increase the SO2
control efficiency of the existing venturi scrubbers to 90% control
efficiency is 0.139 dv at Caney Creek and 0.05 dv or less at each of
the other Class I areas (see table below).

     Table 51--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and
                              Improvement From Use of Additional Scrubbing Reagent
----------------------------------------------------------------------------------------------------------------
                                                  Add-on spray scrubber  impacts   Estimated impacts from use of
                                                               (dv)                   additional reagent (dv)
                                     Baseline    ---------------------------------------------------------------
          Class I area              visibility                      Visibility                      Visibility
                                    impact (dv)     Visibility      improvement     Visibility      improvement
                                                    impact (dv)    from baseline    impact (dv)    from baseline
                                                                       (dv)                            (dv)
----------------------------------------------------------------------------------------------------------------
Caney Creek.....................           0.844           0.698           0.146           0.705           0.139
Upper Buffalo...................           0.146           0.093           0.053           0.096            0.05
Hercules-Glades.................           0.105           0.054           0.051           0.057           0.048
Mingo...........................           0.065           0.039           0.026            0.04           0.025
Cumulative Visibility             ..............  ..............           0.276  ..............           0.262
 Improvement (dv)...............
----------------------------------------------------------------------------------------------------------------

    Our Proposed SO2 BART Determination: Taking into consideration the
five factors, we propose to determine that SO2 BART for
Power Boiler No. 2 is an emission limit of 0.11 lb/MMBtu on a 30
boiler-operating-day rolling average, which we estimate is
representative of operating the existing scrubbers at 90% control
efficiency. In this particular case, we define boiler-operating-day 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. We are inviting public comment specifically on the
appropriateness of this proposed SO2 emission limit. We
believe that this emission limit can be achieved by using additional
scrubbing reagent in the operation of the existing venturi scrubbers.
We estimate that operating the existing scrubbers to achieve this level
of control would result in visibility improvement of 0.139 dv at Caney
Creek and 0.05 dv or lower at each of the other Class I areas. We
estimate the cumulative visibility improvement at the four Class I
areas to be 0.262 dv. Based on the cost information provided by the
facility, we have estimated that the use of additional scrubbing
reagent to increase the control efficiency of the existing venturi
scrubbers is estimated to cost $1,411 per ton of SO2
removed. Based on Domtar's BART analysis, new add-on spray scrubbers
that would be operated downstream of the existing venturi scrubbers are
projected to result in visibility improvement of 0.146 dv at Caney
Creek and 0.053 dv or lower at each of the other Class I areas. The
cumulative visibility improvement at the four Class I areas is
projected to be 0.276 dv. The cost of add-on spray scrubbers is
estimated to be $5,258 per ton of SO2 removed, not including
additional construction costs that would likely be incurred to make
space to house the new scrubbers. We do not believe that the amount of
visibility improvement that is projected from the installation and
operation of new add-on spray scrubbers would justify their high
average cost-effectiveness. The incremental visibility improvement of
new add-on spray scrubbers compared to using additional scrubbing
reagent to increase the control efficiency of the existing venturi
scrubbers ranges from 0.001 to 0.007 dv at each Class I area, yet the
incremental cost-effectiveness is estimated to be $16,752. We do not
believe the incremental visibility benefit warrants the higher cost
associated with new add-on spray scrubbers. Therefore, we are proposing
to determine that SO2 BART for Power Boiler No. 2 is an
emission limit of 0.11 lb/MMBtu on a 30 boiler-operating-day rolling
averaging basis, and are inviting comment on the appropriateness of
this emission limit. We propose to require the facility to demonstrate
compliance with this emission limit using the existing CEMS. Since the
SO2 emission limit we are proposing can be achieved with the
use of the existing venturi scrubbers but will require scrubber pump
upgrades and additional scrubbing reagent, we propose to require
compliance with this BART emission limit no later than 3 years from the
effective date of the final action, but are inviting public comment on
the appropriateness of a compliance date anywhere from 1-5 years.
    d. Proposed NOX BART Analysis and Determination for Power Boiler
No. 2. For NOX BART, Domtar's 2014 BART analysis evaluated
LNB, SNCR, and Methane de-NOX (MdN). In the 2006/2007 Domtar
BART analysis, which was submitted in the 2008 Arkansas RH SIP, other
NOX controls were also evaluated but found by the State to
be either already in use or not technically feasible for use at Power
Boiler No. 2. Fuel blending, boiler operational modifications, and
boiler tuning/optimization are already in use at the source, while FGR,
OFA, and SCR were found to be technically infeasible for use at Power
Boiler No. 2. Domtar did not further evaluate these NOX
controls, and instead focused on LNB, SNCR, and MdN in its 2014 BART
analysis for Power Boiler No. 2.
    MdN utilizes the injection of natural gas together with
recirculated flue gases to create an oxygen-rich zone above the
combustion grate. Air is then injected at a higher furnace elevation to
burn the combustibles. In response to comments provided by us regarding
Domtar 2014 BART analysis, Domtar stated that discussions regarding the
technical infeasibility of MdN in the 2006/2007 Domtar BART analysis,
submitted as part of the 2008 Arkansas RH SIP,

