boiler volume or decreasing the heat input rate. For these reasons, OFA
was not considered further.
    LEA is not compatible with the design of the boiler. The boiler is
a stoker boiler that operates on the principle of creating an even
release of heat across the entire grate. In order to achieve optimal
conditions, sufficient air flow is required from beneath the grate. In
addition sufficient air flow is needed to keep the grate and parts
exposed to combustion material below their maximum operating
temperatures. For these reasons, LEA is not considered further.
    Similarly, FGR creates a LEA condition, but may not affect the
under fire air needed to properly operate the stoker grate system. In
order to prevent high loss on ignition and increased emissions
associated with incomplete combustion (and the LEA condition) the
volume of the boiler's combustion chamber would likely need to be
increased to maintain the current steam rate and overall heat release
rate, and thus is not compatible with the design of the boiler. FGR is
a technique with multiple mechanisms for reducing NOX,
including reducing the available oxygen, since some exhaust gas
replaces oxygen rich ambient air. For this reason, FGR is not
considered further.
Step 3: Evaluate Control Effectiveness of Remaining Control
Technologies
    Baseline NOX emissions from the boiler are 587 tpy. A
summary of emissions projections for RSCR and SNCR, the only remaining
control technologies, are provided in Table 178. Further information
can be found in the docket.

                Table 178--Summary of Boiler NOX Reasonable Progress Analysis Control Technology
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
SNCR......................................................                35               205               382

RSCR......................................................                75               440               147
----------------------------------------------------------------------------------------------------------------

Factor 1: Costs of Compliance
    Table 179 provides a summary of estimated annual costs and cost
effectiveness for SNCR and RSCR.

   Table 179--Summary of Boiler NOX Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
SNCR................................          $294,377            $1,436
\1\ RSCR............................           748,097             1,700
------------------------------------------------------------------------
\1\ Further information on our cost calculation can be found in the
  docket in the document titled Reasonable Progress (RP) Four-Factor
  Analysis of Control Options for Roseburg Forest Products Co./Missoula
  Particleboard (a similar type source to Plum Creek's boiler).

    For SNCR, we are adopting cost figures provided by Plum Creek,\288\
except that we annualized the capital cost by multiplying the capital
cost by a CRF that corresponds to a 7% interest rate and 20-year
equipment life (which yields a CRF of 0.0944), as specified in the
Office of Management and Budget's Circular A-4, Regulatory
Analysis.\289\ For RSCR, we are adopting the total annual cost for RSCR
for the SolaGen sander dust burner at Roseburg Forest Products. This is
likely an underestimation of the cost for the boiler dryers at Plum
Creek, because the boiler at Plum Creek is larger than the SolaGen
sander dust burner at Roseburg.
---------------------------------------------------------------------------

    \288\ Plum Creek Revised Response, Table C-4 (Mar. 13, 2012).
    \289\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

Factor 2: Time Necessary for Compliance
    RSCR systems can be operational within eight months to one year.
Because RSCR includes much of the equipment needed for SNCR, with
additional equipment (the catalyst for instance), we have assumed that
SNCR could be installed within a similar timeframe to that quoted for
RSCR. Therefore, SNCR also can be installed and operational within
eight months to one year.
Factor 3: Energy and Non-Air Quality Environmental Impacts of
Compliance
    RSCR requires the reheat of the flue gas, either through a heat
exchanger that uses plant waste heat, and/or through direct reheat of
the flue gas by additional combustion or electrically powered heating
elements. Although specific estimates of resources needed to operate
RSCR on the Columbia Falls boiler were not available, we have examined
estimates presented for a similar source (Roseburg Forest Products) to
illustrate the approximate quantity of resources needed to run a RSCR
system. Table 180 provides estimates of these additional resources that
are necessary for RSCR.

              Table 180--Additional Ammonia, Natural Gas, Electricity, and Steam Required for RSCR
----------------------------------------------------------------------------------------------------------------
                                     Ammonia (NH3)        Natural gas         Electricity            Steam
----------------------------------------------------------------------------------------------------------------
RSCR usage per system...........  300,000 to 400,000  2 million scf/year  930,000-5.4         42.5-125 lb/hr or
                                   gal/year.           to 9.7 million      million kWh/year.   186-548 tpy.
                                                       scf/year.
----------------------------------------------------------------------------------------------------------------

    Additionally, the RSCR catalyst may have the potential to emit
NH3 (as NH3 slip) and generate nitrous oxide if
not operated optimally. Catalysts must be disposed of, presenting a
cost; however, many catalyst manufacturers provide a system to
regenerate or recycle the catalyst reducing the impacts associated with
spent catalysts. In addition to these considerations, there are issues
associated with the production, transport, storage, and use of
NH3. However, regular handling of NH3 has reduced
the risks associated with its transport, storage, and use.
    As with RSCR, there are issues associated with NH3,
electricity, and compressed air for SNCR. Although specific estimates
of resources needed to operate SNCR on the Columbia Falls boiler were
not available, we have examined estimates presented for a similar
source (Roseburg Forest Products) to illustrate the approximate
quantity of resources needed to run a SNCR system. Table 181 provides
estimates for additional reagent, electricity and steam use.

