for AECC Bailey Unit 1 and AECC McClellan Unit 1. In Step 1 of this
BART analysis, AECC identified use of fuel oil with 1% sulfur content
and installation of a scrubber as the only two control options
available. This is a problem because 1% sulfur fuel oil is not the
maximum level of control available when it comes to the use of low
sulfur fuel as a control strategy for SO2 emissions. After
completing the remaining steps of the BART analysis, AECC determined
and ADEQ agreed that BART for the AECC Bailey Unit 1 and the AECC
McClellan Unit 1 is use of fuel oil with 1% sulfur content. Our
evaluation of AECC's BART analysis beyond Step 1 can be found in the
TSD. We are not discussing in this proposed notice our evaluation of
AECC's BART analysis for the AECC Bailey Unit 1 and the AECC McClellan
Unit 1 beyond Step 1, as we are proposing that AECC did not properly
complete the first step of the BART analysis and thus we find that AECC
and ADEQ did not properly follow the requirements of section
51.308(e)(1)(ii)(A) in determining BART. Specifically, we are proposing
that AECC and ADEQ did not properly ``take into consideration the
technology available'' by failing to consider the maximum level of
control each control option is capable of achieving. The BART
Guidelines (Appendix Y to Part 41) provide that in identifying all
options, you must identify the most stringent option (i.e., maximum
level of control each technology is capable of achieving) as well a
reasonable set of options for analysis. The requirement to consider the
most stringent level of control when making BART determinations is also
found in the RHR (64 FR 35740), which provides that in establishing
source specific BART emission limits, the State should identify and
consider in the BART analysis the maximum level of emission reduction
that has been achieved in other recent retrofits at existing sources in
the source category. The visibility regulations define BART as ``an
emission limitation based on the degree of reduction achievable through
the application of the best system of continuous emission reduction.''
Since recent retrofits at existing sources provide a good indication of
the current ``best system'' for controlling emissions, these controls
must be considered in the BART analysis. In considering use of fuel oil
with low sulfur content as a control option in the BART analysis, AECC
did not identify and consider the maximum level of control achievable
from the use of low sulfur fuel oil, and thus the BART analysis is
flawed.
    Sulfur content in fuel oil currently can be found in industry to be
0.5% by weight or less. AECC should have considered the use of fuel oil
with 0.5% sulfur content or less in the BART analysis for the two units
in question. We are aware of several fossil-fuel fired steam electric
plants throughout the country that are currently limited by permit to
burn fuel oil with a sulfur content of 0.5% or less by weight.
Connecticut limits the sulfur content of fuel oil to a maximum 0.3%
\34\ and New York requires facilities to comply with the use of fuel
oil with varying sulfur content limits, with facilities in New York
City being required to use fuel oil with a maximum 0.3% sulfur
content.\35\ Lowering the sulfur content in fuel oil is also a part of
the long-term strategy recommended by the Mid-Atlantic/Northeast
Visibility Union (MANE-VU) states to reduce and prevent regional
haze.\36\ The MANE-VU states in the inner zone (New Jersey, New York,
Delaware, and Pennsylvania) plan to reduce the sulfur content of No. 6
residual fuel oil to 0.3-0.5% sulfur by weight by no later than
2012.\37\ Therefore, the use of fuel oil with a 0.5% sulfur content or
lower is technically feasible and either AECC or ADEQ should have
evaluated its cost effectiveness for the AECC Bailey Unit 1 and the
AECC McClellan Unit 1. In addition, an operating air permit restriction
to use only natural gas as the fuel source for the two units would have
also been acceptable. As part of the BART analysis, ADEQ and/or AECC
must perform a cost analysis in which all cost estimates are properly
documented and must evaluate the visibility impacts of all technically
feasible control options considered before making a BART determination.
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    \34\ Connecticut Department of Environmental Protection (DEP).
``22a-174-19a: Control of Sulfur Dioxide Emissions from Power Plants
and Other Large Stationary Sources of Air Pollution,'' Regulations
of Connecticut State Agencies, Title 22a: Abatement of Air
Pollution, December 28, 2000. http://www.dep.state.ct.us/air2/regs/mainregs/sec19a.pdf.
    \35\ New York State Department of Environmental Conservation
(DEC). ``Subpart 225-1: Fuel Composition and Use-Sulfur
Limitations,'' Environmental Conservation Rules and Regulations, May
8, 2005. http://www.dec.state.ny.us/website/regs/subpart225_1.html.
    \36\ MANE-VU is an RPO that includes the following states:
Maine, New Hampshire, Vermont, Massachusetts, Rhode Island,
Connecticut, New York, New Jersey, Pennsylvania, Maryland, Delaware,
and also the District of Columbia.
    \37\ See 76 FR 27973.
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    Therefore, for the reasons expressed above, we are proposing to
disapprove the SO2, NOX, and PM BART
determinations for the AECC Bailey Unit 1 and the AECC McClellan Unit
1.
b. AEP Flint Creek No. 1 Boiler BART Determination
    The AEP Flint Creek No. 1 Boiler is a BART-eligible source. The
unit has a gross output of 558 MW and a maximum heat input rate of 6324
MMBtu/hr, and burns primarily low sulfur western coal, but can also
combust fuel oil and tire derived fuels (TDF). Fuel oil firing is only
allowed during startup and shutdown of the boiler, startup and shutdown
of the pulverizer mills, for flame stabilization when the coal is
frozen, for fuel oil tank maintenance, to prevent boiler tube failure
in extreme cold weather, and when the unit is offline for maintenance.
    Regarding BART for PM, ADEQ conducted pre-control CALPUFF modeling
for the AEP Flint Creek No. 1 Boiler showing that PM10 and
PM2.5 emissions from the source have minimal visibility
impacts at each Class I area within 300 km. Based on this, AEP decided
and ADEQ agreed that the existing PM emission limit in the operating
air permit, which is achievable through the use of the existing
electrostatic precipitator (ESP), is BART for PM for AEP Flint Creek
No. 1 Boiler. We reviewed the CALPUFF visibility modeling submitted by
ADEQ for AEP Flint Creek No. 1 Boiler, and agree that PM10
and PM2.5 emissions from the source have minimal visibility
impacts at each Class I area within 300 km. As explained in section
IV.D.3 of this proposed rulemaking, using CALPUFF on a pollutant
specific basis to model only the impact of PM emissions on visibility
is an acceptable approach to determine whether a source should be
subject to review for PM controls. In the case of the AEP Flint Creek
No. 1 Boiler, we have found that the visibility impact due to PM
emissions alone is so minimal such that the installation of any
additional PM controls on the unit would likely

achieve very low emissions reductions, have minimal visibility benefit,
and not be cost-effective. Therefore, we are proposing to approve
ADEQ's determination that PM BART for AEP Flint Creek No. 1 Boiler is
the existing PM emission limit. The federally enforceable operating air
permit for the source sets the PM emission limit for the unit at 0.1
lb/MMBtu.\38\
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    \38\ ADEQ Operating Air Permit for AEP-Flint Creek Power Plan
(Permit No. 0276-AOP-R5). This permit can be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0276-AOP-R5.pdf.
---------------------------------------------------------------------------

    Regarding BART for SO2 and NOX, neither AEP
nor ADEQ performed a BART analysis that considered the statutory
factors states are required to consider in determining what retrofit
controls are BART for the AEP Flint Creek No. 1 Boiler. Instead, AEP
determined and ADEQ agreed that BART for SO2 is the
presumptive limit of 0.15 lb/MMBtu and that BART for NOX is
the presumptive limit of 0.23 lb/MMBtu for AEP Flint Creek No. 1
Boiler.\39\ We are aware that the AEP Flint Creek Power Plant has a 558
MW generating capacity, and is therefore not required to follow the
BART Guidelines in making BART determinations for the No. 1 Boiler.
However, this facility and/or the State must still conduct a BART
analysis as specified in 40 CFR 51.308(e)(1)(ii)(A), which provides
that:

    \39\ The ``presumptive limits'' are the rebuttable specific
limits established in the BART Rule for SO2 and
NOX for certain EGUs based on fuel type, unit size, cost
effectiveness, and the presence or absence of pre-existing controls.

    The determination of BART must be based on an analysis of the
best system of continuous emission control technology available and
associated emission reductions achievable for each BART-eligible
source that is subject to BART within the State. In this analysis,
the State must take into consideration the technology available, the
costs of compliance, the energy and nonair quality environmental
impacts of compliance, any pollution control equipment in use at the
source, the remaining useful life of the source, and the degree of
improvement in visibility which may reasonably be anticipated to
---------------------------------------------------------------------------
result from the use of such technology.

    Therefore, we are proposing to disapprove ADEQ's BART finding since
neither AEP nor ADEQ conducted a BART analysis considering the best
system of controls for BART for SO2 and NOX for
AEP Flint Creek No. 1 Boiler. The source and/or ADEQ should have
performed a BART analysis for SO2 and NOX.
Controls achieving more than the SO2 and NOX
presumptive limits are available and should be considered in the BART
analysis, especially considering the magnitude of the visibility impact
of the AEP Flint Creek No. 1 Boiler on the Class I areas within 300
km.\40\ For instance, selective catalytic reduction (SCR) controls are
routinely designed and have routinely achieved a NOX control
efficiency of 90% and a NOX emission rate as low as 0.04 lb/
MMBtu,\41\ based on a 30-day rolling average. Furthermore, SCR system
designers analyzed EPA's Clean Air Market's CEMS data to determine the
NOX levels that are currently being achieved by over 100
SCR-equipped coal-fired boilers, and found that 25 of these units are
achieving NOX emissions less than 0.05 lb/MMBtu on an hourly
average basis.\42\ Flue gas desulfurization (FGD) units (i.e., wet and
dry scrubbers), are a type of post-combustion control for
SO2 emissions. In a report for the National Lime
Association, Sargent & Lundy stated that vendors guarantee
SO2 reduction efficiencies of up to 95%, or as low as 0.06
lb/MMBtu SO2 for dry scrubbers.\43\ The Longleaf Energy
Station in Georgia has two 600 MW boilers that burn coal and are
equipped with a dry scrubber capable of achieving SO2
emissions of 0.065 lb/MMBtu on a 30-day rolling average when the
uncontrolled SO2 emission rate is less than or equal to 1
lb/MMBtu.\44\ The Desert Rock Energy Company, a 1500 MW coal fired
power plant in New Mexico, is equipped with a wet scrubber and has an
SO2 emission limit of 0.060 lb/MMBtu, averaged over a 24-
hour period.\45\ We note that a 24-hour average is much more stringent
than a 30-day rolling average.
---------------------------------------------------------------------------

    \40\ ADEQ's CALPUFF visibility modeling indicates the highest
modeled visibility impact of AEP Flint Creek No. 1 Boiler on nearby
Class I areas is: 3.970 [Delta]dv at Caney Creek; 3.781 [Delta]dv at
Upper Buffalo; 3.983 [Delta]dv at Hercules Glade; 2.596 [Delta]dv at
Mingo; 1.420 [Delta]dv at Sipsey. ADEQ's post-control visibility
modeling shows that the State's BART determinations would result in
the source still causing visibility impairment at Caney Creek (1.573
[Delta]dv), Upper Buffalo (2.089 [Delta]dv), and Hercules Glade
(1.541 [Delta]dv), and contributing to visibility impairment at
Mingo (0.927) (Appendix 9.2B of the Arkansas Regional Haze SIP).
    \41\ See, e.g., William J. Gretta and others, The SCR Retrofit
Design for the Seminole Generating Station, PowerGen, 2008, Hitachi
SCR at Seminole Electric Delivers 0.04 lb/MMBtu NOX
(Preliminary Results), FGD and DeNOX Newsletter, December
2009, No. 380, and NOX CEMS data reported to Clean Air
Markets.
    \42\ Clay Erickson, Robert Lisauskas, and Anthony Licata, What
New in SCRs, DOE's Environmental Control Conference, May 16, 2006,
p. 28. Available here: http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, Selective Catalytic
Reduction: From Planning to Operation, Competitive Power College,
December 2005, p. 75-77.
    \43\ See also Sargent & Lundy, IPM Model--Revisions to Cost and
Performance for APC Technologies, SDA FGD Cost Development
Methodology, Final, August 2010, p. 1 (``It should be noted that the
lowest available SO2 emission guarantees, from the
original equipment manufacturers of SDA FGD systems, are 0.06 lb/
MMBtu.'').
    \44\ Georgia Environmental Protection Division, Longleaf Energy
Station, Permit No. 4911-099-0033-P-01-0, April 9, 2010. Available
at: http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-18499.
    \45\ U.S. EPA, Region 9, Prevention of Significant Deterioration
Permit, Desert Rock Energy Company, July 31, 2008. Available at:
http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-1110.
---------------------------------------------------------------------------