remain correct.\100\ The 2006/2007 Domtar BART analysis submitted in
the 2008 Arkansas RH SIP discussed that MdN has not been fully
demonstrated for this type of boiler and incorporates FGR, which is
considered technically infeasible for use at Power Boiler No. 2. Domtar
also stated it recently completed additional research and found that
since the 2006/2007 Domtar BART analysis, MdN has not been placed into
operation in power boilers at paper mills or any comparable source
types. We are also not aware of any power boilers at paper mills that
operate MdN for NOX control, and agree that this control can
be considered technically infeasible for use at Power Boiler No. 2 and
do not further consider it in this evaluation. Domtar also questioned
the technical feasibility of SNCR for boilers with high load swing such
as Power Boiler No. 2, but in response to comments from us, SNCR was
evaluated in Domtar's 2014 BART analysis.
---------------------------------------------------------------------------

    \100\ A copy of Domtar's response is found in the docket for
this proposed rulemaking. See email from Kelly Crouch, dated May 16,
2014.
---------------------------------------------------------------------------

    Based on vendor estimates, the 2006/2007 Domtar BART analysis
estimated the potential control efficiency of LNB to be 30%. In
Domtar's 2014 BART analysis, SNCR was evaluated at a control efficiency
of 27.5% and 35% for Power Boiler No. 2. These values were based on
SNCR control efficiency estimates that came from the equipment vendor's
proposal,\101\ which according to the facility, is not an
appropriations request level quote and therefore requires further
refinement.\102\ For example, Domtar's 2014 BART analysis discusses
that for a base loaded coal boiler with steady flue gas flow patterns
and temperature distribution across the flue gas pathway, SNCR is
typically capable of achieving 50% NOX reduction. However,
Power Boiler No. 2 is not a base loaded boiler and does not have steady
flue gas flow patterns or steady temperature distribution across the
flue gas pathway. To demonstrate the wide range in temperature at Power
Boiler No. 2 and its relationship to steam demand, Domtar obtained an
analysis of furnace exit gas temperatures for Power Boiler No. 2 from
an engineering consultant.\103\ The furnace exit gas temperatures were
analyzed for a 12-day period that according to Domtar is representative
of typical boiler operations. The consultant's report indicated that
furnace exit gas temperatures are representative of temperatures in the
upper portion of the furnace, which is the optimal location for
installation of the SNCR injection nozzles. The consultant estimated
that 1700-1800[deg]F represents the temperature range at which SNCR can
be expected to reach 40% control efficiency at the current boiler
operating conditions. It was found that there is wide variability in
the furnace exit gas temperatures for Power Boiler No. 2, with
temperatures ranging from 1000-2000[deg]F. The data also indicate that
there is a direct positive relationship between boiler steam demand and
furnace exit gas temperatures. It was also found that Power Boiler No.
2 operated in the optimal temperature zone at which SNCR can be
expected to reach 40% control efficiency for only a total of 20 hours
over the 12-day period analyzed (288 continuous hours), which is
approximately 7% of the time. According to Domtar, the significant
temperature swings, which are due to load following and steam demand
variability, create a scenario where urea injection will either be too
high or too low. When not enough urea is injected, NOX
removal will be less than projected and when too much urea is injected,
excess ammonia slip will occur. Domtar stated that the observed
significant temperature swings demonstrate that it will be difficult to
maintain stable, optimal furnace temperatures at which urea can be
injected to effectively reduce NOX with minimal ammonia
slip. We agree that because of the wide variability in steam demand and
wide range in furnace temperature observed at Power Boiler No. 2, the
NOX control efficiency of SNCR at the boiler would not reach
optimal control levels on a long-term basis. We also believe there is
uncertainty as to the level of control efficiency that SNCR would be
able to achieve on a long-term basis for Power Boiler No. 2. However,
we further consider SNCR in the remainder of the analysis.
---------------------------------------------------------------------------

    \101\ Fuel Tech Proposal titled ``Domtar Paper Ashdown,
Arkansas- NOX Control Options, Power Boilers 1 and 2,''
dated June 29, 2012. A copy of the vendor proposal is included under
Appendix D to the ``Supplemental BART Determination Information
Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),'' originally dated
June 28, 2013 and revised on May 16, 2014, prepared by Trinity
Consultants Inc. in conjunction with Domtar A.W. LLC. A copy of this
BART analysis and its appendices is found in the docket for our
proposed rulemaking.
    \102\ See the document titled ``Domtar Responses to ADEQ
Regarding Region 6 Comments on Domtar BART Analysis,'' p. 9. A copy
of this document can be found in the docket for our proposed
rulemaking.
    \103\ September 12, 2014 letter from Annabeth Reitter, Corporate
Manager of Environmental Regulation, Domtar, to Dayana Medina, U.S.
EPA Region 6. A copy of this letter and its attachments are found in
the docket for our proposed rulemaking.
---------------------------------------------------------------------------