                     Table 181--Additional Reagent, Electricity and Steam Required for SNCR
----------------------------------------------------------------------------------------------------------------
                                            Reagent (Urea)            Electricity                 Steam
----------------------------------------------------------------------------------------------------------------
Boiler SNCR System...................  165 tpy or 69,740        204,108 kWh/year.......  51.4 lb/hr or 225 tpy.
                                        gallons Urea solution/
                                        year.
----------------------------------------------------------------------------------------------------------------

    As with RSCR, some level of NH3 slip will be present,
which is dependent on the amount of reagent injected and the level of
control that is desired. Higher levels of control are associated with
greater NH3 slip. Whether urea or NH3 is used,
there are impacts associated with the production, transport, storage,
and use of these chemicals. If urea is used, there will be GHG
emissions associated with its hydrolysis prior to its use as a
NOX reagent.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: The cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the sources. We are also taking into account the size of the
facility, the baseline Q/D of the facility, and the potential reduction
in Q/D from the controls. We propose to eliminate the most expensive
option (RSCR), based on costs of compliance and the relatively small
size of this facility. The less expensive option (SNCR) would reduce
emissions by 205 tpy, which equates to approximately an 18.5% reduction
in overall emissions of SO2 + NOX from the
facility, or a reduction of Q/D from 82 to 67. Based on the relatively
small size of this facility, the baseline Q/D, and the reduction in Q/
D, we propose to find it reasonable to eliminate this option.
Therefore, we are proposing to not require any NOX controls
for this planning period.
Line 1 Sander Dust Burners
Step 1: Identify All Available Technologies
    The Line 1 sander dust burners do not currently have post-
combustion or low NOX combustion technology. We identified
the following technologies to be available: SCR, RSCR, SNCR, SNCR/SCR
hybrid, staged combustion, fuel staging, LNB, OFA, LEA, and FGR. SCR,
SNCR, LNB, OFA, LEA and FGR were described in our analysis for CELP.
RSCR, SNCR/SCR hybrid, staged combustion, and fuel staging were
described in our analysis for Plum Creek's Riley Union boiler.
Step 2: Eliminate Technically Infeasible Options
    For the Line 1 sander dust burners, PM loadings are too high for a
hot/high dust SCR, and temperatures are too cool following the PMCD
unless reheat is used. In addition to these issues, the dryer burners
are direct contact dryers. Therefore, any NH3 in the gas
stream from a hot/high dust SCR would have the potential to stain or
darken the wood product. For these reasons, SCR was not considered
further.
    The exhaust from the Line 1 sander dust burners acts as a direct
contact heat source for the drying processes at the facility. The use
of SNCR would require injection of the reagent prior to the dryers
introducing NH3 to the product lines. Contact with
NH3 may result in reduced product quality. NH3
darkens wood, which would not be acceptable for Plum Creek's light
colored stains. Additionally, NH3 may affect the curing of
any formaldehyde-based resins used in the wood products. High levels of
NH3 reduce the cellulosic structure of the wood, allowing it
to be permanently shaped; however compressive strength is reduced,
which is an important factor for product quality. Space constraints
also are a consideration because there is not sufficient residence time
at the required temperatures in the exhaust stream prior to the
location where the exhaust comes into contact with the wood products;
therefore, there is a likelihood that the conversion of the
NH3 reagent may not be sufficiently completed before the
exhaust enters the dryers, making product quality a concern (as stated
above). For these reasons, SNCR was not considered further.
    Because the PM concentrations in the exhaust of the sander dust
burners would require the PM controls to precede the catalyst section
of the hybrid system, reheat would be required. RSCR is considered to
be feasible without firebox/SNCR injection, therefore SNCR/SCR hybrid
systems were not considered further.
    Fuel staging is not feasible for the Line 1 sander dust burners.
The Line 1 sander dust burners have a combustion chamber that is too
small to accommodate fuel staging; therefore, fuel staging was not
considered further.
    Staged combustion is not compatible with the Line 1 sander dust
burners. The Line 1 sander dust burners have a combustion chamber that
is one-quarter the volume of the Line 2 sander dust burner. Staged
combustion techniques increase the volume (or size) of the flame front
for a given heat input rate; therefore it would be necessary to reduce
the overall heat input of the burners to achieve lower flame
temperatures and thereby realize the NOX reduction
achievable with staged combustion techniques. A reduction in the heat
rate to the Line 1 sander dust burners would result in insufficient
heat being sent into the drying process.
    As stated above in the Step 2 discussion of staged combustion,
there is insufficient combustion chamber volume to implement LNB design
for the Line 1 sander dust burners; therefore, LNB are considered to be
technically infeasible for the Line 1 sander dust burners without
increasing combustion chamber volume or decreasing the heat input rate
(which would affect Plum Creek's ability to successfully operate the
wood product dryers). For this reason, LNB was not considered further.
    As also discussed above, there is insufficient combustion chamber
volume to implement OFA on the Line 1 burners without decreasing the
heat input rate. The reduced heat input rate would prevent the dryers
from operating as designed. For this reason, OFA was not considered
further.
    LEA is considered to be technically infeasible for the Line 1
sander dust burners because sander dust suspension burners require high
levels of air in order to fluidize the solid fuel. Poor operation of
the burners would result with LEA since high excess air conditions are
necessary to sustain stable combustion. The Line 1 dryers are all
suspension burners, and therefore LEA is considered technically
infeasible for these sources.
    Because FGR depends on the same conditions as LEA and LEA is
considered technically infeasible for the Line 1 sander dust burners,
FGR is also

considered infeasible for the Line 1 sander dust burners. Additionally,
FGR may require additional combustion chamber volume to accommodate the
same heat input while maintaining a reduced flame temperature. For
these reasons, FGR was not considered further.
Step 3: Evaluate Control Effectiveness of Remaining Control
Technologies
    Baseline NOX emissions from the Line 1 sander dust
burners are 319 tpy. A summary of emissions projections for RSCR, the
only remaining control technology, is provided in Table 182. Further
information can be found in the docket.