    Therefore, for the reasons expressed above, we are proposing to
disapprove ADEQ's determination of SO2 and NOX
BART for the AEP Flint Creek No. 1 Boiler.
c. Entergy Lake Catherine Unit 4 BART Determination
    The Entergy Lake Catherine Unit 4 is a BART-eligible source. Unit 4
is a combustion engineering tilting tangential fired boiler powering a
552 MW generator. The unit has a maximum heat input rate of 5850 MMBtu/
hr and burns primarily natural gas with No. 6 fuel oil as the secondary
fuel. There is currently no emission control equipment connected to the
boiler. Class I areas within 300 km of the facility include Caney
Creek, Upper Buffalo, and Hercules Glades.
    Since Unit 4 is permitted to burn both natural gas and No. 6 fuel
oil, ADEQ made BART determinations for both natural gas firing and fuel
oil firing scenarios. The Arkansas RH SIP contains the CALPUFF pre-
control modeling files for the natural gas firing scenario, and ADEQ
also provided the modeling files for the fuel oil firing scenario.
CALPUFF post-control modeling results for both gas and oil firing were
also included in the Arkansas RH SIP. In the State's September 27, 2011
supplemental submittal, ADEQ brought to our attention that per an
inspection report dated July 28, 2011, Entergy Lake Catherine Unit 4 is
no longer capable of burning fuel oil. ADEQ noted that the fuel tanks
at the source have been emptied and the pipework necessary to burn fuel
oil is in the process of being removed. ADEQ stated the source does
maintain the ability to burn natural gas. We note that since the source
has not modified its permit and ADEQ has not revised its RH SIP to
reflect this change, we are not disregarding the BART emission limits
for the source for fuel oil firing in this proposed rulemaking.
    Regarding BART for SO2 and PM for the natural gas firing
scenario, Entergy stated that most of the visibility-causing emissions
from Unit 4 are due to NOX since SO2 and PM
emissions from natural gas-fired boilers are generally very low.
Therefore, for the natural gas

firing scenario for Unit 4, Entergy made no BART determination for
SO2, and determined that BART for PM is the existing PM
emission limit in the operating air permit. ADEQ agreed with the
Entergy's determination. Revisions to the State's RH Rule, Chapter 15
of APC&E Commission Regulation 19, which were submitted to us on August
3, 2010, state the existing PM emission limit as of October 15, 2007 is
PM BART for the natural gas firing scenario for Entergy Lake Catherine
Unit 4. This corresponds to an emission limit of 45 lb/hr PM.\46\ We
agree that SO2 and PM emissions from natural gas-fired
boilers are generally very low, and therefore we are proposing to
approve ADEQ's decision not to make a BART determination for
SO2 for the natural gas firing scenario for Unit 4. Since we
have found that the visibility impact of Unit 4 due to PM emissions
alone (from natural gas firing) is so minimal such that the
installation of any additional PM controls on the unit would likely
achieve very low emissions reductions, have minimal visibility
benefits, and not be cost-effective, we are also proposing to approve
ADEQ's determination that BART for PM for Unit 4 for the natural gas
firing scenario is the existing PM emission limit as of October 15,
2007, or 45.0 lb/hr.
---------------------------------------------------------------------------

    \46\ See ADEQ Operating Air Permit for Entergy Arkansas Inc.-
Lake Catherine Plant (Permit No. 1717-AOP-R4). This permit can be
viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/1717-AOP-R4.pdf.
---------------------------------------------------------------------------

    Regarding BART for NOX for the natural gas firing and
fuel oil firing scenarios, Entergy conducted a BART analysis to
determine what retrofit controls are BART for Lake Catherine Unit 4. In
Step 1 of the BART analysis for NOX, Entergy considered a
combination of the following NOX combustion controls for the
natural gas firing scenario: boiler tuning, burners out of service
(BOOS), induced flue gas recirculation (IFGR), overfire air (OFA), and
low NOX burners (LNB). Entergy considered a combination of
the following NOX combustion controls for the fuel oil
firing scenario: boiler tuning, boiler modifications, BOOS, and forced
flue gas recirculation (FFGR). However, Entergy did not consider post-
combustion controls for NOX, such as selective catalytic
reduction (SCR) and selective non-catalytic reduction (SNCR), even
though these controls are technically feasible and available
technologies for reducing NOX emissions currently used by
similar facilities. We provided comments to ADEQ to this effect on May
1, 2007.\47\ In response to our comments, Arkansas included in its RH
SIP submittal the results of a computerized model it obtained from
Entergy, which according to the source, evaluated Unit 4's performance
and the capital and operation and maintenance costs associated with
each identified control technology. Entergy reported that the results
of the computerized model showed that post-combustion controls, such as
SCR and SNCR, had a cost that would be uneconomical to install. The
results of this computer model are discussed further in our discussion
of Step 4 of the BART analysis.
---------------------------------------------------------------------------

    \47\ Our comments on this matter are documented in Appendix 9.3B
of the Arkansas RH SIP.
---------------------------------------------------------------------------

    For Step 3 of the NOX BART analysis, Entergy evaluated
the control effectiveness of the control options considered in Step 1
for both the natural gas and fuel oil firing scenarios. We generally
agree with Entergy's evaluation of the control effectiveness of all
control options considered. In Step 4 of the BART analysis, Entergy
considered the costs of compliance for each control option. In
evaluating the costs of compliance, Entergy analyzed the cost-
effectiveness in annualized dollars per ton of NOX removed
($/ton) of the control options identified in Step 1 of the BART
analysis for NOX for the natural gas and fuel oil firing
scenarios. We note there are two flaws in Entergy's cost-analysis.
Entergy provided no documentation or detailed breakdown of the cost
estimates. The results of the computer model the source used to
determine the cost-effectiveness of post-combustion controls also did
not provide documentation or a detailed breakdown of the cost
estimates. We have no basis to verify the validity of neither the cost
estimates nor Entergy's determination based on the cost estimation
analysis for BART. The basis for cost estimates should be documented
either with data supplied by a vendor (i.e., budget estimates or bids)
or by a referenced source. This was not done in the BART analysis.
Furthermore, Unit 4 is a peaking unit,\48\ and Entergy attempted to
account for this by assuming a 10% capacity factor \49\ in the
calculation of the metrics for tons removed and $/ton removed for all
control options considered in Step 1 of the BART analysis. The computer
model Entergy used to estimate the cost effectiveness of post-
combustion controls likewise assumed a 10% capacity factor in the
calculation of the metrics for tons removed and $/ton removed. Given
that there are no permit requirements in place that would limit the
operation of this unit to 10% capacity, the facility can legally be
operated well above the 10% capacity factor assumed by Entergy. Thus,
any cost effectiveness analysis based on a 10% capacity factor is
likely to significantly inflate the cost per ton of controlling this
unit. In support of the 10% capacity utilization factor, Entergy stated
that the unit has operated, on average, at a capacity of 6.9% for the
past three years. However, past use of this unit was much higher--
approximately 46% on average--over the 2001-2005 period.\50\ Given the
variability in capacity utilization of this unit over the past ten
years, the assumed 10% capacity utilization should be supported by an
enforceable limit. Therefore, we are proposing to disapprove ADEQ's
NOX BART determination for both the natural gas and fuel oil
firing scenarios for Lake Catherine Unit 4.
---------------------------------------------------------------------------

    \48\ 40 CFR 72.2 defines a peaking unit as ``[a] unit that has
(i) An average capacity factor of no more than 10.0 percent during
the previous three calendar years and (ii) A capacity factor of no
more than 20.0 percent in each of those calendar years.''
    \49\ 40 CFR 72.2 defines capacity factor as either ``(1) The
ratio of a unit's actual annual electric output (expressed in MWe/
hr) to the unit's nameplate capacity (or maximum observed hourly
gross load (in MWe/hr) if greater than the nameplate capacity) times
8760 hours; or (2) The ratio of a unit's annual heat input (in
million British thermal units or equivalent units of measure) to the
unit's maximum rated hourly heat input rate (in million British
thermal units per hour or equivalent units of measure) times 8,760
hours.
    \50\ Table 2-1 of the ``BART Analysis for Lake Catherine Plant-
Unit 4,'' prepared by Robert Paine, December 2006 notes that Unit 4
was operated 6,988 hours in 2001 (79.7% utilization); 5,651 hours in
2002 (64.5% utilization); 3,972 hours in 2003 (45.3% utilization);
1,534 hours in 2004 (17.5% utilization); and 2,059 hours in 2005
(23.5% utilization).
---------------------------------------------------------------------------

    For SO2 BART for the fuel oil-firing scenario, Entergy
identified only one available control option in Step 1 of the BART
analysis- use of fuel oil with low sulfur content. ADEQ agreed with the
source's decision. Entergy only considered the use of fuel oil with 1%,
0.5%, and 0.2% sulfur content by weight. We note use of fuel oil with
1% sulfur content is the base case, as Entergy stated the source's
current Title V permit limits the sulfur content of fuel oil used to
1%. Entergy did not consider any post-combustion SO2
controls in the BART analysis, even though post-combustion control
technologies, such as wet and dry scrubbers, are currently being used
by comparable facilities to control SO2 emissions. As such,
Entergy did not identify and consider control technologies that are
capable of the maximum level of control that is achievable, as is
required by the BART guidelines and the RHR. In Step 3 of the