    In the 2006/2007 Domtar BART analysis, the capital cost, operating
cost, and cost-effectiveness of LNB were estimated based on vendor
estimates. The analysis was based on a 10-year amortization period,
based on the equipment's life expectancy. However, since we believe a
30-year equipment life is a more appropriate estimate for LNB, we have
revised the cost estimate for LNB.\104\ The annual emissions reductions
used in the cost-effectiveness calculations were determined by
subtracting the estimated controlled annual emission rate from the
baseline annual emission rate. We have also revised the average cost-
effectiveness calculations presented in the 2006/2007 Domtar BART
analysis for LNB by using the boiler's actual annual uncontrolled
NOX emissions rather than the maximum 24-hour emission rate
as the baseline annual emissions. The table below summarizes the
estimated cost of LNB for Power Boiler No. 2, based on the cost
estimates in the 2006/2007 Domtar BART analysis our revisions discussed
above.
---------------------------------------------------------------------------

    \104\ See the spreadsheet titled ``Domtar PB No. 2 LNB_cost
revisions.'' A copy of this spreadsheet is found in the docket for
this proposed rulemaking.
---------------------------------------------------------------------------

    In Domtar's 2014 BART analysis, the capital costs, operating costs,
and cost-effectiveness of SNCR were calculated based on methods and
assumptions found in our Control Cost Manual, and supplemented with
mill-specific cost information for water, fuels, and ash disposal and
urea solution usage estimates from the equipment vendor. The two SNCR
control scenarios evaluated were 27.5% and 35% control efficiencies.
The capital cost was annualized over a 30-year period and then added to
the annual operating cost to obtain the total annualized costs. The
annual emissions reductions associated with each NOX control
option were determined by subtracting the estimated controlled annual
emission rate from the baseline annual emission rate. The baseline
annual emissions used in the calculations are the uncontrolled actual
emissions from the 2001-2003 baseline period. The average cost-
effectiveness was calculated by dividing the total annual cost by the
estimated annual NOX emissions reductions. The table below
summarizes the cost of SNCR for Power Boiler No. 2.

                                            Table 52--Summary of Cost of NOX Controls for Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Annual
                                             Baseline       NOX Removal      emissions      Capital     Total annual    Average cost   Incremental cost-
          NOX Control scenario             emission rate   efficiency of  reduction (NOX    cost ($)     cost ($/yr)    effectiveness  effectiveness ($/
                                             (NOX tpy)     controls (%)        tpy)                                        ($/ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SNCR--27.5%.............................           1,536            27.5             422    2,681,678         843,575           1,998  .................
LNB.....................................           1,536              30             461    6,131,745         899,605           1,951              1,437
SNCR--35%...............................           1,536              35             537    2,877,523       1,026,214           1,909              1,666
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Domtar's 2014 BART analysis did not identify any energy or non-air
quality environmental impacts associated with the use of LNB or SNCR.
We are not aware of any unusual circumstances at the facility that
could create non-air quality environmental impacts associated with the
operation of NOX controls greater than experienced elsewhere
and that may therefore provide a basis for the elimination of these
control options as BART (40 CFR part 51, Appendix Y, section
IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-
air quality environmental impacts associated with NOX
controls at Power Boiler No. 2 that would affect our proposed BART
determination.
    Consideration of the presence of existing pollution control
technology at the source is reflected in the BART analysis in two ways:
First, in the consideration of available control technologies, and
second, in the development of baseline emission rates for use in cost
calculations and visibility modeling. Power Boiler No. 2 is equipped
with multiclones for particulate removal and two venturi scrubbers in
parallel for control of SO2 emissions. It is also equipped
with a combustion air system including overfire air to optimize boiler
combustion efficiency, which also helps control emissions. The
NOX baseline emission rate used in the cost calculations and
visibility modeling reflects the use of these existing controls.
    In the 2014 BART analysis, Domtar assessed the visibility
improvement associated with LNB and SNCR by modeling the NOX
emission rates associated with each control option using CALPUFF, and
then comparing the visibility impairment associated with the baseline
emission rate to the visibility impairment associated with the
controlled emission rates as measured by the 98th percentile modeled
visibility impact. The table below shows a comparison of the baseline
(i.e., existing) visibility impacts and the visibility impacts
associated with LNB and SNCR.