                Table 182--Summary of Line 1 NOX Reasonable Progress Analysis Control Technology
----------------------------------------------------------------------------------------------------------------
                                                              Control           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    emissions (tpy)
----------------------------------------------------------------------------------------------------------------
RSCR...................................................                75                240                 79
----------------------------------------------------------------------------------------------------------------

Factor 1: Costs of Compliance
    Table 183 provides a summary of estimated annual costs and cost
effectiveness for RSCR.

   Table 183--Summary of Line 1 NOX Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual cost  effectiveness ($/
                                           ($)                ton)
------------------------------------------------------------------------
\1\ RSCR..........................           748,097              3,117
------------------------------------------------------------------------
\1\ Further information on our cost calculation can be found in the
  docket in the document titled Reasonable Progress (RP) Four-Factor
  Analysis of Control Options for Roseburg Forest Products Co./Missoula
  Particleboard (a similar type source to Plum Creek).

    For RSCR, we are adopting the total annual cost for RSCR for the
SolaGen sander dust burner at Roseburg Forest Products. This is likely
an underestimation of the cost for the Line 1 sander dust burners at
Plum Creek, because the Line 1 sander dust burners are smaller than the
SolaGen sander dust burner at Roseburg.
Factor 2: Time Necessary for Compliance
    RSCR systems for the Line 1 sander dust burners could be
operational within eight months to one year.
Factor 3: Energy and Non-Air Quality Environmental Impacts of
Compliance
    The energy and non-air quality environmental impacts from RSCR were
discussed in the analysis for the boiler. Specific reagent, electricity
and steam requirements were not calculated for the Line 1 sander dust
burners but are expected to be less than what would be needed for the
boiler.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: The cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the sources. We are also taking into account the size of the
facility, the baseline Q/D of the facility, and the potential reduction
in Q/D from the controls. The emissions reductions from the only
feasible option (RSCR) would be fairly small (240 tpy), which would
result in approximately 21.7% reduction in overall emissions of
SO2 + NOX for this facility, or a reduction of Q/
D from 82 to 64. Based on the costs of compliance, the relatively small
size of the facility, and the reduction in Q/D, we think it reasonable
to not impose RSCR for this facility. Therefore, we are proposing to
not require any NOX controls on this unit for this planning
period.
Line 2 Sander Dust Burner
Step 1: Identify All Available Technologies
    The line 2 sander dust burner uses staged combustion to control
NOX. We identified the following technologies to be
available: SCR, RSCR, SNCR, SNCR/SCR hybrid, staged combustion, fuel
staging, LNB, OFA, LEA, and FGR. SCR, SNCR, LNB, OFA, LEA and FGR were
described in our analysis for CELP. RSCR, SNCR/SCR hybrid, staged
combustion, and fuel staging were described in our analysis for Plum
Creek's boiler.
Step 2: Eliminate Technically Infeasible Options
    All of the sander dust burners have the same issues associated with
the implementation of SCR as the boiler. PM loadings are too high for a
hot/high dust SCR, and temperatures are too cool following PM control
unless reheat is used. In addition to these issues, the dryer burners
are all direct contact dryers. Therefore, any NH3 in the gas
stream from a hot/high dust SCR would have the potential to stain or
darken the wood product. For these reasons, SCR was not considered
further.
    The exhaust from the Line 2 sander dust burner acts as a direct
contact heat source for the drying processes at the facility. Using
SNCR on the Line 2 sander dust burner would cause the same product
quality issues that were explained in the analysis for the Line 1
sander dust burners. Space constraints are also an issue as explained
for the Line 1 sander dust burners. For these reasons, SNCR was not
considered further.
    As explained in the analysis for the Line 1 sander dust burners,
the PM concentrations in the exhaust of the sander dust burners would
require the