BART analysis, Entergy considered the control effectiveness of all
technically feasible control options identified in Step 1 by using AP-
42 factors for 1%, 0.5%, and 0.2% sulfur residual oil to determine the
amount of sulfur dioxide emissions that would be eliminated by use of
low sulfur fuel oil. Entergy found that based on a 10% capacity factor,
use of 0.5% sulfur fuel oil would result in 1,059 tpy SO2
removed from the baseline and use of 0.2% sulfur fuel oil would result
in 1,802 tpy SO2 removed from the baseline. In Step 4 of the
BART analysis, Entergy considered the costs of compliance for each
control option. Entergy provided no documentation or detailed breakdown
of the costs estimates for low sulfur fuel oil. Therefore, we have no
basis to verify the validity of either the cost estimates or ADEQ's
BART determination based on the cost estimation. The basis for cost
estimates should be documented, and should clearly indicate the amount
of fuel oil that corresponds to the annual cost listed in the cost-
analysis. After conducting post-control visibility modeling, Entergy
determined and ADEQ agreed that SO2 BART for the fuel oil
firing scenario is an SO2 emission limit of 0.562 lb/MMBtu
on a 30 day rolling average. The RH SIP provides conflicting
information on whether this emission limit corresponds to use of 1% or
0.5% sulfur fuel oil. On September 27, 2011, ADEQ submitted a
supplemental submittal clarifying that the 0.562 lb/MMBtu emission
limit corresponds to use of 0.5% sulfur content fuel oil. However, for
the reasons discussed above, we are proposing to find that the source
and ADEQ did not properly follow the requirements of section
51.308(e)(1)(ii)(A) in determining SO2 BART for the fuel oil
firing scenario. Specifically, we are proposing that ADEQ did not
properly take into consideration ``the technology available'' and ``the
costs of compliance.''
    Regarding BART for PM for the fuel oil firing scenario, Entergy
identified the PM10 emission rates associated with use of
1%, 0.5%, and 0.2% sulfur fuel oil. Entergy determined PM BART for Unit
4 for the fuel oil firing scenario is 0.037 lb/MMBtu on a 30 day
rolling average. ADEQ's September 27, 2011 supplemental submittal
clarified that this PM emission limit corresponds to use of 0.5% sulfur
content fuel oil. ADEQ and Entergy did not consider any post-combustion
controls in the BART analysis for PM for the fuel oil firing scenario.
We note the use of a wet scrubber system that controls both
SO2 and PM emissions may prove to be cost-effective and
provide for substantial visibility improvement and should therefore be
considered in Unit 4's BART analysis.
    We are proposing to find that Entergy and ADEQ did not properly
follow the requirements of section 51.308(e)(1)(ii)(A) in determining
BART for NOX for both the natural gas and fuel oil firing
scenarios and BART for SO2 and PM for the fuel oil firing
scenario for the Entergy Lake Catherine Unit 4. Specifically, we are
proposing that ADEQ did not properly take into consideration ``the
technology available'' and ``the costs of compliance.'' For the reasons
identified above, we are proposing to disapprove ADEQ's BART
determinations for PM, NOX, and SO2 under oil
firing conditions, and NOX under natural gas firing
conditions. We are proposing to approve ADEQ's BART determination for
the Entergy Lake Catherine Unit 4 for PM under gas firing conditions
and ADEQ's decision to make no BART determination for SO2
under gas firing conditions.
d. Entergy White Bluff Units 1, 2, and Auxiliary Boiler BART
Determinations
    The White Bluff Units 1 and 2 and the Auxiliary Boiler are BART-
eligible sources. Units 1 and 2 are coal fired boilers with a maximum
power rating of 850 MW each and a heat input rate of 8700 MMBtu/hr
each. Units 1 and 2 are permitted to burn both sub-bituminous and
bituminous coal as the primary fuel and No. 2 fuel oil or bio-diesel as
the start-up fuel. The Auxiliary Boiler is a 183 MMBtu/hr boiler that
is permitted to burn only No. 2 fuel oil or biodiesel. The Class I
areas located within 300 km of the facility are Caney Creek, Upper
Buffalo, and Hercules Glades. Since Units 1 and 2 are permitted to burn
both bituminous and sub-bituminous coal, ADEQ made separate BART
determinations for bituminous sub-bituminous coal firing.
    Regarding BART for PM for Units 1 and 2, neither Entergy nor ADEQ
performed a BART analysis to determine what retrofit controls are BART
for Units 1 and 2. The source's rationale for this, which ADEQ agreed
with, was its belief that most of the visibility-causing emissions from
Units 1 and 2 are due to SO2 and NOX, and
PM10 emissions are well-controlled with existing
electrostatic precipitators (ESPs). We reviewed the CALPUFF visibility
modeling submitted by ADEQ for Entergy White Bluff, and agree that PM
emissions from the source have minimal visibility impacts at each Class
I area within 300 km. Revisions to the Arkansas RH Rule (APC&E
Commission Regulation 19, chapter 15) that were submitted to us by ADEQ
on August 3, 2010, state the PM BART emission limit for White Bluff
Units 1 and 2 is the existing PM emission limit in the air permit as of
October 15, 2007. The federally enforceable operating air permit states
the PM emissions from the two units are controlled with ESPs and
requires that the two units comply with a PM emission standard of 0.10
lb/MMBtu.\51\ Since we have found that the visibility impact of the
source due to PM emissions alone is so minimal such that the
installation of any additional PM controls on the units would likely
achieve very low emissions reductions, have minimal visibility
benefits, and not be cost-effective, we are proposing to approve ADEQ's
determination that PM BART for both the bituminous and sub-bituminous
coal firing scenarios is the existing PM emission limit for Units 1 and
2.
---------------------------------------------------------------------------

    \51\ ADEQ Operating Air Permit for Entergy Services Inc.--White
Bluff Plant (Permit No. 0263-AOP-R6). This permit can be viewed at
http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0263-AOP-R6.pdf.
---------------------------------------------------------------------------

    Regarding SO2 BART for White Bluff Units 1 and 2,
Entergy performed a BART analysis and determined that the presumptive
limits of 0.15 lb/MMBtu for both the sub-bituminous and bituminous coal
firing scenarios for SO2 for Units 1 and 2 apply to the two
units because they are greater than 200 MW each. Although Entergy
performed a BART analysis for BART for SO2, it considered
only those control options that meet the presumptive limit of 0.15 lb/
MMBtu, without considering whether a more stringent SO2
emission limit is BART for Units 1 and 2. As stated elsewhere in this
proposed rulemaking, the BART guidelines and the RHR require
consideration of the most stringent control technology in the BART
analysis. Because the control technology options considered in the BART
analysis are capable of achieving a lower emission limit than the
presumptive limit for this facility, and these controls are being
currently used by similar facilities to control SO2
emissions to an emission limit lower than the presumptive limit,
consideration of these technologies and the lowest emission limit
achievable must be included in the BART analysis.
    In Step 1 of the SO2 BART analysis for Units 1 and 2,
Entergy identified two available options to control the units to the
presumptive SO2 limit: limestone forced oxidation (wet
scrubbing) and lime spray dryer (dry scrubbing). Entergy did not
identify either control option as technically infeasible. In Step

3 of the BART analysis, Entergy evaluated the control effectiveness of
the two control options, stating the wet scrubber can achieve up to 95%
control efficiency while the dry scrubber can achieve up to 92% control
efficiency. In Step 4 of the BART analysis, Entergy evaluated the costs
of compliance for the two control options. Entergy determined the
installation of a wet scrubber would have an annualized cost of
$17,023,735 with a cost effectiveness of $620/ton SO2
removed at Unit 1 and an annualized cost of $17,159,021 with a cost-
effectiveness of $620/ton SO2 removed at Unit 2. Entergy
also determined the installation of a dry scrubber would have an
annualized cost of $34,035,909 with a cost effectiveness of $1280/ton
SO2 removed at Unit 1 and an annualized cost of $34,306,388
with a cost-effectiveness of $1280/ton SO2 removed at Unit
2. In Step 5 of the BART analysis, Entergy evaluated the visibility
impacts of the two control options. However, Entergy's modeling
underestimated the visibility benefit anticipated from the use of wet
or dry scrubbers because it modeled both control options at the same
SO2 emission rate of 0.15 lb/MMBtu, rather than at the
achievable control effectiveness of 92% removal for dry scrubbing and
95% for wet scrubbing. We also note that Entergy deviated from the
modeling protocol and used the 98th percentile (8th highest modeled
day) in this analysis instead of the maximum modeled visibility impact.
Entergy's post-control modeling showed that the visibility benefits for
dry scrubbers and wet scrubbers is nearly the same (with dry scrubbing
being slightly better due to a hotter plume and lower sulfuric acid
emissions), while the annualized cost of a dry scrubber is nearly twice
that of a wet scrubber. Entergy determined and ADEQ agreed that BART
for SO2 for Units 1 and 2 is installation and operation of a
wet scrubber at each unit to achieve the presumptive BART limit of 0.15
lb/MMBtu for both the sub-bituminous and the bituminous coal firing
scenarios. Entergy considered a wet scrubber achieving 0.15 lb/MMBtu to
be the most stringent technology available. But as discussed elsewhere,
wet scrubbers and dry scrubbers have been documented to achieve much
lower emissions, including emissions as low as .065 lbs/MMBtu for dry
scrubbers. Therefore, the evaluation is not acceptable. In addition, we
note that the 0.15 lb/MMBtu presumptive BART limit established by ADEQ
corresponds to 82% control removal of the wet scrubber at Unit 1 and
80% control removal at Unit 2, as indicated by ADEQ in the Arkansas RH
SIP narrative.\52\ Table A-1 in Appendix A of the BART analysis
indicates the cost-effectiveness of installing and operating a wet
scrubber is $620/ton SO2 removed. Although Table A-1
indicates such cost-effectiveness value corresponds to operation of the
wet scrubber at 95% control efficiency, neither ADEQ nor Entergy
provided a breakdown of the cost estimates and we were therefore unable
to verify whether it in fact corresponds to 95% control efficiency or
if it corresponds to 80% control efficiency at Unit 2 and 82% control
efficiency at Unit 1. Even if the $620/ton SO2 removed cost-
effectiveness value corresponds to only 82% control efficiency for Unit
1 and 80% control efficiency for Unit 2, we believe that the
incremental cost of operating the wet scrubber at 95% vs. 80% and 82%
control efficiency is relatively minimal, and is likely cost-effective.
Since Entergy and ADEQ considered only the 0.15 lb/MMBtu SO2
presumptive limit in the BART analysis for Units 1 and 2, even though a
lower limit is technically achievable and more than likely cost-
effective, we are proposing to disapprove ADEQ's determination that
BART for SO2 for Units 1 and 2 is the presumptive limit of
0.15 lb/MMBtu on a 30-day rolling average for both the sub-bituminous
and bituminous coal firing scenarios.
---------------------------------------------------------------------------

    \52\ See Table 9.3a of the Arkansas RH SIP.
---------------------------------------------------------------------------

    Regarding NOX BART for White Bluff Units 1 and 2,
Entergy performed a BART analysis in which available combustion control
technologies to control NOX to the presumptive limit of 0.15
lb/MMBtu for the sub-bituminous coal-firing scenario and 0.28 lb/MMBtu
for the bituminous coal-firing scenario were considered. As in the
SO2 BART analysis for Units 1 and 2, Entergy did not
consider establishing NOX BART emission limits more
stringent than the NOX presumptive limits. In Step 1 of the
NOX BART analysis, Entergy considered the following control
options: boiler tuning, OFA, and LNB. Entergy did not evaluate post-
combustion controls such as SCR and SNCR or any other NOX
control options capable of emission limits more stringent than the
presumptive limits, when these are technically feasible and available
and are currently being used by comparable facilities to control
NOX emissions at rates more stringent than the presumptive
limit. Since Entergy did not identify the maximum control technology
available as a control option in Step 1 of the BART analysis, the
subsequent analysis in the remaining steps was incomplete. However, for
the sake of providing a fuller picture of our evaluation of Entergy's
BART analysis for NOX for White Bluff Units 1 and 2, we
discuss the remaining steps of the BART analysis.
    Entergy did not identify any of the NOX controls it
listed in Step 1 of the BART analysis as being technically infeasible.
In Step 3 of the BART analysis, Entergy evaluated the control
effectiveness of the control options. Entergy determined boiler tuning
will result in 37% control removal; a combination of boiler tuning and
OFA will result in 53.6% control removal; and a combination of boiler
tuning, OFA, and LNB will result in 69% control efficiency at each
unit. In Step 4 of the BART analysis, Entergy evaluated the costs of
compliance for the control options considered and determined that a
combination of boiler tuning, OFA, and LNB has a control effectiveness
of $463/ton NOX removed for Unit 1 and $437/ton
NOX removed for Unit 2. We note Entergy's cost analysis of
the NOX control options included no documentation or
detailed breakdown of the costs. We have no basis to verify the
validity of neither the cost estimates nor Entergy and ADEQ's
determination based on the analysis of cost estimation for BART. The
basis for cost estimates must be documented either with data supplied
by an equipment vendor (i.e., budget estimates or bids) or by a
referenced source. This was not done. Without either ADEQ or Entergy
providing a breakdown of costs of material, labor, operation and
maintenance, etc, we cannot verify the accuracy of Entergy's cost
effectiveness determination. Furthermore, the cost-effectiveness
analysis is problematic because Entergy assumed, and ADEQ agreed with,
an 85% utilization of the two units when the units are capable of 100%
utilization and there is no federally enforceable limit of 85%
utilization in place.\53\ Since the two units are technically and
legally capable of operating at 100% utilization, a cost estimate
assuming 85% utilization may underestimate the amount of emission
reductions achieved by the controls and therefore under-represent the
potential cost-effectiveness of such controls. In Step 5 of the BART
analysis, Entergy evaluated the visibility impacts of the control
options and subsequently determined that a combination of boiler

tuning, OFA, and LNB is BART for NOX for Units 1 and 2,
achieving an emission limit of 0.15 lb/MMBtu for the sub-bituminous
coal firing scenario and 0.28 lb/MMBtu for the bituminous coal firing
scenario. ADEQ agreed with the Entergy's determination.
---------------------------------------------------------------------------

    \53\ Based on operating hours provided by Entergy for Units 1
and 2, Unit 1 was operated 92.5% of the time in 2003, and Unit 2 was
operated 92.7% of the time in 2004. See Table 2-1, under Section 2.2
of the BART analysis for Entergy White Bluff Units 1 and 2 (found in
Appendix 9.3A of the RH SIP).
---------------------------------------------------------------------------