         Table 53--Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile Visibility Impacts and Improvement Due to NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          SNCR--27.5% Control           LNB 30% Control            SNCR--35% Control
                                                                              efficiency                  efficiency                  efficiency
                                                           Baseline  -----------------------------------------------------------------------------------
                      Class I area                        visibility                Visibility                  Visibility                  Visibility
                                                             impact   Visibility    improvement   Visibility    improvement   Visibility    improvement
                                                             (dv)        impact   from  baseline     impact   from  baseline     impact   from  baseline
                                                                         (dv)          (dv)          (dv)          (dv)          (dv)          (dv)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek.............................................       0.844       0.678           0.166       0.663           0.181       0.632           0.212
Upper Buffalo...........................................       0.146       0.134           0.012       0.132           0.014       0.129           0.017
Hercules-Glades.........................................       0.105       0.095           0.010       0.094           0.011       0.092           0.013
Mingo...................................................       0.065       0.060           0.005       0.060           0.005       0.059           0.006
Cumulative Visibility Improvement (dv)..................  ..........  ..........           0.193  ..........           0.211  ..........           0.248
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The table above shows that the installation and operation of SNCR
when operated at 35% control efficiency, if feasible, is projected to
result in visibility improvement of 0.212 dv at Caney Creek and 0.017
dv or less at each of the other Class I areas. When operated at 27.5%
control efficiency, if feasible, SNCR is projected to result in
visibility improvement of 0.166 dv at Caney Creek and 0.012 dv or less
at each of the other Class I areas. The installation and operation of
LNB is projected to result in visibility improvement of 0.181 dv at
Caney Creek and 0.014 dv or less at each of the other Class I areas.
    Our Proposed NOX BART Determination: Taking into
consideration the five factors, we are proposing to determine that
NOX BART for the Domtar Ashdown Mill Power Boiler No. 2 is
an emission limit of 345 lb/hr on a 30 boiler-operating-day rolling
averaging basis, based on the installation and operation of LNB. In
this particular case, we define boiler-operating-day 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. MdN
was determined to be not technically feasible for use at Power Boiler
No. 2 because it has not been fully demonstrated for this type of
boiler and incorporates FGR, which is technically infeasible for use at
the boiler. The installation and operation of SNCR is projected to
result in some visibility improvement at the Class I areas when
operated at 27.5% and 35% control efficiency. However, based on the
information provided by the facility, we believe that because of the
wide variability in steam demand and wide range in furnace temperature
observed in Power Boiler No. 2, the NOX control efficiency
of SNCR at the boiler would not reach optimal control levels on a long-
term basis. There is uncertainty as to the level of control efficiency
that SNCR would be able to achieve on a long-term basis for Power
Boiler No. 2. The installation and operation of LNB is projected to
result in visibility improvement of 0.181 dv at Caney Creek and 0.005-
0.014 dv at each of the other Class I areas. The installation and
operation of LNB is estimated to cost $1,951 per ton of NOX
removed, which

we consider to be cost-effective. Therefore, we are proposing to
determine that NOX BART for Power Boiler No. 2 is an
emission limit of 345 lb/hr on a 30 boiler-operating-day rolling
average basis, based on the installation and operation of LNB. We are
proposing to require compliance with this emission limit no later than
3 years from the effective date of the final rule, and are inviting
public comment on the appropriateness of this compliance date. 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.
    e. PM BART Analysis and Determination for Power Boiler No. 2. PM
BART for Power Boiler No. 2 is addressed in Domtar's 2014 BART
analysis. Power Boiler No. 2 is subject to the Boiler MACT standards
required under CAA section 112, and found at 40 CFR part 63, subpart
DDDDD--National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters. Domtar streamlined the BART analysis for Power Boiler
No. 2 by relying on the Boiler MACT standards for PM to satisfy the PM
BART requirement. Power Boiler No. 2 was determined to fall under the
``biomass hybrid suspension grate'' subcategory for the Boiler
MACT.\105\ As such, Power Boiler No. 2 is subject to the Boiler MACT PM
emission limit of 0.44 lb/MMBtu. The BART Guidelines provide that for
VOC and PM sources subject to MACT standards, the BART analysis may be
streamlined by including a discussion of the MACT controls and whether
any major new technologies have been developed subsequent to the MACT
standards.\106\ The BART Guidelines discuss that there are many VOC and
PM sources that are well controlled because they are regulated by the
MACT standards, and in many cases it will be unlikely that emission
controls more stringent than the MACT standards will be identified
without identifying control options that would cost many thousands of
dollars per ton. Therefore, the BART Guidelines provide that unless
there are new technologies subsequent to the MACT standards which would
lead to cost-effective increases in the level of control, the MACT
standards may be relied on for purposes of BART. Domtar's 2014 BART
analysis does not discuss whether any new technologies subsequent to
the MACT standards have become available and whether they would lead to
cost-effective increases in the level of PM control for Power Boiler
No. 2. However, Domtar at one point estimated the cost of installing
both an add-on spray scrubber and wet ESP on Power Boiler No. 2. Based
on this cost information previously provided by Domtar,\107\ we have
determined that a wet ESP alone would have a purchased equipment cost
(PEC) of $3.22 million and capital costs of approximately $11.3
million. The total annual cost of a wet ESP alone is estimated to be
approximately $1.96 million. The average annual PM emissions from Power
Boiler No. 2 for the 2001-2003 baseline period were 183 tpy. Assuming
that the wet ESP has a 95% control efficiency for PM emissions, we
estimate that it would remove 174 PM tpy. Based on this, we estimate
that the average cost-effectiveness of installing and operating a wet
ESP on Power Boiler No. 2 is $11,254 per PM ton removed. Additionally,
an examination of the species contribution to the 98th percentile
visibility impacts shows that PM emissions contribute a very small
portion of the visibility impairment attributable to Power Boiler No.
2. As shown in the table below, the baseline visibility impairment
attributable to Power Boiler No. 2 is 0.844 dv at Caney Creek and 0.146
dv or less at each of the other Class I areas, based on the 98th
percentile visibility impacts. The PM species contribute only 1.06-
4.58% of the baseline visibility impairment attributable to Power
Boiler No. 2 at the modeled Class I areas.
---------------------------------------------------------------------------