PM controls to precede the catalyst section of the hybrid system, and
so reheat would be required. RSCR is considered to be feasible without
firebox/SNCR injection; therefore SNCR/SCR Hybrid systems were not
considered further.
    Fuel staging is not feasible for the Line 2 sander dust burner. The
Line 2 sander dust burner uses staged combustion. Further modification
of the combustion chamber would be required to use fuel staging;
however, space constraints would make the expansion infeasible. Also,
additional NOX reductions would not likely be realized
because the staged combustion design has already reduced thermal
NOX to the extent possible. For these reasons, fuel staging
is not considered further.
    The Line 2 sander dust burner already uses staged combustion,
therefore further staging would not be technically feasible without
complete replacement.
    LNB (or staged combustion) is a technique that was designed into
the Line 2 sander dust burner; therefore, further staging, or LNB
configuration was not considered further.
    The Line 2 sander dust burner uses staged combustion. Further
modification of the combustion chamber would be required to use fuel
staging; however, space constraints would make the expansion
infeasible. Also, further NOX reductions would not likely be
realized because the staged combustion design has already reduced
thermal NOX to the extent possible. For these reasons, fuel
staging is not considered further.
    The Line 2 sander dust burner already employs staged combustion;
therefore, further staging through the use of OFA is technically
infeasible. For this reason, OFA was not considered further.
    LEA is considered to be technically infeasible for the Line 2
sander dust burner because sander dust suspension burners require high
levels of air in order to fluidize the solid fuel. Poor operation of
the burners would result with LEA since high excess air conditions are
found under the conditions necessary to sustain stable combustion. The
Line 2 dryers are all suspension burners, and therefore LEA is
considered technically infeasible for these sources. For these reasons,
LEA was not considered further.
    FGR is not technically feasible for the Line 2 sander dust burner
for the same reasons as were described under the analysis for the Line
1 sander dust burners. Because FGR causes a LEA condition and LEA is
considered technically infeasible for the Line 2 sander dust burner,
FGR has also been considered to be infeasible for the Line 2 sander
dust burner. Also, FGR may require additional combustion chamber volume
to accommodate the same heat input while maintaining a reduced flame
temperature. For these reasons, FGR was not considered further.
Step 3: Evaluate Control Effectiveness of Remaining Control
Technologies
    Baseline NOX emissions from the Line 2 sander dust
burner are 200 tpy. A summary of emissions projections for RSCR, the
only remaining control technology, is provided in Table 184.

                Table 184--Summary of Line 2 NOX Reasonable Progress Analysis Control Technology
----------------------------------------------------------------------------------------------------------------
                                                              Control           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    emissions (tpy)
----------------------------------------------------------------------------------------------------------------
RSCR...................................................                75                150                 50
----------------------------------------------------------------------------------------------------------------

Factor 1: Costs of Compliance
    Table 185 provides a summary of estimated annual costs and cost
effectiveness for RSCR.

   Table 185--Summary of Line 2 NOX Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual cost  effectiveness ($/
                                           ($)                ton)
------------------------------------------------------------------------
\1\ RSCR..........................           748,000              4,987
------------------------------------------------------------------------
\1\ Further information on our cost calculation can be found in the
  docket in the document titled Reasonable Progress (RP) Four-Factor
  Analysis of Control Options for Roseburg Forest Products Co./Missoula
  Particleboard (a similar type source to Plum Creek's boiler).

    For RSCR, we are adopting the total annual cost for RSCR for the
SolaGen sander dust burner at Roseburg Forest Products. This is likely
an underestimation of the cost for the Line 2 sander dust burner
because the line 2 sander dust burner at Plum Creek is larger than the
SolaGen sander dust burner at Roseburg.
Factor 2: Time Necessary for Compliance
    RSCR systems for the Line 2 sander dust burner could be operational
within eight months to one year.
Factor 3: Energy and Non-Air Quality Environmental Impacts of
Compliance
    The energy and non-air quality environmental impacts from RSCR were
discussed in the analysis for the boiler. Specific reagent, electricity
and steam requirements were not calculated for the Line 2 sander dust
burner, but are expected to be less than what would be needed for the
boiler.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: The cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the sources. We are also taking into account the size of the
facility, the baseline Q/

D of the facility, and the potential reduction in Q/D from the
controls. Based on the costs of compliance and the relatively small
size of this facility, we find it reasonable to eliminate the only
control option (RSCR). Therefore, we are proposing that no additional
controls will be required for this planning period.
viii. Roseburg Forest Products
    Roseburg Forest Products Company owns and operates a particleboard
manufacturing facility in Missoula, Montana. Additional information to
support this four factor analysis can be found in the docket.\290\ The
facility has two production lines, one with a multi-platen batch press
(Line 1) and one with a continuous press (Line 2). A pre-dryer is used
to reduce the moisture of green wood materials received at the
facility. Heat for the pre-dryer is provided by exhaust from a 45
MMBtu/hr SolaGen sander dust burner. There are four final dryers
associated with Line 1 and two final dryers associated with Line 2 that
produce dried wood furnish for face and core material in the
particleboard. Heat input for all six of the final dryers is provided
by the combined exhaust of a 50 MMBtu/hr ROEMMC sander dust burner and
55 MMBtu/hr sander dust-fired Babcock & Wilcox boiler, which also
provides steam for facility processes.
---------------------------------------------------------------------------

    \290\ Reasonable Progress Analysis, Roseburg Forest Products,
Missoula Particleboard, Submitted for Roseburg Forest Products by
Golder Associates, Inc. (Feb. 2, 2011); Reasonable Progress (RP)
Four-Factor Analysis of Control Options for Roseburg Forest Products
Co., Missoula Particleboard.
---------------------------------------------------------------------------