    As already explained in our evaluation of BART for SO2
for Units 1 and 2, we disagree with Entergy and ADEQ's approach of not
considering an emission limit more stringent than the presumptive limit
when comparable facilities have used control technologies to reduce
emissions below the presumptive limit. Also, as explained elsewhere in
this notice, the BART Rule does not suggest the presumptive limits
should be viewed as establishing a safe harbor from more stringent
regulation under the BART provisions. ADEQ's CALPUFF pre-control
modeling indicates the three subject to BART units at White Bluff
together cause visibility impairment at Caney Creek, Upper Buffalo,
Hercules Glade, Mingo, and Sipsey.\54\ A considerable portion of this
visibility impairment is due to NOX emissions. ADEQ's post-
control modeling indicates the three subject to BART units at White
Bluff combined would still cause visibility impairment at all five
Class I areas modeled (Caney Creek, Upper Buffalo, Hercules Glade,
Mingo and Sipsey), and that a considerable portion of the post-control
modeled visibility impairment is due to NOX emissions. In
light of the post-control modeling results, ADEQ and/or Entergy should
have considered additional post-combustion controls, such as SNCR and
SCR, that are capable of achieving NOX emission limits well
below the NOX presumptive limits, and have been widely used
by similar facilities to achieve emissions at rates below the
presumptive limit. Therefore, we are proposing to disapprove ADEQ's
determination that BART for NOX for White Bluff Units 1 and
2 is 0.15 lb/MMBtu for the sub-bituminous coal firing scenario and 0.28
lb/MMBtu for the bituminous coal firing scenario.
---------------------------------------------------------------------------

    \54\ The maximum modeled pre-control [Delta]dv values at
surrounding Class I areas due to the three subject-to-BART units at
White Bluff are: Caney Creek= 8.816 [Delta]dv; Upper Buffalo= 7.750
[Delta]dv; Hercules Glade=6.314 [Delta]dv; Mingo=5.617; and
Sipsey=5.843. See Appendix 9.2C of the Arkansas RH SIP.
---------------------------------------------------------------------------

    With regard to the Auxiliary Boiler, neither ADEQ nor Entergy
conducted a BART analysis that considered the statutory factors states
are required to consider in determining what level of control is BART
for a source, whether this be an emission limit or a work practice
standard. The Arkansas RH SIP narrative states ADEQ decided to
establish work practice standards for this source pursuant to 40 CFR
51.308(e)(1)(iii), rather than establish BART emission limits for
SO2, NOX, and PM. APC&E Commission Regulation 19,
Chapter 15, established that BART for the Auxiliary Boiler is a
restriction to operate no more than 4360 hours annually. Since ADEQ's
pre and post-control visibility modeling shows the visibility impact on
surrounding Class I areas of all three units at the facility combined,
we are not able to assess the visibility impact on Class I areas of the
Auxiliary Boiler alone. The operating permit indicates the Auxiliary
Boiler combusts No. 2 fuel oil or biodiesel to provide steam for Unit 1
and 2 start-up activities. The restriction established by ADEQ as BART
would allow the Auxiliary Boiler to operate 50% of the time on an
annual basis. In practice, an auxiliary boiler that is only needed for
start-up is typically operated much less than that. We are proposing to
find that ADEQ did not properly follow the requirements of section
51.308(e)(1)(ii)(A) because neither ADEQ nor Entergy performed a BART
analysis for the Auxiliary Boiler for their chosen work practice
standard. We are proposing to disapprove ADEQ's determination that BART
for the White Bluff Auxiliary Boiler is a restriction to operate no
more than 4360 hours annually.
e. Domtar Power Boilers No. 1 and 2 BART Determinations
    The Domtar Power Boilers No. 1 and 2 are BART-eligible sources. The
Power Boilers generate steam and electricity for the other processes
within the Domtar kraft pulp mill. The No. 1 Power Boiler has a heat
input rating of 580 MMBtu/hr and is permitted to burn bark, wood waste,
municipal yard waste, recycled sanitary products composed of cellulose
and polypropylene, pelletized paper fuel (PPF), No. 6 fuel oil, used
oil generated on site, reprocessed fuel oil, tire derived fuel (TDF),
and natural gas. The No. 1 Power Boiler is equipped with a traveling
grate, a combustion air system, and a wet ESP for removal of PM
emissions. According to the operating air permit, the No. 1 Power
Boiler's permitted emission rate for PM/PM10 is 0.07 lb/
MMBtu. The operating air permit provides that the sulfur content of the
fuel oil used at the No.1 Power Boiler shall not exceed 3.0% by weight
and that the No. 1 Power Boiler shall not use more than 2,700,000
gallons of fuel oil for any consecutive 12-month period. The permit
also limits the total amount of TDF used at the Power Boilers No. 1, 2,
and 3 combined to 220 tons in any 24-hour period.
    The No. 2 Power Boiler has a heat input rating of 820 MMBtu/hr and
burns primarily pulverized bituminous coal, but is also permitted to
burn non-condensable gases (NCGs), bark and wood chips used to absorb
oil spills, wood waste, municipal yard waste, natural gas, used oil
generated on site, recycled sanitary products based on cellulose and
polypropylene, No. 6 fuel oil, reprocessed fuel oil, TDF, and petroleum
coke. The No. 2 Power Boiler is equipped with a traveling grate,
combustion air system including OFA, multiclones for removal of PM
emissions, and two venturi scrubbers in parallel for removal of
remaining PM emissions and SO2. According to the operating
air permit, the No. 2 Power Boiler's permitted emission rate for PM/
PM10 is 0.1 lb/MMBtu.
    Regarding BART for PM, Domtar stated the No. 1 and 2 Power Boilers
were at the time subject to the Boiler Maximum Achievable Control
Technology (MACT) PM emission standard of 0.07 lb/MMBtu. A wet ESP was
installed at the No. 1 Power Boiler to meet the 0.07 lb/MMBtu Boiler
MACT PM emission standard. Domtar also stated that the No. 2 Power
Boiler's existing wet scrubber is capable of meeting the Boiler MACT PM
emission standard. Domtar noted that in the BART Guidelines, EPA
encourages the use of streamlined approaches for BART determinations
and elected to forego a BART analysis and to presumptively rely on the
0.07 lb/MMBtu Boiler MACT PM emission standard in existence at the time
to meet the BART PM requirements for both the No. 1 and No. 2 Power
Boilers. We note the BART Guidelines (Appendix Y to Part 51) provide
that for VOC and PM sources subject to MACT standards, States may
streamline the BART analysis by including a discussion of the MACT
controls and whether any major new technologies have been developed
subsequent to the MACT standards. The 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, sources may
rely on the MACT standards for purposes of BART.
    Concerning Power Boiler No. 1, Domtar provided a discussion of
other PM control technologies available at the time, and determined
that a wet ESP with a PM emission limit of 0.07 lb/MMBtu on a 30-day
rolling average is BART for Power Boiler No. 1. ADEQ agreed with
Domtar's determination. We agree that ADEQ's determination for BART for
PM for Power Boiler No. 1 is consistent with the BART Guidelines and
are proposing to approve it.

Concerning Power Boiler No. 2, Domtar stated that the unit was subject
to the Boiler MACT \55\ PM emission standard in existence at the time
(0.07 lb/MMBtu), and indicated its intent to presumptively rely on such
standard to meet BART PM requirements for Power Boiler No. 2. However,
instead of adopting 0.07 lb/MMBtu as the BART PM emission limit for
Power Boiler No. 2, ADEQ adopted 0.10 lb/MMBtu as the BART PM emission
limit. Since ADEQ did not select the Boiler MACT PM emission standard
current at the time the BART determination was made as the BART PM
emission limit for Power Boiler No. 2, ADEQ cannot elect to take the
streamlined approach provided in the BART Guidelines. If ADEQ chooses
to take the streamlined approach provided in the BART Guidelines, ADEQ
must select the Boiler MACT PM standard if it determines there are no
new and cost-effective technologies or available upgrades developed
subsequent to the MACT standard. Otherwise, ADEQ and/or Domtar must
perform a complete BART analysis that considers the statutory factors
under section 51.308(e)(ii)(A) to determine BART for PM for Power
Boiler No. 2. Furthermore, ADEQ's pre-control visibility modeling
indicates a considerable portion of the combined visibility impact of
No. 1 and 2 Power Boilers at Caney Creek is due to PM emissions.\56\
Therefore, we are proposing to disapprove ADEQ's determination that
BART for PM10 for Power Boiler No. 2 is 0.10 lb/MMBtu on a
30-day rolling average, and we are proposing to approve ADEQ's
determination that BART for PM10 for Power Boiler No. 1 is
0.07 lb/MMBtu on a 30-day rolling average.
---------------------------------------------------------------------------

    \55\ The MACT standards are part of the National Emission
Standards for Hazardous Air Pollutants for Source Categories
(NESHAP), provided under 40 CFR 63.
    \56\ ADEQ's pre-control modeling files are found in Appendix
9.2B of the Arkansas RH SIP. Since ADEQ's visibility modeling shows
the visibility impact of No. 1 and 2 Power Boilers combined, we were
unable to assess the visibility impact of No. 2 Power Boiler
individually on surrounding Class I areas.
---------------------------------------------------------------------------

    Regarding BART for SO2 for Power Boiler No. 1, Domtar
noted pre-combustion controls such as fuel switching/blending and fuel
cleaning are ineffective, as wood has low sulfur content. Domtar also
noted post-combustion controls such as flue gas desulfurization (FGD)
and (i.e., wet and dry scrubbers) have not been installed on wood-fired
boilers because of the relatively low SO2 emissions from
wood combustion. Domtar determined that due to the low sulfur content
of wood, SO2 emissions from wood combustion are inherently
low and ``have a negligible impact on visibility impairment.'' Domtar
determined SO2 BART for Power Boiler No. 1 is no additional
SO2 controls beyond the existing fuel restrictions (fuel oil
with a maximum 3.0% sulfur content and a usage limitation of 2,700,000
gallons of fuel oil per consecutive 12-month period) are necessary.
ADEQ agreed with Domtar's determination and decided that an emission
limit of 1.12 lb/MMBtu on a 30-day rolling average is BART for
SO2 for Power Boiler No. 1. We note that ADEQ's CALPUFF pre-
control modeling demonstrates the No. 1 Power Boiler emits more than
one-third of the total modeled emissions of SO2 from the two
sources.
    We agree that due to the low sulfur content of wood, SO2
emissions from wood-fired boilers are generally relatively low. Table
1.6-2 of EPA's Compilation of Air Pollutant Emission Factors indicates
the combustion of wood waste has a typical SO2 emission rate
of 0.025 lb/MMBtu.\57\ In light of this, we question the
appropriateness of an SO2 emission limit of 1.12 lb/MMBtu
for Power Boiler No. 1. Neither ADEQ nor Domtar provided any support
for this emission limit. Domtar stated that approximately 75 percent of
the heat input for Power Boiler No. 1 is supplied by bark. A unit
combusting primarily bark should be capable of achieving an
SO2 emission rate much lower than 1.12 lb/MMBtu. The
facility's current permit for this unit limits its annual
SO2 emissions to 214 tons per year (tons/year), which is a
low figure. Therefore, there appears to be a mismatch between ADEQ's
relatively high BART SO2 emission limit and what the
facility actually needs, based on its current permit. As part of its
BART analysis, ADEQ and/or Domtar should have conducted a fuel
inventory of this boiler in order to explore this issue. Other sources
of potential sulfur emissions should have been investigated, including
emissions resulting from burning fuel oil and TDF. ADEQ should also
have considered lowering the sulfur content of fuel oil burned at the
source, and/or lowering the limit on fuel oil usage. If Power Boiler
No. 1 truly needs such a high SO2 emission limit, then ADEQ
and/or the Domtar should have investigated the feasibility,
effectiveness, and cost of SO2 controls. Therefore, we are
proposing to find that ADEQ did not properly follow the requirements of
section 51.308(e)(1)(ii)(A) in determining BART. We are proposing to
disapprove ADEQ's determination that BART for SO2 for Power
Boiler No. 1 is 1.12 lb/MMBtu on a 30-day rolling average.
---------------------------------------------------------------------------