    \105\ See letter dated October 28, 2013, from Thomas Rheaume,
Permits Branch Manager, ADEQ, to Ms. Kelly Crouch, Manager of
Environmental, Energy, and Pulp Tech. at Domtar Ashdown Mill. A copy
of this letter is found in the docket for this proposed rulemaking.
    \106\ 40 CFR part 51, Appendix Y, section IV.C.
    \107\ The cost estimate of new add-on spray scrubbers and a wet
ESP for Power Boiler No. 2 is found in Appendix B to the analysis
titled ``Supplemental BART Determination Information Domtar A.W.
LLC, Ashdown Mill (AFIN 41-00002),'' dated June 28, 2013, prepared
by Trinity Consultants Inc. in conjunction with Domtar A.W. LLC. A
copy of the BART analysis is found in the docket for our proposed
rulemaking.

                      Table 54--Baseline Visibility Impairment and Species Contribution for Domtar Ashdown Mill--Power Boiler No. 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               98th         Species contribution to 98th percentile visibility impacts
                                                                            Percentile   ---------------------------------------------------------------
              Emissions unit                        Class I area            visibility         98th            98th            98th            98th
                                                                           impacts  (dv)   Percentile %    Percentile %    Percentile %    Percentile %
                                                                               \108\            SO4             NO3            PM10             NO2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Power Boiler No. 2........................  Caney Creek.................           0.844           22.04           70.68            4.58            2.69
                                            Upper Buffalo...............           0.146           76.99           20.76            2.26            0.00
                                            Hercules-Glades.............           0.105           61.17           37.68            1.06            0.09
                                            Mingo.......................           0.065           81.46           15.47            3.07            0.00
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Because of the very low baseline visibility impacts that are due to
PM emissions from Power Boiler No. 2, we believe that there is
potential for a very small amount of visibility improvement from the
installation and operation of a wet ESP. We conclude that the
installation and operation of a wet ESP for PM control is not cost-
effective in light of the relatively small improvement in visibility.
Therefore, we are proposing to find that the current Boiler MACT PM
standard of 0.44 lb/MMBtu satisfies the PM BART requirement for Power
Boiler No. 2. We are also proposing that the same method for
demonstrating compliance with the Boiler MACT PM standard is to be used
for demonstrating compliance with the PM BART emission limit. Because
we are proposing a BART emission limit that represents current/baseline
operations and no control equipment installation is necessary, we are
proposing that this emission limitation be complied with for BART
purposes from the date of effectiveness of the finalized action.
---------------------------------------------------------------------------

    \108\ The visibility impact shown represents the highest 98th
percentile value among the three modeled years.

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

IV. Our Proposed Reasonable Progress Analysis and Determinations

    The Regional Haze Rule does not mandate specific milestones or
rates of progress towards achieving the national visibility goal, but
instead calls for states to establish goals that provide for
``reasonable progress'' toward achieving natural (i.e., ``background'')
visibility conditions. The Regional Haze Rule and section 169A of the
CAA require the states, or us in the case of a FIP, to set RPGs by
considering four factors: The costs of compliance, the time necessary
for compliance, the energy and non-air quality environmental impacts of
compliance, and the remaining useful life of any potentially affected
sources (collectively ``the RP factors'').\109\ States, or us in the
case of a FIP, have considerable flexibility in how they take these
factors into consideration, as noted in our Reasonable Progress
Guidance.\110\ The RPGs must provide for an improvement in visibility
on the most impaired days, and ensure no degradation in visibility on
the least impaired days during the planning period.\111\ Furthermore,
if the projected progress for the worst days is less than the Uniform
Rate of Progress (URP), then the state or EPA must demonstrate, based
on the factors above, that it is not reasonable to provide for a rate
of progress consistent with the URP.\112\
---------------------------------------------------------------------------