    The Babcock & Wilcox boiler is the oldest of the three sander dust-
fired sources at the facility. It is a stoker-type boiler that was
installed in 1969. Unlike the other sander dust burners at the
facility, the boiler serves the function of producing steam for
facility processes in addition to providing heat input to the final
dryers. The ROEMMC burner was installed in 1979, although it is a 1978
model burner. The sole purpose of this burner is to provide heat input
for the final dryers. The SolaGen sander dust burner was installed in
2006, although it is a 2005 model. The sole purpose of this burner is
to provide heat input to the pre-dryer.
    PM emissions from the Babcock & Wilcox boiler, ROEMMC burner, and
Line 1 and 2 final dryers are controlled by multi-clones at the dryer
outlets. PM emissions from the SolaGen burner and pre-dryer are
controlled by a cyclone, a wet ESP, and a regenerative thermal
oxidizer. As discussed previously in Section V.D.6.b., the contribution
from point sources to primary organic aerosols, EC, PM2.5
and PM10 at Montana Class I areas is very small, and
modeling tends to confirm that PM emissions from point sources do not
have a very large impact. Therefore, we are proposing that additional
controls for PM are not necessary for this planning period.
    SO2 emissions are relatively small (6 tpy of
SO2 for all units combined). Thus, SO2 emissions
from these units are not significant contributors to regional haze and
our analysis only considers NOX. Additional controls for
SO2 will not be considered or required in this planning
period. We are therefore considering controls only for NOX
for this planning period.
Babcock & Wilcox Boiler
Step 1: Identify All Available Technologies
    The Babcock & Wilcox boiler does not currently have post-combustion
controls or low NOX combustion technology. We identified
that the following technologies to be available: SCR, RSCR, SNCR, SNCR/
SCR hybrid, staged combustion, fuel staging, LNB, OFA, LEA, and FGR.
SCR, SNCR, LNB, OFA, LEA and FGR were described in our analysis for
CELP. RSCR, SNCR/SCR hybrid, staged combustion, and fuel staging were
described in our analysis for the boiler at Plum Creek Manufacturing.
Step 2: Eliminate Technically Infeasible Options
    SCR catalysts may be fouled or plugged by exhaust gas that contains
high concentrations of PM, as is the case with the combustion of wood,
biomass, or hog fuel. To prevent the premature failure of the catalyst,
the PM must be removed from the exhaust stream prior to the SCR. In
this case, the exhaust from the PM control equipment will not meet the
minimum temperature required for SCR to be effective. In addition to
these issues, there is insufficient space prior to the dryers to add
both PM controls and SCR. Even if there were space to add both systems,
the exhaust from PM controls and SCR would be at a lower temperature,
resulting in insufficient heat being sent to the dryers. For these
reasons, SCR was not considered further.
    The exhaust from all of the units act as direct contact heat
sources for the drying processes at the facility. The use of SNCR would
require injection of the reagent prior to the dryers, which would
introduce NH3 to the product lines. Roseburg has stated that
contact with NH3 may reduce product quality. For this
reason, SNCR was not considered further.
    A SNCR/SCR hybrid system also uses a catalyst and thus would
experience similar technical difficulties related to catalyst plugging
and/or fouling, as described for SCR. If PM controls were retrofitted
prior to the dryers to allow the SCR to be operated without reheat, the
exhaust from the PM controls would be significantly reduced, resulting
in insufficient heat being sent to the dryers. Space constraints and
product quality concerns are also issues. For these reasons, a SNCR/SCR
hybrid system was not considered further.
    Two stable zones of combustion are required for fuel staging. If
there is insufficient space, the secondary fuel and combustion zone
will impinge on the primary zone having the effect of raising the peak
flame temperature and, in turn, increasing NOX emissions.
There is not sufficient room within the boiler to achieve fuel staging
while maintaining the necessary heat input to the dryers. The creation
of a larger combustion zone within the boiler also has the possibility
of causing greater flame impingement on the boiler wall and tubes,
which may compromise their integrity and cause premature failure. For
these reasons, fuel staging was not considered further.
    Staged combustion is considered feasible for the boiler in the form
of a new SolaGen-type LNB; however, staged combustion in the form of
OFA is considered technically infeasible for the boiler. Suspension
burners such as the boiler need high air flow through the fuel-feed
auger and burner to suspend and fluidize the solid fuel. Splitting the
combustion air to OFA ports would result in poor and perhaps unstable
combustion at the burner tip. For this reason, OFA was not considered
further.
    As with OFA, suspension-type burners, such as the boiler, require
high levels of air in order to fluidize the solid fuel. The burners
would operate poorly with LEA. For this reason, LEA was not considered
further.
    FGR is a technique with multiple mechanisms for reducing
NOX, including reducing the available oxygen, since some
exhaust gas replaces oxygen rich ambient air. As with LEA, some
combustion air must be reduced to accommodate the recirculating flue
gas, which may cause the suspension burner to operate improperly. FGR
may be applied in some situations, but in order to maintain the
necessary heat input in this situation, additional combustion chamber
volume would be required to accommodate the volume of the flue gas
introduced into the combustion

chamber. For these reasons, FGR was not considered further.
Step 3: Evaluate Control Effectiveness of Remaining Control
Technologies
    A summary of emissions projections for LNB and RSCR, the only
remaining control technologies, are provided in Table 186. At this
facility, RSCR would be placed downstream of the wood particle dryers
and as a result would control emissions from both the boiler and the
ROEMMC sander dust burner. Baseline NOX emissions from the
boiler are 134 tpy. Baseline NOX emissions from the Line 1
dryers would be from the boiler and ROEMMC sander dust burner combined
and are 202 tpy. Baseline NOX emissions from the Line 2
dryers would be from the boiler and ROEMMC sander dust burner combined
and are 92 tpy.