    \57\ Compilation of Air Pollutant Emission Factors, Volume I:
Stationary Point and Area Sources, AP-42, 5th Edition, January 1995.
---------------------------------------------------------------------------

    Regarding BART for SO2 for Power Boiler No. 2, neither
ADEQ nor Domtar performed a BART analysis that considered the statutory
factors under section 51.308(e)(ii)(A). Domtar stated the unit is
equipped with a wet scrubber for control of SO2 and PM
emissions. According to Domtar, the existing wet scrubber currently
achieves an SO2 control efficiency of approximately 90%.
Domtar indicated that the BART Guidelines provide an option to skip the
comprehensive BART analysis for subject to BART units already equipped
with the most stringent controls available, including all possible
improvements to control devices, as long as these are made federally
enforceable for the purpose of implementing BART for the source. Domtar
stated that since wet scrubbing is the most effective method of
controlling SO2 emissions and it has not identified any
feasible upgrades to the existing wet scrubber, no BART analysis is
necessary. ADEQ agreed with Domtar, and determined that no additional
SO2 removal is needed for the No. 2 Power Boiler, and BART
for SO2 is 1.20 lb/MMBtu on a 30-day rolling average using
the existing wet scrubber.
    We agree that the BART Guidelines allow sources to forego the BART
analysis when the source already has the most stringent controls
available in place and all possible improvements to control devices
have been made. However, we disagree that a 1.20 lb/MMBtu
SO2 emissions rate corresponds to the most stringent control
available. We note FGD systems are capable of SO2 reduction
efficiencies up to 98%.\58\ Therefore, the 90% reduction efficiency
claimed by Domtar does not correspond to the highest SO2
control efficiency wet scrubbers are capable of achieving. The highest
SO2 control efficiency issue aside, although Domtar stated
it did not identify any feasible upgrades to the existing wet scrubber,
it provided no documentation of what upgrades were considered and why
they were found to be technical infeasible. In considering all possible
improvements to the scrubber, Domtar should have evaluated options that
not only improve the design removal efficiency of the scrubber vessel
itself, but also considered upgrades that can improve the overall
SO2 removal efficiency of the scrubber system. For example,
the

BART Guidelines state that improving maintenance practices, adjusting
scrubber chemistry, and increasing auxiliary equipment redundancy are
some ways to improve average SO2 removal efficiencies. For
the reasons discussed above, we are proposing to find that ADEQ did not
properly follow the requirements of section 51.308(e)(1)(ii)(A) in
determining BART for SO2 for Power Boiler No. 2. We are
proposing to disapprove ADEQ's determination that BART for
SO2 for the No. 2 Power Boiler is 1.20 lb/MMBtu on a 30-day
rolling average using the existing wet scrubber.
---------------------------------------------------------------------------

    \58\ See EPA's Air Pollution Control Fact Sheet on FGD control
technology, available at http://www.epa.gov/ttn/catc/dir1/ffdg.pdf.
---------------------------------------------------------------------------

    Regarding BART for NOX for Power Boilers No. 1 and 2,
Domtar performed a BART analysis to determine what controls are BART
for the two boilers. In Step 1 of the NOX BART analysis,
Domtar identified the following control technologies: boiler tuning/
optimization, fuel blending, FGR, LNB, OFA, SCR, SNCR, and reburning/
methane de-NOX. Domtar stated the source has employed and
intends to continue to employ the latest boiler optimization and tuning
techniques, and that such control technologies are considered part of
the base case for Power Boilers No. 1 and 2. Similarly, Domtar
explained it historically mixes 10-15% (heat input basis) wood with
coal in the No. 2 Power Boiler and therefore fuel blending is
considered part of the base case for the No. 2 Power Boiler. In Step 3
of the BART analysis, Domtar evaluated the technical feasibility of
each control option. Domtar explained that since wood is inherently low
in nitrogen content, fuel blending is not technically feasible for
wood-fired boilers, and therefore eliminated this as a control option
for Power Boiler No. 1. Regarding FGR, Domtar asserted that only
thermal NOX can be controlled by FGR. As most NOX
emissions from the No. 1 and No. 2 Power Boilers are due to fuel
NOX rather than thermal NOX, Domtar determined
FGR is technically infeasible for both power boilers. Domtar stated
that combustion modification with LNB is used in both gas/oil-fired and
coal fired units, but is not used for wood-fired boilers. Therefore,
Domtar determined use of LNB is technically infeasible for Power Boiler
No. 1. Regarding use of OFA, Domtar stated the source was informed by
one OFA vendor that while OFA results in decreased NOX
emissions, the primary purpose is combustion optimization, and
implementation of OFA can actually increase NOX emissions in
certain circumstances. Based on this, Domtar determined an OFA system
upgrade at Power Boilers No. 1 and 2 is technically infeasible and
eliminated this as a control option for both units in question. Domtar
determined that methane de-NOX is the only technically
feasible NOX control option for Power Boiler No. 1 and
methane de-NOX and LNB are the only two technically feasible
NOX control options for Power Boiler No. 2. In so doing,
Domtar determined that SCR and SNCR are technically infeasible control
options for No. 1 and 2 Power Boilers because they are not suited for
power boilers that experience wide temperature variances and high load
swings. We note a review of the RACT/BACT/LAER Clearinghouse (Process
types 11.120 and 11.190) indicates there are several wood-fired utility
boilers that employ SNCR. In particular, a similar source, the bark
boiler at Temple Inland Kraft Linerboard Mill in Orange, Texas, employs
SNCR, Low Excess Air (LEA), and low NOX gas burners.\59\ The
Temple Inland Kraft boiler has a NOX emission limit of 0.166
lb/MMBtu on a 30 day rolling average. Like the Domtar Power Boilers No.
1 and 2, the Temple Inland Kraft boiler exhibits load swing. We also
note there are other similarities in the operating parameters of the
bark boiler at Temple Inland Kraft and Power Boiler No. 1 (the bark
boiler) at Domtar. Like Power Boiler No. 1 at Domtar, the bark boiler
at Temple Inland Kraft is permitted to burn, among other fuel sources,
bark/wood biomass, natural gas, and tire-derived fuel. The Temple
Inland Kraft bark boiler has a maximum heat input rating of 656 MMBtu/
hr, while Domtar Power Boiler No. 1 has a maximum heat input rating of
580 MMBtu/hr. In conducting its BART analysis, ADEQ and/or Domtar
should have more carefully considered the use of post-combustion
control technologies, such as SNCR, for both power boilers at Domtar,
since SNCR is a control technology that has been used at similar
facilities to control NOX emissions. Because ADEQ eliminated
some of the control options as being technically infeasible in Step 2
of the BART analysis, the subsequent analysis in remaining steps was
incomplete. However, for the sake of providing a fuller picture of our
evaluation of Domtar's BART analysis for NOX for Domtar
Power Boilers No. 1 and 2, we discuss the remaining steps of the BART
analysis.
---------------------------------------------------------------------------

    \59\See the docket for this rulemaking to view the Title V
permit for the Temple Inland Kraft Linerboard Mill.
---------------------------------------------------------------------------

    In Step 3 of the BART analysis, Domtar evaluated the control
effectiveness of the control options it considered technically
feasible. Domtar determined that methane de-NOX has a
potential control efficiency of 50%, whereas LNB has a potential
control efficiency of 30%. In Step 4 of the BART analysis, Domtar
evaluated the cost of compliance for each control option. Domtar
determined the cost-effectiveness of methane de-NOX is
$7,262/ton NOX removed at Power Boiler No. 1 and $4,259/ton
NOX removed at Power Boiler No. 2, while the cost-
effectiveness of LNB is $1,465/ton NOX removed at Power
Boiler No. 1. Domtar eliminated consideration of methane de-
NOX at Power Boilers No. 1 and 2 due to its high cost. Since
Domtar eliminated the only control option considered for Power Boiler
No. 1 prematurely (before evaluating visibility impacts), it
determined, and ADEQ agreed, that there are no NOX controls
available for Power Boiler No. 1 and ADEQ established a BART
NOX emission limit of 0.46 lb/MMBtu on a 30-day rolling
average for Power Boiler No. 1. This would result in no additional
NOX emission reductions at Power Boiler No. 1 beyond
baseline conditions.
    Also based on the cost-effectiveness analysis, Domtar determined
that BART for Power Boiler No. 2 is LNB and ADEQ established a BART
NOX emission limit of 0.45 lb/MMBtu on a 30-day rolling
average for Power Boiler No. 2. After making BART determinations for
the No. 1 and 2 Power Boilers, ADEQ modeled the visibility impacts of
the controls it selected as BART. We note Domtar and ADEQ's approach
for making NOX BART determinations for the No. 1 and 2 Power
Boilers is flawed, as the RHR and the BART Guidelines provide that the
visibility impacts of all technically feasible control options, which
corresponds to Step 5 of the BART analysis, must be considered before a
BART determination is made. ADEQ and Domtar eliminated methane de-
NOX in the BART analysis for Power Boilers No. 1 and 2 due
to high cost before evaluating the visibility impacts of this control
option. Thereby, ADEQ modeled only the visibility impacts of LNB for
Power Boiler No. 2.
    ADEQ stated its post-control visibility modeling demonstrates the
BART determinations for PM, SO2, and NOX for
Power Boilers No. 1 and 2 will result in a combined visibility
improvement of 9.9% at Caney Creek and 12.9% at Upper Buffalo.\60\ We
note this is very

minimal visibility improvement and that there is ample room for the
additional visibility improvement that would result from BART controls
more stringent than those selected by ADEQ and Domtar.
---------------------------------------------------------------------------

    \60\ ADEQ's post-control modeling, showing the visibility
improvement resulting from BART controls, demonstrates that the
visibility impact of Power Boilers No. 1 and 2 combined will be
2.038 [Delta]dv at Caney Creek and 1.029 [Delta]dv at Upper Buffalo
after ADEQ's BART controls are put in place.
---------------------------------------------------------------------------

    We are proposing to find that ADEQ did not properly follow the
requirements of section 51.308(e)(1)(ii)(A) in determining
NOX BART for Power Boilers No.1 and 2. Specifically, we are
proposing that ADEQ did not properly take into consideration ``the
technology available'' and ``the degree of improvement in visibility
which may reasonably be anticipated to result from the use of such
technology.'' We disagree with Domtar and ADEQ's assessment that use of
SNCR at the two power boilers is technically infeasible. In addition,
ADEQ did not model the visibility impacts of all technically feasible
control options before making NOX BART determinations. For
these reasons, we are proposing to disapprove ADEQ's determination that
BART for NOX for Power Boiler No. 1 is a NOX
emission limit of 0.46 lb/MMBtu (which would achieve no NOX
emission reductions beyond the baseline) and that BART for
NOX for Power Boiler No. 2 is a NOX emission
limit of 0.45 lb/MMBtu (achieved by use of LNB).
f. ADEQ BART Results and Summary
    We have reviewed ADEQ's BART determinations for the sources listed
in Table 3, above. For the reasons discussed above, and as discussed in
more detail in the TSD, we are proposing to find that ADEQ has
partially satisfied the BART requirement of section 51.308(e). We are
proposing to find that the BART determinations listed in Table 4
satisfy the BART requirement of section 51.308(e). We are proposing to
find that the BART determinations listed in Table 5 do not satisfy the
BART requirement of section 51.308(e). We are also proposing to find
that the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill are
subject to BART and require a full BART analysis to satisfy the BART
requirement of section 51.308(e).
---------------------------------------------------------------------------

    \61\ Emission limits are based on a 30-day rolling average.