    \109\ 40 CFR 51.308(d)(1)(i)(A) and CAA section 169A(g)(1).
    \110\ Guidance for Setting Reasonable Progress Goals Under the
Regional Haze Program, June 1, 2007, memorandum from William L.
Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA
Regional Administrators, EPA Regions 1-10 (pp. 4-2, 5-1).
    \111\ Id.
    \112\ 40 CFR 51.308(d)(1)(ii).
---------------------------------------------------------------------------

    In our final action on the Arkansas RH SIP published on March 12,
2012, we disapproved the RPGs established by Arkansas for Caney Creek
and Upper Buffalo because Arkansas did not establish the RPGs in
accordance with the requirements of the CAA and the RHR.\113\
Specifically, Arkansas did not take into consideration the four RP
factors in establishing its RPGs for Caney Creek and Upper Buffalo,
stating that it was an unnecessary exercise. Arkansas believed,
incorrectly, that no additional analysis of potential reasonable
progress measures was necessary because visibility projections for the
Class I areas indicated improvements in visibility consistent with the
URP. As discussed in our disapproval action, a state must determine
whether additional control measures are reasonable based on a
consideration of the four RP factors. Accordingly, in this proposed
rule, we are evaluating the four RP factors to determine whether
additional controls are reasonable and we are establishing RPGs for
Caney Creek and Upper Buffalo after consideration of the RP factors.
---------------------------------------------------------------------------

    \113\ 77 FR 14604, March 12, 2012.
---------------------------------------------------------------------------

A. Reasonable Progress Analysis of Point Sources

    A discussion of the particular pollutants that contribute to
visibility impairment at Arkansas' two Class I areas was provided in
our October 17, 2011 proposed action on the 2008 Arkansas RH SIP (see
76 FR 64186). In that proposed action, we explained that CENRAP used
CAMx with its Particulate Source Apportionment (PSAT) tool to provide
source apportionment by geographic region and major source category
(i.e., point, natural, on-road, non-road, and area sources). Sulfate
from all the source categories combined contributed 87.05 inverse
megameters (Mm-\-1\) out of 133.93 Mm-\1\ of
light extinction at Caney Creek and 83.18 Mm-\1\ out of
131.79 Mm-\1\ of light extinction at Upper Buffalo on the
20% worst days in 2002, which is approximately 65% and 63% of the total
light extinction at each Class I area, respectively. Nitrate from all
source categories combined contributed 13.78 Mm-\1\ out of
133.93 Mm-\1\ of light extinction at Caney Creek and 13.30
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo, which is approximately 10% of the total light
extinction in 2002 on the 20% worst days at each Class I area. The
source category point sources contributed 81.04 Mm-\1\ out
of 133.93 Mm-\1\ of light extinction at Caney Creek and
77.80 Mm-\1\ out of 131.79 Mm-\1\ of light
extinction at Upper Buffalo on the 20% worst days in 2002 (see the
tables below). This represents approximately 60% of the total light
extinction at each Class I area. Each of the source categories other
than the point source category, contribute a much smaller proportion of
the total light extinction at each Class I area. We are therefore
focusing only on the point sources category in our reasonable progress
analysis for this regional haze planning period. Sulfate from point
sources contributed 75.1 Mm-\1\ out of 133.93
Mm-\1\ of light extinction at Caney Creek and 72.17
Mm-\1\ out of 131.79 Mm-\1\ of light extinction
at Upper Buffalo, which is approximately 56% of the total light
extinction at Caney Creek and 55% of the total light extinction at
Upper Buffalo. Nitrate from point sources contributed 4.06
Mm-\1\ out of 133.93 Mm-\1\ of light extinction
at Caney Creek and 3.93 Mm-\1\ out of 131.79
Mm-\1\ of light extinction at Upper Buffalo, which is
approximately 3% of the total light extinction at each Class I area. On
the 20% worst days in 2002, sulfate from Arkansas point sources
contributed 2.20% of the total light extinction at Caney Creek and
1.99% at Upper Buffalo, and nitrate from Arkansas point sources
contributed 0.27% of the total light extinction at Caney Creek and
0.14% at Upper Buffalo.\114\ For both Caney Creek and Upper Buffalo,
SO2 emissions (sulfate precursor) are the principal driver
of regional haze on the 20% worst days in Arkansas' Class I areas, as
visibility impairment in 2002 on the 20% worst days is largely due to
sulfate from point sources.
---------------------------------------------------------------------------

    \114\ See the CENRAP TSD and the August 27, 2007 CENRAP PSAT
tool (CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP
TSD and instructions for accessing the August 27, 2007 CENRAP PSAT
tool can be found in the docket for this proposed rulemaking.