               Table 186--Summary of Roseburg NOX Reasonable Progress Analysis Control Technology
----------------------------------------------------------------------------------------------------------------
                                                                Control           Emissions         Remaining
                      Control option                       effectiveness (%)   reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
LNB......................................................               22.2                30               104
RSCR Line 1..............................................               75              \1\151             \1\51
RSCR Line 2..............................................               75               \1\69             \1\23
----------------------------------------------------------------------------------------------------------------
\1\ RSCR on the dryers would control emissions from the boiler and the ROEMMC.

    LNBs are a form of staged combustion and may be able to achieve 50-
70% reductions in NOX emissions when firing coal, depending
on the design or generation of the burner. However, NOX
reductions are highly dependent on the specifics of the burner design,
fuel fired, and the operational setting. Roseburg presented a control
efficiency for LNB applicable to the boiler of approximately 20%, which
was based on information from the LNB vendor. This is not unreasonable
considering that biomass produces primarily fuel NOX rather
than thermal NOX, and LNB primarily reduce the generation of
thermal NOX.
Factor 1: Costs of Compliance
    Table 187 provides a summary of estimated annual costs and cost
effectiveness for LNB and RSCR.

  Table 187--Summary of Roseburg NOX Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
LNB.................................            70,624             2,354
RSCR Line 1.........................         2,261,273            14,975
RSCR Line 2.........................         1,234,469            17,891
------------------------------------------------------------------------

    For LNB, we are adopting cost figures provided by Roseburg, except
that we annualized the capital cost by multiplying the capital cost by
a CRF that corresponds to a 7% interest rate and 20-year equipment life
(which yields a CRF of 0.0944), as specified in the Office of
Management and Budget's Circular A-4, Regulatory Analysis.\291\
---------------------------------------------------------------------------

    \291\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

Factor 2: Time Necessary for Compliance
    EPA found cases in which boilers have been retrofitted with LNB in
less than six months. However, this does not take into account
variables that affect the ability of a company to have equipment off-
line, such as seasonal variations in business that may require Roseburg
to postpone retrofit until such time as is appropriate. In this case,
we would expect that the LNB can be installed within a maximum of 12
months.
    RSCR systems can be operational within eight months to one year.
Factor 3: Energy and Non-air Quality Environmental Impacts of
Compliance
    LNB would reduce the heat rate that could be sent to the units
without increasing the volume of the combustion chamber. That would
have the effect of reducing the mass flow rate and heat flux through
the dryers. In order to make up for the lost heat it may be possible to
add an additional heat source; however, that would use additional fuel,
increasing natural resource use. It may be possible to reduce the
amount of ambient air mixed into the exhaust prior to the dryers, but
this is unlikely because there must be sufficient air flow, in addition
to heat, to reduce the moisture content of the product.
    RSCR requires the reheat of the flue gas, either through a heat
exchanger that utilizes plant waste heat, and/or through direct reheat
of the flue gas by additional combustion or electrically powered
heating elements. The flue gas at the boiler exhaust is approximately
572 [deg]F, and the temperature of the exhaust of the ROEMMC varies
between 700 [deg]F and 1050 [deg]F. These two gas streams then mix with
additional ambient air and pass through the Line 1 and Line 2 dryers,
further reducing the exhaust gas temperature to 130 [deg]F to 155
[deg]F. In order to reheat the gas stream and operate the RSCR system
it is anticipated that the following resources described in Table 188
would be required or consumed.

               Table 188--Additional Ammonia, Natural Gas, Electricity and Compressed Air for RSCR
----------------------------------------------------------------------------------------------------------------
                                     Ammonia (NH3)        Natural gas         Electricity       Compressed air
----------------------------------------------------------------------------------------------------------------
Line 1 RSCR.....................  433,000 gal/year..  9.7 million scf/    3.6 million kWh/    7.2 million scf/
                                                       year.               year.               year
Line 2 RSCR.....................  433,000 gal/year..  4.7 million scf/    1.7 million kWh/    3.8 million scf/
                                                       year.               year.               year
----------------------------------------------------------------------------------------------------------------