                                                Table 4--BART Determinations Satisfying Section 51.308(e)
--------------------------------------------------------------------------------------------------------------------------------------------------------
           Facility name                   BART emission unit                         Pollutant                          BART emission limit \61\
--------------------------------------------------------------------------------------------------------------------------------------------------------
American Electric Power Flint       Boiler No. 1...................  PM10......................................  existing PM emission limit (0.1 lb/
 Creek Power Plant.                                                                                MMBtu).
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy Lake Catherine Plant......  Unit 4........................  natural gas firing...  SO2..................  No BART Determination.
                                                                                --------------------------------------------------------------
                                                                                PM10.................  existing PM emission limit (45 lb/hr).
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy White Bluff Plant.........  Unit 1........................  bituminous coal        PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                   ---------------------------------------------------------------------------------------------------------------------
                                    Unit 2........................  bituminous coal        PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    PM10.................  existing PM emission limit (0.1 lb/
                                                                     firing.                                       MMBtu).
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

Domtar Ashdown Mill...............  No. 1 Power Boiler.............  PM10......................................  0.07 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                              Table 5--BART Determinations Not Satisfying Section 51.308(e)
--------------------------------------------------------------------------------------------------------------------------------------------------------
           Facility name                   BART emission unit                         Pollutant                           BART emission limit 62
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arkansas Electric Cooperative       Unit 1.........................  SO2.......................................  Use of fuel oil with 1% sulfur content.
 Corporation Carl E. Bailey
 Generating Station.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  No BART Determination.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM........................................  No BART Determination.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arkansas Electric Cooperative       Unit 1.........................  SO2.......................................  Use of fuel oil with 1% sulfur content.
 Corporation John L. McClellan
 Generating Station.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  No BART Determination.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM........................................  No BART Determination.
--------------------------------------------------------------------------------------------------------------------------------------------------------
American Electric Power Flint       Boiler No. 1...................  SO2.......................................  0.15 lb/MMBtu.
 Creek Power Plant.
                                                                    ------------------------------------------------------------------------------------

                                                                     NOX.......................................  0.23 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy Lake Catherine Plant......  Unit 4........................  natural gas firing...  NOX..................  0.15 lb/MMBtu.
                                                                   -------------------------------------------------------------------------------------
                                                                    fuel oil firing......  SO2..................  0.562 lb/MMBtu.
                                                                                --------------------------------------------------------------
                                                                                NOX..................  0.25 lb/MMBtu.
                                                                                --------------------------------------------------------------
                                                                                PM...................  0.037 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Entergy White Bluff Plant.........  Unit 1........................  bituminous coal        SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                --------------------------------------------------------------
                                                                                NOX..................  0.28 lb/MMBtu.
                                                                                --------------------------------------------------------------
                                                                    sub-bituminous coal    SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                --------------------------------------------------------------
                                                                                NOX..................  0.15 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Unit 2........................  bituminous coal        SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                --------------------------------------------------------------
                                                                                NOX..................  0.28 lb/MMBtu.
                                                                   -------------------------------------------------------------------------------------
                                                                    sub-bituminous coal    SO2..................  0.15 lb/MMBtu.
                                                                     firing.
                                                                                --------------------------------------------------------------
                                                                                NOX..................  0.15 lb/MMBtu.
                                   ---------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                    Auxiliary Boiler...............  All.......................................  Boiler to be operated no more than 4360
                                                                                hrs annually.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Domtar Ashdown Mill...............  No. 1 Power Boiler.............  SO2.......................................  1.12 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  0.46 lb/MMBtu.
                                   ---------------------------------------------------------------------------------------------------------------------
                                    No. 2 Power Boiler.............  SO2.......................................  1.2 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     NOX.......................................  0.45 lb/MMBtu.
                                                                    ------------------------------------------------------------------------------------
                                                                     PM10......................................  0.1 lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------

4. Arkansas' Regional Haze Rule
    APC&E Commission Regulation 19, Chapter 15 requires each source
subject to BART to install and operate BART no later than 6 years after
the effective date of ADEQ's regulation or 5 years after we approve
this RH SIP, which ever comes first.\63\
---------------------------------------------------------------------------

    \62\ Emission limits are based on a 30-day rolling average.
    \63\ See Arkansas Pollution Control and Ecology Commission Reg.
19.1504(B).
---------------------------------------------------------------------------

    ADEQ originally submitted Arkansas' RH Rule, the APC&E Commission
Regulation 19, Chapter 15, along with the Arkansas RH SIP, which we
received on September 23, 2008. On August 3, 2010, we received a SIP
revision submittal from ADEQ revising several chapters of APC&E
Commission Regulation 19, including chapter 15. The revisions to
Chapter 15 of APC&E Commission Regulation 19 that we received on August
3, 2010 are mostly non-substantive amendments that revise the original
version of the rule we received on September 23, 2008. Therefore, in
this proposed rulemaking we are proposing to take action on the version
of Chapter 15 of APC&E Regulation 19 contained in the submittal we
received on September 23, 2008, as revised by the submittal received on
August 3, 2010. The only portion of the August 3, 2010 SIP submittal we
are proposing to take action on in this rulemaking is that portion
revising chapter 15 of APC&E Regulation 19. In this proposed
rulemaking, we are not proposing to take action on the portions of the
August 3, 2010 SIP submittal that revise other chapters of APC&E
Commission Regulation 19, as those chapters are not related to regional
haze. We will take action on the revisions to other chapters of APC&E
Commission Regulation 19 at a later time.
    We are proposing to partially approve and partially disapprove
chapter 15 of APC&E Commission Regulation 19. We are proposing to
approve those portions of chapter 15 of APC&E Commission Regulation 19
that incorporate the BART determinations we are proposing to approve
and those portions that are consistent with our overall action on the
Arkansas RH SIP. Specifically, we are proposing to approve the
following sections of chapter 15 of APC&E Commission Regulation 19:
Reg. 19.1501, which establishes the purpose

of the rule; Reg. 19.1502, which incorporates by reference the
definitions contained in 40 CFR 51.301, as in effect on June 22, 2007;
Reg. 19.1503, which identifies the State's BART-eligible sources; the
portion of Reg. 19.1504(A) that identifies AECC Bailey Generating
Station (Unit 1), AECC McClellan Generating Station (Unit 1), Domtar
Ashdown Mill (Power Boilers No. 1 and 2), Lake Catherine (Unit 4),
White Bluff (Units 1, 2, and the Auxiliary Boiler), and AEP Flint Creek
(Boiler No. 1) as subject to BART sources; Reg. 19.1504(B), which
requires each source subject to BART to install and operate BART as
expeditiously as possible, but no later than 6 years after the
effective date of the State's regulation or 5 years after EPA approval
of the RH SIP (whichever comes first); \64\ Reg. 19.1504(C), which
requires each source subject to BART to maintain the control equipment
required by chapter 15, and establish procedures to ensure such
equipment is properly operated and maintained; Reg. 19.1505(A)(3),
which establishes PM BART for AEP Flint Creek Power Plant, Boiler 1;
Reg. 19.1505(D)(3), which establishes PM BART for Domtar Ashdown Mill,
Power Boiler No. 1; Reg. 19.1505(F)(3), which establishes PM BART
(bituminous coal) for Entergy White Bluff, Unit 1; Reg. 19.1505(G)(3),
which establishes PM BART (sub-bituminous coal) for Entergy White
Bluff, Unit 1; Reg. 19.1505(I)(3), which establishes PM BART
(bituminous coal) for Entergy White Bluff, Unit 2; Reg. 19.1505(J)(3),
which establishes PM BART (sub-bituminous coal) for Entergy White
Bluff, Unit 2; Reg. 19.1505(M)(2), which establishes PM BART (natural
gas) for Entergy Lake Catherine Unit 4; Reg.19.1506, which provides the
compliance provisions for the subject to BART sources; and Reg.
19.1507, which provides that the Part 70 permit of each facility
subject to BART shall be subject to re-opening.
---------------------------------------------------------------------------

    \64\ On March 26, 2010, the Arkansas Pollution Control & Ecology
Commission, Arkansas' rulemaking body, granted all Arkansas subject-
to-BART sources a variance from the compliance deadline imposed by
the State's RH Rule, such that these sources are now required to
comply with BART requirements no later than 5 years after EPA
approval of the RH SIP.
---------------------------------------------------------------------------

    We are proposing to disapprove the portion of Chapter 15 of APC&E
Commission Regulation 19 that fails to identify the 6A and 9A Boilers
at the Georgia-Pacific Mill as subject to BART sources, and the
portions that incorporate the State's BART determinations we are
proposing to disapprove. Specifically, we are proposing to disapprove
the following sections of Chapter 15 of the Arkansas Pollution Control
and Ecology Commission Regulation 19: the portion of Reg. 19.1504(A)
that fails to identify the 6A and 9A Boilers at the Georgia-Pacific
Crossett Mill as subject to BART sources; Reg. 19.1505(A)(1), which
establishes SO2 BART for AEP Flint Creek Power Plant, Boiler
1; Reg. 19.1505(A)(2), which establishes NOX BART for AEP
Flint Creek Power Plant, Boiler 1; Reg. 19.1505(B), which establishes
SO2 BART for AECC Bailey Generating Station, Unit 1; Reg.
19.1505(C), which establishes SO2 BART for AECC McClellan
Generating Station, Unit 1; Reg 19.1505(D)(1), which establishes
SO2 BART for Domtar Ashdown Mill, Power Boiler No. 1; Reg.
19.1505(D)(2), which establishes NOX BART for Domtar Ashdown
Mill, Power Boiler No. 1; Reg. 19.1505(E)(1), which establishes
SO2 BART for Domtar Ashdown Mill, Power Boiler No. 2; Reg.
19.1505(E)(2), which establishes NOX BART for Domtar Ashdown
Mill, Power Boiler No. 2; Reg. 19.1505(E)(3), which establishes PM BART
for Domtar Ashdown Mill, Power Boiler No. 2; Reg. 19.1505(F)(1), which
establishes SO2 BART (bituminous coal) for Entergy White
Bluff, Unit 1; Reg. 19.1505(F)(2), which establishes NOX
BART (bituminous coal) for Entergy White Bluff, Unit 1; Reg.
19.1505(G)(1), which establishes SO2 BART (sub-bituminous
coal) for Entergy White Bluff, Unit 1; Reg. 19.1505(G)(2), which
establishes NOX BART (sub-bituminous coal) for Entergy White
Bluff, Unit 1; Reg. 19.1505(H), which provides that when burning a mix
of bituminous and sub-bituminous coal at White Bluff Unit 1, the
NOX BART limits shall be prorated using the percentage of
each coal being used; Reg. 19.1505(I)(1), which establishes
SO2 BART (bituminous coal) for Entergy White Bluff, Unit 2;
Reg. 19.1505(I)(2), which establishes NOX BART (bituminous
coal) for Entergy White Bluff, Unit 2; Reg. 19.1505(J)(1), which
establishes SO2 BART (sub-bituminous coal) for Entergy White
Bluff, Unit 2; Reg. 19.1505(J)(2), which establishes NOX
BART (sub-bituminous coal) for Entergy White Bluff, Unit 2; Reg.
19.1505(K), which provides that when burning a mix of bituminous and
sub-bituminous coal at White Bluff Unit 2, the NOX BART
limits shall be prorated using the percentage of each coal being used;
Reg. 19.1505(L), which establishes BART for Entergy White Bluff,
Auxiliary Boiler; Reg. 19.1505(M)(1), which establishes NOX
BART (natural gas) for Entergy Lake Catherine Unit 4; Reg.
19.1505(N)(1), which establishes SO2 BART (fuel oil) for
Entergy Lake Catherine Unit 4; Reg. 19.1505(N)(2), which establishes
NOX BART (fuel oil) for Entergy Lake Catherine Unit 4; and
Reg. 19.1505(N)(3), which establishes PM BART (fuel oil) for Entergy
Lake Catherine Unit 4.