                      Table 55--Modeled Baseline Light Extinction for 20% Worst Days at Caney Creek Wilderness Area in 2002 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           87.05           75.10            0.09            1.19            1.70            5.66
NO3.....................................................           13.78            4.06            0.64            4.70            2.45            1.37
POA.....................................................           10.50            1.29            1.33            0.46            1.34            5.32
EC......................................................            4.80            0.19            0.33            0.86            1.79            1.40
SOIL....................................................            1.12            0.19            0.01            0.01            0.01            0.87
CM......................................................            3.73            0.21            0.04            0.03            0.02            3.19
                                                         -----------------------------------------------------------------------------------------------

Sum.....................................................          133.93           81.04            2.45            7.26            7.31           17.81
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions. Sums include secondary organic matter.

                           Table 56--Modeled Baseline Light Extinction for 20% at Upper Buffalo Wilderness Area in 2002 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           83.18           72.17            0.08            1.15            1.67            5.24
NO3.....................................................           13.30            3.93            0.61            4.14            2.71            1.23
POA.....................................................           10.85            1.06            1.33            0.47            1.38            5.75
EC......................................................            4.72            0.16            0.31            0.80            1.93            1.30
SOIL....................................................            1.21            0.20            0.02            0.01            0.01            0.93
CM......................................................            6.85            0.29            0.05            0.05            0.02            6.02
                                                         -----------------------------------------------------------------------------------------------
Sum.....................................................          131.79           77.80            2.39            6.62            7.72           20.46
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions. Sums include secondary organic matter.

    The CENRAP's 2018 visibility projections show the total extinction
at Caney Creek for the 20% worst days is estimated to be 85.84 Mm-1,
which is a reduction of approximately 36% from 2002 levels (see table
below). The total extinction at Upper Buffalo for the 20% worst days in
2018 is estimated to be 86.16 Mm-1, which is a reduction of
approximately 35% from 2002 levels (see the table below).Sulfate from
all source categories combined is projected to contribute 48.95
Mm-1 out of 85.84 Mm-1 of light extinction at
Caney Creek on the 20% worst days in 2018, or approximately 57% of the
total light extinction. Nitrate from all source categories combined is
projected to contribute 7.57 Mm-1 out of 85.84
Mm-1 of light extinction at Caney Creek on the 20% worst
days in 2018, or approximately 9% of the total light extinction. The
other source categories are each projected to continue contributing a
much smaller proportion of the total light extinction at each Class I
area. At Upper Buffalo, sulfate from all source categories combined is
projected to contribute 45.38 Mm-1 out of 86.16
Mm-1 of light extinction on the 20% worst days in 2018,
which is approximately 53% of the total light extinction. Nitrate from
all source categories combined is projected to contribute 9.22
Mm-1 out of 86.16 Mm-1 of light extinction on the
20% worst days at Upper Buffalo, which is approximately 11% of the
total light extinction. Sulfate from point sources is projected to
contribute 39.83 Mm-1 out of 85.84 Mm-1 of light
extinction at Caney Creek on the 20% worst days in 2018, or
approximately 46% of the total light extinction. Nitrate from point
sources is projected to contribute 2.84 Mm-1 out of 85.84
Mm-1 of light extinction at Caney Creek on the 20% worst
days, which is approximately 3% of the total light extinction. At Upper
Buffalo, sulfate from point sources is projected to contribute 37.09
Mm-1 out of 86.16 Mm-1 of light extinction on the
20% worst days in 2018, which is approximately 43% of the total light
extinction. On the 20% worst days in 2018, sulfate from Arkansas point
sources is projected to contribute 3.58% of the total light extinction
at Caney Creek and 3.20% at Upper Buffalo, and nitrate from Arkansas
point sources is projected to contribute 0.29% of the total light
extinction at Caney Creek and 0.25% at Upper Buffalo.\115\ Based on the
2018 visibility projections, sulfate from point sources is expected to
continue being the principal driver of regional haze on the 20% worst
days at Arkansas Class I areas.
---------------------------------------------------------------------------

    \115\ See the CENRAP TSD and the August 27, 2007 CENRAP PSAT
tool (CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP
TSD and instructions for accessing the August 27, 2007 CENRAP PSAT
tool can be found in the docket for this proposed rulemaking.