    Additionally, the RSCR catalyst may have the potential to emit
NH3 (as NH3 slip) and generate nitrous oxide if
not operated optimally. Catalysts must be disposed of, presenting a
cost; however, many catalyst manufacturers provide a system to
regenerate or recycle the catalyst reducing the impacts associated with
spent catalysts. In addition to these considerations, there are issues
associated with the production, transport, storage, and use of
NH3. However, regular handling of NH3 has reduced
the risks associated with its transport, storage, and use.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: The cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the sources. We are also taking into account the size of the
facility, the baseline Q/D of the facility, and the potential reduction
in Q/D from the controls. We propose to eliminate the most expensive
options (RSCR on line 1 and line 2), based on costs of compliance and
the relatively small size of this facility. The most cost-effective
option (LNB) would reduce emissions by only 34 tpy, which equates to
approximately a 9.2% reduction in overall emissions of SO2 +
NOX from the facility, or a reduction of Q/D from 12 to 11.
Based on this benefit, the baseline Q/D, and the reduction in Q/D, we
find it reasonable to eliminate this option. Therefore, we are
proposing to not require any NOX controls on this unit for
this planning period.
ROEMMC Sander Dust Burner
Step 1: Identify All Available Technologies
    The ROEMMC sander dust burner does not currently have post
combustion controls or low NOX combustion technology. We
identified that the following technologies to be available: SCR, RSCR,
SNCR, SNCR/SCR hybrid, staged combustion, fuel staging, LNB, OFA, LEA,
and FGR. SCR, SNCR, and LNB, OFA, LEA and FGR were described in our
analysis for CELP. RSCR, SNCR/SCR hybrid, staged combustion, and fuel
staging were described in our analysis for the boiler at Plum Creek
Manufacturing.
Step 2: Eliminate Technically Infeasible Options
    SCR was not considered further for the ROEMMC sander dust burner
for the same reasons provided for the boiler: Insufficient space for
both PM controls (necessary to avoid fouling and plugging) and the SCR
catalyst, and insufficient heat from the exhaust to operate the dryers.
    RSCRs would be placed downstream of the wood particle dryers. The
RSCRs would control emissions from the ROEMMC sander dust burner in
addition to the Babcock & Wilcox boiler. This technology was described
in the analysis for the boiler; for the same reasons it was considered
feasible there, it is considered feasible here.
    SNCR was not considered further for the ROEMMC sander dust burner
for the same reason provided for the boiler: reduced product quality
due to contact with NH3. A SNCR/SCR hybrid system was also
not considered further for the ROEMMC sander dust burner for the same
reasons provided for the boiler: lower temperature exhaust from PM
controls and the SCR/SNCR hybrid system would provide insufficient heat
for the dryers.
    Staged combustion techniques increase the volume of the flame front
for a given heat input rate. The ROEMMC sander dust burner is small,
making it necessary to reduce the overall heat input to levels below
what is needed to operate the dryers to achieve staged combustion. For
this reason, staged combustion was not considered further.
    Fuel staging was not considered further for the same reasons
provided for the boiler: Insufficient space to achieve fuel staging
while maintaining the necessary heat input the dryers.
    LNB designs increase the length of the flame front. In order for
the ROEMMC sander dust burner to operate as designed (with a rich and
lean zone), the heat input to the burner would need to be decreased so
that a smaller, yet longer flame could be created within the same
physical space available with the current combustion chamber. The
reduced firing rate would have the effect of reducing the necessary
heat input below acceptable levels for operating the dryers. For these
reasons, LNB was not considered further.
    The ROEMMC sander dust burner does not have sufficient space to
install OFA ports. In addition to space constraints, suspension burners
such as the ROEMMC need high air flow through the fuel feed auger and
burner to suspend and fluidize the solid fuel. Splitting the combustion
air to OFA ports would result in poor and perhaps unstable combustion
at the burner tip. For these reasons, OFA was not considered further.
    LEA was not considered further for the ROEMMC sander dust burner
for the same reasons provided for the boiler. Suspension-type burners,
such as the ROEMMC sander dust burner, require high levels of air in
order to fluidize the solid fuel. The burners would operate poorly with
LEA.
    FGR was not considered further for the ROEMMC sander dust burner
for the same reasons provided for the boiler. FGR reduces the available
oxygen, since some exhaust gas replaces oxygen rich ambient air.
Additionally, FGR may require increased combustion chamber volume to
accommodate the same heat input while maintaining a reduced flame
temperature. For these reasons, FGR was not considered further.
    All technologies identified in Step 1 were eliminated in Step 2;
therefore, our analysis for the ROEMMC sander dust burner is complete.
We have determined that no additional controls should be imposed on
this unit in this planning period.
SolaGen Sander Dust Burner
Step 1: Identify All Available Technologies
    The SolaGen sander dust burner currently uses LNB and FGR to
control NOX. We identified that the following technologies
to be available: SCR, RSCR, SNCR, SNCR/SCR hybrid, staged combustion,
fuel staging, OFA, and LEA. SCR, SNCR, LNB, OFA, LEA and FGR were
described in our analysis for

CELP. RSCR, SNCR/SCR hybrid, staged combustion, and fuel staging were
described in our analysis for the boiler at Plum Creek Manufacturing.
Step 2: Eliminate Technically Infeasible Options
    SCR was not considered further for the SolaGen sander dust burner
for the same reasons provided for the boiler. There is insufficient
space prior to the pre-dryer to add both PM controls and SCR, and the
exhaust from PM controls and SCR would be at a lower temperature
resulting in insufficient heat being sent to the pre-dryer.
    SNCR was not considered further for the SolaGen sander dust burner
for the same reason provided for the boiler: reduced product quality
from contact with NH3. A SNCR/SCR hybrid system was not
considered further for the SolaGen sander dust burner for the same
reasons provided for the boiler: lower temperature exhaust from PM
controls and the SCR/SNCR hybrid system would provide insufficient heat
for the pre-dryer.
    The SolaGen sander dust burner is a LNB, which is a form of staged
combustion; further staging would not be technically feasible for the
SolaGen. For this reason, staged combustion was not considered further.
    Fuel staging was not considered further for the same reasons
provided for the boiler. There is not sufficient room to achieve fuel
staging while maintaining the necessary heat input for the pre-dryer.
    The SolaGen sander dust burner already utilizes a LNB design,
making further excess air infeasible to support stable combustion. For
this reason, OFA was not considered further.
    LEA was not considered further for the SolaGen sander dust burner
for the same reasons provided for the boiler. Suspension-type burners,
such as the SolaGen sander dust burner, require high levels of air in
order to fluidize the solid fuel. The burners would operate poorly with
LEA.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NOX emissions from the SolaGen sander dust
burner are 58 tpy. A summary of emissions projections for RSCR, the
only remaining control technology, is provided in Table 189.