E. Long-Term Strategy

    As described in section IV.E of this action, the LTS is a
compilation of state-specific control measures relied on by the state
for achieving its RPGs. Arkansas' LTS for the first implementation
period addresses the emissions reductions from federal, state, and
local controls that take effect in the state from the end of the
baseline period starting in 2004 until 2018. The Arkansas LTS was
developed by ADEQ, in coordination with the CENRAP RPO, through an
evaluation of the following components: (1) Construction of a CENRAP
2002 baseline emission inventory; (2) construction of a CENRAP 2018
emission inventory, including reductions from CENRAP member state
controls required or expected under federal and state regulations,
(including BART); (3) modeling to determine visibility improvement and
apportion individual state contributions; (4) state consultation; and
(5) application of the LTS factors.
1. Emissions Inventories
    Section 51.308(d)(3)(iii) requires that Arkansas document the
technical basis, including modeling, monitoring and emissions
information, on which it relied upon to determine its apportionment of
emission reduction obligations necessary for achieving reasonable
progress in each mandatory Class I Federal area it affects. Arkansas
must identify the baseline emissions inventory on which its strategies
are based. Section 51.308(d)(3)(iv) requires that Arkansas identify all
anthropogenic sources of visibility impairment considered by the state
in developing its long-term strategy. This includes major and minor
stationary sources, mobile sources, and area sources. Arkansas met
these requirements by relying on technical analyses developed by its
RPO, CENRAP, and approved by all state participants, as described
below.
    The emissions inventory used in the RH technical analyses was
developed by CENRAP with assistance from Arkansas. ADEQ provided a
statewide emissions inventory for 2002- representing the mid-point of
the 2000-2004 baseline period, and a projected emissions inventory for
2018, the end of the first 10-year planning period. The 2018 inventory
is based on visibility modeling conducted by CENRAP. The 2018 emissions
inventory was

developed by projecting 2002 emissions and applying reductions expected
from federal and state regulations affecting the emissions of the
visibility-impairing pollutants NOX, PM, SO2, and
VOCs.
a. Arkansas' 2002 Emission Inventory
    ADEQ and CENRAP developed an emission inventory for five inventory
source classifications: Point, area, non-road and on-road mobile
sources, and biogenic sources for the baseline year of 2002. Arkansas'
2002 emissions inventory provides estimates of annual emissions for
haze producing pollutants by source category as summarized in Table 6,
based on information in section 7.0 of Arkansas' RH SIP.

                                                       Table 6--Arkansas' 2002 Emissions Inventory
                                                                       [Tons/year]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs            PM10            PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................          92,205               1          72,419          44,329          12,406           7,837
Area....................................................          29,889         152,436          27,450          93,548         148,433          68,000
Non-road mobile.........................................           5,490              49          62,472          54,785           5,673           5,220
On-road mobile..........................................           3,902           2,480         141,894          48,599           3,784           3,021
Biogenic................................................               0               0          18,960       1,385,666               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         131,485         154,967         323,195       1,626,927         170,296          84,078
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2002 emissions inventory was
constructed. We are proposing that Arkansas' 2002 emission inventory is
acceptable.
b. Arkansas' 2018 Emission Inventory
    In constructing Arkansas' 2018 emission inventory, ADEQ used a
combination of our Economic Growth Analysis System (EGAS 6), our mobile
emissions factor model (MOBILE 6), our off-road emissions factor model
(NONROAD), and the Integrated Planning Model (IPM) for electric
generating units. CENRAP developed emissions for five inventory source
classifications: point, area, non-road and on-road mobile sources, and
biogenic sources. CENRAP used the 2002 emission inventory, described
above, to estimate emissions in 2018. All control strategies expected
to take effect prior to 2018 are included in the projected emission
inventory. Arkansas' 2018 emissions inventory provides estimates of
annual emissions for haze producing pollutants by source category as
summarized in Table 7, based on information in section 7.0 of the
Arkansas RH SIP.

                                                       Table 7--Arkansas' 2018 Emissions Inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                SO2             NH3             NOX            VOCs            PM10            PM2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Point...................................................         106,461           2,575          71,107          55,603          19,799          13,775
Area....................................................          31,169         201,722          31,531         107,387         148,592          69,585
Non-road mobile.........................................             211              49          34,305          31,475           3,678           3,387
On-road mobile..........................................             442           3,412          33,640          19,924             949             949
Biogenic................................................               0               0          18,960       1,385,666               0               0
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         138,283         207,758         189,542       1,600,055         173,019          87,695
--------------------------------------------------------------------------------------------------------------------------------------------------------

    See the TSD for details on how the 2018 emissions inventory was
constructed. CENRAP and ADEQ used this and other state's 2018 emission
inventories to construct visibility projection modeling for 2018. We
are proposing that Arkansas' 2018 emission inventory is acceptable.
2. Visibility Projection Modeling
    CENRAP performed modeling for the RH LTS for its member states,
including Arkansas. The modeling analysis is a complex technical
evaluation that began with selection of the modeling system. CENRAP
used (1) The Mesoscale Meteorological Model (MM5) meteorological model,
(2) the Sparse Matrix Operator Kernel Emissions (SMOKE) modeling system
to generate hourly gridded speciated emission inputs, (3) the Community
Multiscale Air Quality (CMAQ) photochemical grid model and (4) the
Comprehensive Air Quality model with extensions (CAMx), as a secondary
corroborative model. CAMx was also utilized with its Particulate Source
Apportionment Technology (PSAT) tool to provide source apportionment
for both the baseline and future case visibility modeling.
    The photochemical modeling of RH for the CENRAP states for 2002 and
2018 was conducted on the 36-km resolution national regional planning
organization domain that covered the continental United States,
portions of Canada and Mexico, and portions of the Atlantic and Pacific
Oceans along the east and west coasts. The CENRAP states' modeling was
developed consistent with our guidance.\65\
---------------------------------------------------------------------------

    \65\ Guidance on the Use of Models and Other Analyses for
Demonstrating Attainment of Air Quality Goals for Ozone,
PM2.5, and Regional Haze, (EPA-454/B-07-002), April 2007,
located at http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf Emissions Inventory Guidance for Implementation of
Ozone and Particulate Matter National Ambient Air Quality Standards
(NAAQS) and Regional Haze Regulations, August 2005, updated November
2005 (``our Modeling Guidance''), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001
---------------------------------------------------------------------------

    CENRAP examined the model performance of the regional modeling for
the areas of interest before determining whether the CMAQ model results
were suitable for use in the RH assessment of the LTS and for use in
the modeling assessment. The 2002 modeling efforts were used to
evaluate air quality/visibility modeling for a historical episode--in
this case, for calendar year 2002--to demonstrate the suitability of
the modeling systems for subsequent planning, sensitivity, and
emissions control strategy modeling. Model performance evaluation is
performed by comparing output from

model simulations with ambient air quality data for the same time
period to determine whether the model's performance is sufficiently
accurate to justify using the model for simulating future conditions.
Once CENRAP determined the model performance to be acceptable, it used
the model to determine the 2018 RPGs using the current and future year
air quality modeling predictions, and compared the RPGs to the URP. The
results of CENRAP's visibility projection modeling are discussed in the
section that follows.
3. Sources of Visibility Impairment
    Visibility impairment in Class I areas is the result of local air
pollution as well as transport of regional pollution across long
distances. CENRAP used CAMx with its Particulate Source Apportionment
Technology (PSAT) tool to provide source apportionment by geographic
region and major source category. The pollutants causing the highest
levels of light extinction are associated with the sources causing the
most visibility impairment.
a. Sources of Visibility Impairment in Caney Creek
    Tables 8 and 9 show the modeled contributions to total extinction
at Caney Creek for each source category and species for 2002 and 2018,
respectively.\66\ Visibility impairment at Caney Creek in 2002 on the
worst 20% days is largely due to SO4 from point sources that
contributes over half (75.1 Mm-\1\) of the total extinction
of 133.93 Mm-\1\. The largest contributions of
SO4 come from Texas (11.55 Mm-\1\ from all source
categories) and the eastern United States (17.98 Mm-\1\).
Overall, the largest source region contributions to visibility
impairment in 2002 are from the eastern United States (19.16
Mm-\1\), Texas (14.89 Mm-\1\), and Arkansas
(13.57 Mm-\1\).
---------------------------------------------------------------------------

    \66\ The species contributing to visibility extinction at Caney
Creek and Upper Buffalo, shown on Tables 8-11, are the following:
sulfate (SO4), nitrate (NO3), primary organic
aerosols (POA), elemental carbon (EC), soil dust, and coarse mass
(CM). These species' precursors are SO2, NOX,
and in some cases, NH3 and VOCs.
---------------------------------------------------------------------------

    In 2018, Arkansas sources will contribute the most to visibility
impairment at Caney Creek, as large reductions in impairment from point
sources in East Texas and the eastern U.S. will occur while
SO4 emissions, particularly from point sources, are expected
to increase in Arkansas. The 2018 projection shows the total extinction
at Caney Creek for the worst 20% days is estimated to be 85.84
Mm-\1\, a reduction of approximately 36% from 2002 levels.
Anticipated reductions of SO4 emissions from point sources
in Texas, the eastern United States, Indiana, and Ohio will account for
a decrease of 24.41 Mm-\1\ in total light extinction, which
is approximately half of the total expected reduction between 2002 and
2018. Even with such large expected reductions in SO4
emissions from point sources in 2018, extinction due to point sources
will still be the highest contributor to visibility impairment on the
worst 20% days, accounting for over half of the total extinction.
Visibility impairment from all Arkansas sources will decrease by 2.32
Mm-\1\, almost entirely due to expected reductions from
mobile sources. Total reductions in NO3 emissions from
mobile sources will contribute a decrease in total extinction of
approximately 9 Mm-\1\. There is an under-prediction bias in
the model that must be considered when examining source apportionment
results for SO4. Use of a 12 km resolution modeling grid in
CAMX reduced the summertime SO4 bias but required large
computational expense. The use of higher resolution modeling should be
reconsidered in future modeling efforts.

                              Table 8--Projected 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 and secondary organic matter.

                              Table 9--Projected 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.

b. Sources of Visibility Impairment in Upper Buffalo
    Tables 10 and 11 show the contributions to total extinction at
Upper Buffalo for each source category and species for 2002 and 2018,
respectively. Visibility impairment at Upper Buffalo in 2002 on the
worst 20% days is largely due to SO4 from point sources that
contributes over half (72.17 Mm-\1\) of the total extinction
of 131.79 Mm-\1\. The largest contributions of visibility
impairment due to SO4 come from the eastern United States
(18.56 Mm-\1\), Indiana (9.79 Mm-\1\), Illinois
(8.06 Mm-\1\), and Kentucky (6.93 Mm-\1\).
Overall, the largest source region contributions to visibility
impairment in 2002 are from the eastern United States (20.00
Mm-\1\), Arkansas (13.47 Mm-\1\), Indiana (10.20
Mm-\1\), Illinois (9.64 Mm-\1\), and Missouri
(9.60 Mm-\1\).
    In 2018, Arkansas sources will contribute the most to visibility
impairment at Upper Buffalo, as large reductions in impairment from
point sources in Indiana, Illinois, Ohio and the eastern U.S. will
occur while SO4 emissions, particularly from point sources,
are expected to increase in Arkansas. The 2018 projection shows the
total extinction at Upper Buffalo for the worst 20% days is estimated
to be 86.16 Mm-\1\, a reduction of approximately 35% from
2002 levels. Anticipated reductions of SO4 emissions from
point sources in the eastern United States, Indiana, Illinois, Kentucky
and Ohio will account for a decrease of 28.43 Mm-\1\ in
total light extinction, more than 60% of the total expected reduction
in impairment between 2002 and 2018. Even with such large expected
reductions in SO4 emissions from point sources in 2018,
extinction due to point sources will still be the highest contributor
to visibility impairment on the worst 20% days, accounting for
approximately half of the total extinction. Visibility impairment from
all Arkansas sources will decrease by 1.45 Mm-\1\, due to
expected reductions from mobile sources. Total reductions in
NO3 emissions from mobile sources will contribute a decrease
in total extinction of approximately 8.5 Mm-\1\. There is an
under-prediction bias in the model that must be considered when
examining source apportionment results forSO4. Use of a 12
km resolution modeling grid in CAMX reduced the summertime sulfate bias
but required large computational expense. The use of higher resolution
modeling should be reconsidered in future modeling efforts.

                            Table 10--Projected Light Extinction for 20% Worst Days 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 and secondary organic matter.

                            Table 11--Projected 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.

c. Arkansas' Contribution to Visibility Impairment in Class I Areas
Outside the State
    CAMx PSAT results were also utilized to evaluate the impact of
Arkansas emission sources in 2002 and 2018 on visibility impairment at
Class I areas outside of the state. Arkansas sources are modeled to
have contributions to the Class I areas in Missouri (Hercules-Glades
and Mingo). Outside of Arkansas and Missouri, the largest contribution
from Arkansas sources is at the Wichita Mountains Class I area in
Oklahoma, amounting to 2.0% of the visibility impairment at Wichita
Mountains in 2002 and 2.3% in 2018. Arkansas is also projected to
contribute a small amount of visibility degradation at Class I areas in
other states listed in Table 12. We agree that additional emission
reductions in Arkansas, beyond those controlled through BART
requirements, are not necessary to protect visibility at Class I areas
outside of the state at this time. Table 12 summarizes the projected
contribution from Arkansas emissions on visibility degradation at 9
Class I areas for the 20 percent worst days in 2002 and 2018, as
modeled by CENRAP.\67\
---------------------------------------------------------------------------

    \67\ See Appendix E of the TSD for CENRAP Emissions and Air
Quality Modeling To Support Regional Haze State Implementation,
found in Appendix 8.1 of the Arkansas RH SIP.