                       Table 57--Modeled Future Light Extinction for 20% Worst Days at Caney Creek Wilderness Area in 2018 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           48.95           39.83            0.07            0.12            0.44            5.31
NO3.....................................................            7.57            2.84            0.53            0.97            1.33            1.37
POA.....................................................            9.93            1.76            1.18            0.14            1.03            5.09
EC......................................................            3.17            0.24            0.30            0.16            0.94            1.31
SOIL....................................................            1.29            0.35            0.01            0.01            0.01            0.87
CM......................................................            3.58            0.24            0.04            0.03            0.01            3.02
                                                         -----------------------------------------------------------------------------------------------
Sum.....................................................           85.84           45.27            2.12            1.44            3.76           16.96
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\Totals include contributions from boundary conditions and secondary organic matter.

                      Table 58--Modeled Future Light Extinction for 20% Worst Days at Upper Buffalo Wilderness Area in 2018 (Mm-1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total \1\         Point          Natural         On-road        Non-road          Area
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO4.....................................................           45.38           37.09            0.06            0.12            0.42            4.95
NO3.....................................................            9.22            3.48            0.63            1.10            1.81            1.48
POA.....................................................           10.17            1.48            1.20            0.14            1.01            5.49
EC......................................................            3.07            0.21            0.28            0.15            0.99            1.21
SOIL....................................................            1.40            0.40            0.01            0.01            0.01            0.93
CM......................................................            6.53            0.36            0.05            0.04            0.02            5.65
Sum.....................................................           86.16           43.02            2.24            1.57            4.25           19.71
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Totals include contributions from boundary conditions and secondary organic matter.

    As a starting point in our analysis to determine whether additional
controls on Arkansas sources are reasonable in the first regional haze
planning period, we examined the most recent SO2 and
NOX emissions inventories for point sources in Arkansas.
Based on the 2011 National Emissions Inventory (NEI), the Entergy White
Bluff Plant, the Entergy Independence Plant, and the AEP Flint Creek
Power Plant are the three largest point sources of SO2 and
NOx emissions in Arkansas (see table below).\116\ The combined annual
emissions from these three sources make up approximately 84% of the
statewide SO2 point-source emissions and 55% of the
statewide NOX point-source emissions. We have evaluated
White Bluff Units 1 and 2 and Flint Creek Unit 1 for controls under
BART and are proposing to require these units to install SO2
and NOX controls to meet the BART requirements. We believe
that our five-factor BART analysis for these three units is adequate
for this first planning period to eliminate these sources from further
consideration of controls under the reasonable progress requirements
for this first regional haze planning period. Compliance with the BART
requirements is anticipated to result in a substantial reduction in
SO2 and NOX emissions from these two facilities.
The Entergy Independence Plant is not subject to BART, but its
emissions were 30,398 SO2 tpy and 13,411 NOX tpy
based on the 2011 NEI. The Entergy Independence Plant is the second
largest source of SO2 and NOX point-source
emissions in Arkansas, accounting for approximately 36% of the
SO2 point-source emissions and 21% of the NOX
point-source emissions in the State. Additionally, as we discuss in
more detail in the proceeding subsection, the White Bluff and
Independence Plants are sister facilities with nearly identical units.
Based on this, we expect that the cost-effectiveness of controls will
be very similar for the two facilities.
---------------------------------------------------------------------------

    \116\ See NEI 2011 v1. A spreadsheet containing the emissions
inventory is found in the docket for our proposed rulemaking.

                    Table 59--Ten Largest SO2 and NOX Point Sources in Arkansas (NEI 2011 v1)
----------------------------------------------------------------------------------------------------------------
                                                                                NEI 2011 v1 Emissions (tpy)
                 Facility name                               County              -------------------------------
                                                                                SO2             NOX
----------------------------------------------------------------------------------------------------------------
Entergy Arkansas--White Bluff.................  Jefferson.......................        * 31,684        * 16,013
Entergy-Services Inc--Independence Plant......  Independence....................          30,398          13,411
Flint Creek Power Plant (SWEPCO)..............  Benton..........................         * 8,620         * 5,326
FutureFuel Chemical Company...................  Independence....................           3,421             385
Plum Point Energy Station Unit 1..............  Mississippi.....................           2,830           1,525
Evergreen Packaging--Pine Bluff...............  Jefferson.......................           1,755           1,010
Domtar A.W. LLC, Ashdown Mill.................  Little River....................         * 1,603         * 3,152
Albemarle Corporation--South Plant............  Columbia........................           1,279             443
Nucor-Yamato Steel Company....................  Mississippi.....................             607             263
Ash Grove Cement Company......................  Little River....................             440           1,081
Georgia-Pacific LLC--Crossett Paper...........  Ashley..........................             215           2,402
Marion Intermodal.............................  Crittenden......................              12           1,328
Natural Gas Pipeline Co of America #308.......  Randolph........................             0.4           3,194
Natural Gas Pipeline Co of America #307.......  White...........................             0.4           2,941
Natural Gas Pipeline Co of America #305.......  Miller..........................             0.3           1,731