  Table 12--Percent Contribution From Arkansas Emissions to Total Visibility Impairment at Class I Areas on 20%
                                                 Worst Days \68\
----------------------------------------------------------------------------------------------------------------
                Class I area                               State               2002 (percent)    2018 (percent)
----------------------------------------------------------------------------------------------------------------
Upper Buffalo...............................  Arkansas......................              10.2              14.0
Caney Creek.................................  Arkansas......................              10.1              13.1
Hercules Glades.............................  Missouri......................               5.9               7.6
Mingo.......................................  Missouri......................               3.3               4.4
Wichita Mountains...........................  Oklahoma......................               2.0               2.3
Mammoth Cave................................  Kentucky......................               1.0               1.8
Bondville...................................  Illinois......................               1.2               1.5
Breton Island...............................  Louisiana.....................               1.1               1.3
Cadiz.......................................  Kentucky......................               0.9               1.2
----------------------------------------------------------------------------------------------------------------

4. Consultation and Emissions Reductions for Other States' Class I
Areas
    As in the development of Arkansas' RPGs for Caney Creek and Upper
Buffalo, ADEQ used CENRAP as its main vehicle for facilitating
collaboration with FLMs and other states in satisfying its LTS
consultation requirement. This helped ADEQ and other state
environmental agencies analyze emission apportionments at Class I areas
and develop coordinated RH SIP strategies.
---------------------------------------------------------------------------

    \68\ Contributions less than 1% were excluded from Table 12.
---------------------------------------------------------------------------

    Section 51.308(d)(3)(i) requires that Arkansas consult with other
states if its emissions are reasonably anticipated to contribute to
visibility impairment at that state's Class I area(s), and that
Arkansas consult with other states if those states' emissions are
reasonably anticipated to contribute to visibility impairment at Caney
Creek and Upper Buffalo. ADEQ's consultations with other states are
described in section V.C.3 above. The CENRAP visibility modeling
demonstrates Arkansas sources are responsible for a visibility
extinction of approximately 7.1 inverse megameters \69\
(Mm-1) at Hercules Glades and for a visibility extinction of
approximately 4.95 Mm-1 at Mingo on the worst 20% days for
2002.\70\ ADEQ consulted with Missouri, as well as with several other
states whose emissions have a potential visibility impact at Caney
Creek and Upper Buffalo. As already discussed elsewhere in this
proposed notice, ADEQ neither requested additional emission reductions
from other states, nor made a commitment to other states for additional
emission reductions beyond those already factored in to the CENRAP's
photochemical modeling for the 2018 visibility projections. All states
participating in ADEQ's consultation process agreed with this decision.
---------------------------------------------------------------------------

    \69\ An inverse megameter is the direct measurement unit for
visibility impairment data. It is the amount of light scattered and
absorbed as it travels over a distance of one million meters.
Deciviews (dv) can be calculated from extinction data as follows: dv
= 10 x ln (bext(Mm-1)/10).
    \70\ See Appendix E of the TSD for CENRAP Emissions and Air
Quality Modeling To Support Regional Haze State Implementation,
found in Appendix 8.1 of the Arkansas RH SIP.
---------------------------------------------------------------------------

    We are proposing to find that ADEQ's consultations satisfy the
requirements under section 51.308(d)(3)(i) and (ii).
5. Mandatory Long Term Strategy Factors
    Section 51.308(d)(3)(v) requires that Arkansas consider certain
factors in developing its long-term strategy (the LTS factors). These
include: (1) Emission reductions due to ongoing air pollution control
programs, including measures to address RAVI; (2) measures to mitigate
the impacts of construction activities; (3) emissions limitations and
schedules for compliance to achieve the reasonable progress goal; (4)
source retirement and replacement schedules; (5) smoke management
techniques for agricultural and forestry management purposes including
plans as currently exist within the state for these purposes; (6)
enforceability of emissions limitations and control measures; and (7)
the anticipated net effect on visibility due to projected changes in
point, area, and mobile source emissions over the period addressed by
the long-term strategy. For the reasons outlined below, we are
proposing to find that Arkansas has not satisfied all the requirements
of Section 51.308(d)(3)(v).
a. Reductions Due to Ongoing Air Pollution Programs
    In addition to its BART determinations, Arkansas' LTS incorporates
emission reductions due to a number of ongoing air pollution control
programs. This includes EPA's Clean Air Interstate Rule (CAIR), which
was expected to cap Arkansas' ozone season trading budget for annual
NOx allocations at 9,596 tons by 2015. Consistent with EPA guidance and
regulations (see 70 FR 39104, 39106 (July 6, 2005)), many states relied
on EPA's Clean Air Interstate Rule (CAIR) to satisfy key elements of
Regional Haze SIPs. The D.C. Circuit, however, found CAIR to be
inconsistent with the requirements of the Act and remanded the rule to
the Agency. North Carolina v. EPA, 531 F.3d 896, 929-30 (D.C. Cir.
2008); modified on rehearing, North Carolina v. EPA, 550 F.3d 1176,
1178 (D.C. Cir. 2008). In response to the remand of the CAIR rule, on
July 6, 2011, EPA finalized the Transport Rule, also known as the
Cross-State Air Pollution Rule (CSAPR), a rule intended to reduce the
interstate transport of fine particulate matter and ozone (see 76 FR
48208). Since Arkansas was subject to CAIR only for ozone season NOx,
its Regional Haze SIP did not rely on CAIR to meet the requirements for
BART or for attaining the in-state emissions reductions necessary to
ensure reasonable progress. Instead, Arkansas evaluated controls for
its potential BART sources. Arkansas made BART determinations for its
subject to BART sources, including Electric Generating Units (EGUs)
that might have been controlled under CAIR. Controls on these sources
are an element of Arkansas' LTS for attaining the RPGs at Caney Creek
and Upper Buffalo. In terms of the LTS, EPA anticipates that the
Transport Rule will result in similar or better improvements in
visibility than those predicted from CAIR at Class I areas in Arkansas.
As a result, we do not expect the remand of CAIR to have a significant
negative effect on the ability of Arkansas' LTS to ensure that Caney
Creek and Upper Buffalo meet the RPGs in the State's RH SIP. We note
that to assess whether a state's current strategies will be sufficient
to meet its RPGs, the RHR requires a midcourse review by each state
and, if necessary, a correction of the state's regional haze plan. See
40 CFR 52.308(g). If for a particular Class I area, the emissions
reductions resulting from the Transport

Rule do not provide similar or greater benefits than CAIR and if
meeting the RPGs at one of its Class I areas is in jeopardy, the State
will be required to address this circumstance in its five year review.
    ADEQ also considered the Tier 2 Vehicle Emission Standards in
developing its LTS. Federal Tier 2 Vehicle Emission Standards for
passenger cars and light trucks were fully implemented in 2007 and
similar rules for heavy trucks were scheduled to be implemented by
2009. These federal standards will result in reductions of emissions of
PM, ozone precursors, and non-methane organic compounds. In developing
its LTS, ADEQ also considered the Highway Diesel and Nonroad Diesel
Rules, which mandated the use of lower sulfur fuels in diesel engines
beginning in 2006 for highway diesel fuel, and 2007 for nonroad diesel
fuel. These federal rules have resulted in more effective control of PM
emissions from diesel engines by allowing the installation of control
devices that were technically infeasible for fuels with higher sulfur
content.
    We approved Arkansas' Visibility Protection SIP on February 10,
1986 (51 FR 4910). We approved Arkansas' Part II Visibility Protection
SIP, which addresses reasonably attributable visibility impairment
(RAVI) at Caney Creek and Upper Buffalo, on July 21, 1988 (53 FR
27514). As we note in section IV.H of this proposed notice, the FLMs
did not identify any integral vistas in Arkansas. In addition, Caney
Creek and Upper Buffalo are not experiencing RAVI, nor are any Arkansas
sources affected by the RAVI provisions. For this reason, the Arkansas
RH SIP does not incorporate any measures to specifically address RAVI.
b. Measures To Mitigate the Impacts of Construction Activities
    Section 51.308(d)(3)(v)(B) requires that Arkansas consider measures
to mitigate the impacts of construction activities in developing its
LTS. Construction-related activities are believed to be a small
contributor to fine and coarse particulates. ADEQ notes that since the
Arkansas Water and Air Pollution Control Act does not apply to land
clearing, land grading, or road construction operations, ADEQ has
limited opportunities to mitigate air emissions resulting from
construction activities. However, ADEQ notes the federal General
Conformity program requires assessment of the potential impacts of any
construction-related emissions of criteria pollutants from federal
projects in areas that have been designated as not attaining the
National Ambient Air Quality Standards (NAAQS) for that pollutant. ADEQ
also participates in the Blue Skyways Collaborative, a regional group
that works collaboratively on the introduction of innovative, regional-
scale, transportation-related programs and projects. The State has
directed grant funds to fleet managers and equipment suppliers as a
means of subsidizing diesel retrofits and the biodiesel market.
c. Emissions Limitations and Schedules of Compliance
    Section 51.308(d)(3)(v)(C) requires that in developing its LTS,
Arkansas consider emissions limitations and schedules of compliance to
achieve the RPGs. The SIP contains emission limits and schedules of
compliance for those sources subject to BART: the AECC Bailey Unit 1;
the AECC McClellan Unit 1; the AEP Flint Creek Boiler No. 1; the
Entergy Lake Catherine Unit 4; the Entergy White Bluff Units 1, 2, and
the Auxiliary Boiler; and the Domtar Power Boilers No. 1 and 2. The
schedules for implementation of BART for these sources are identified
in Section 9.3 of the RH SIP and in the State's RH Rule included in
Appendix 9.3C of the SIP. The BART emission limits established by ADEQ
are an element of the LTS, and since we are proposing to disapprove a
portion of ADEQ's BART determinations, we cannot propose to approve
this element of the LTS.
d. Source Retirement and Replacement Schedules
    Section 51.308(d)(3)(v)(D) requires that Arkansas consider source
retirement and replacement schedules in developing its LTS. ADEQ stated
retirement and replacement will be managed in conformance with existing
SIP requirements pertaining to the Prevention of Significant
Deterioration (PSD) and the New Source Review (NSR) programs. ADEQ
notes source retirement and replacement will be tracked through on-
going point source inventories.
e. Agricultural and Forestry Smoke Management Techniques
    Section 51.308(d)(3)(v)(E) requires that Arkansas consider smoke
management techniques for agricultural and forestry management purposes
in developing its LTS. ADEQ considered smoke management techniques for
the purposes of agricultural and forestry management in its LTS.
Regulation 18 of the Arkansas Pollution Control and Ecology Commission
contains a general prohibition on ``open burning of refuse, garbage,
trade waste, or other waste material,'' but exempts controlled fires
used for forest and wildlife management and certain agricultural
activities (ADEQ Reg. 18.602-18.603). In 2007, the Arkansas Forestry
Commission approved revisions to the Arkansas Smoke Management Program
(SMP). The Arkansas SMP is designed to assure that prescribed fires are
planned and executed in a manner designed to minimize impacts
associated with the smoke produced by prescribed fires. The Arkansas
SMP recommends a written fire plan that includes measures that can be
taken to reduce residual smoke from burning activities. The Arkansas
SMP also includes a process to evaluate potential smoke impacts at
sensitive receptors and guidelines for scheduling fires such that
exposure of sensitive populations is minimized and visibility impacts
in Class I areas are avoided.
f. Enforceability of Emissions Limitations and Control Measures
    Section 51.308(d)(3)(v)(F) requires that Arkansas ensure the
enforceability of emission limitations and control measures used to
meet reasonable progress goals. ADEQ has ensured that all emission
limitations and control measures used to meet RPGs are enforceable by
incorporating these into State regulations.\71\ The State's RH Rule,