               Table 189--Summary of Roseburg NOX Reasonable Progress Analysis Control Technology
----------------------------------------------------------------------------------------------------------------
                                                              Control           Emissions          Remaining
                     Control option                      effectiveness (%)   reduction (tpy)    emissions (tpy)
----------------------------------------------------------------------------------------------------------------
RSCR...................................................                75                 43                 15
----------------------------------------------------------------------------------------------------------------

Factor 1: Costs of Compliance
    Table 190 provides a summary of estimated annual costs for RSCR.

  Table 190--Summary of Roseburg RSCR Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
          Control option            Total annual cost  effectiveness ($/
                                           ($)                ton)
------------------------------------------------------------------------
RSCR..............................           748,097             17,398
------------------------------------------------------------------------

    We are adopting cost figures provided by Roseburg, except that we
annualized the capital cost by multiplying the capital cost by a CRF
that corresponds to a 7% interest rate and 20-year equipment life
(which yields a CRF of 0.0944), as specified in the Office of
Management and Budget's Circular A-4, Regulatory Analysis.\292\
---------------------------------------------------------------------------

    \292\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

Factor 2: Time Necessary for Compliance
    RSCR systems can be operational within eight months to one year.
Factor 3: Energy and Non-air Quality Environmental Impacts of
Compliance
    RSCR requires the reheat of the flue gas, either through a heat
exchanger that utilizes plant waste heat, and/or through direct reheat
of the flue gas by additional combustion or electrically powered
heating elements. In order to reheat the gas stream and operate the
RSCR system, the following resources described in Table 191 would be
consumed.

          Table 191--Additional Ammonia, Natural Gas, Electricity and Compressed Air Required for RSCR
----------------------------------------------------------------------------------------------------------------
            Ammonia (NH3)                    Natural gas              Electricity             Compressed air
----------------------------------------------------------------------------------------------------------------
304,000 gal/year.....................  2 million scf/year.....  700,000 kWh/year.......  1.3 million scf/year
----------------------------------------------------------------------------------------------------------------

    Environmental impacts were described in the analysis for the
boiler.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: the cost of
compliance; the time necessary for compliance; the

energy and non-air quality environmental impacts of compliance; and the
remaining useful life of the sources. We are also taking into account
the size of the facility, the baseline Q/D of the facility, and the
potential reduction in Q/D from the controls. We find it reasonable to
eliminate the only feasible option, RSCR, on the basis of the costs of
compliance and the relatively small size of this facility. Therefore,
we are proposing that no additional NOX controls will be
required for this planning period.
ix. Smurfit Stone Container
    Smurfit Stone Container Enterprises Inc., Missoula Mill (purchased
and renamed M2Green Redevelopment LLC Missoula Site on 5/3/11) \293\
was determined to be below the threshold of sources subject to BART,
but above the threshold for sources subject to further evaluation for
RP controls. According to an emissions report from M2Green
Redevelopment LLC, the mill was permanently shut down on January 12,
2010 and is no longer operating.\294\
---------------------------------------------------------------------------

    \293\ See http://www.greeninvgroup.com/news/news-release-missoula-announcement.html.
    \294\ M2Green Redevelopment LLC Quarterly Excess Emissions
Report--Third Quarter 2011 (11/1/2011).
---------------------------------------------------------------------------

    While the current owners have permanently shut down the mill at
M2Green Redevelopment LLC, Missoula Site, and it is uncertain whether
the mill will resume operations, should the mill resume operations we
will revise the FIP as necessary in accordance with regional haze
requirements, including the ``reasonable progress'' provisions in 40
CFR 51.308(d)(1).
x. Yellowstone Energy Limited Partnership
    Yellowstone Energy Limited Partnership (YELP), in partnership with
Billings Generation Incorporated, owns an electric power plant in
Billings, Montana.\295\ The plant is rated at 65 MW gross output and
includes two identical CFB boilers that are fired on petroleum coke and
cooker gas; exhaust exits through a common stack. The boilers and
emission controls were installed in 1995.
---------------------------------------------------------------------------

    \295\ All information found within this section can be found in
the corresponding report in the docket.
---------------------------------------------------------------------------

    PM emissions are controlled by two fabric filter baghouses at the
common stack that is designed to achieve greater than 99% control of
particulates.\296\ As discussed previously in Section V.D.6.b., the
contribution from point sources to primary organic aerosols, EC,
PM2.5 at Montana Class I areas is very small, and modeling
tends to confirm that PM emissions from point sources do not have a
very large impact. Therefore, we are proposing that additional controls
for PM are not necessary for this planning period.
---------------------------------------------------------------------------

    \296\ Response to Additional Reasonable Progress Information for
the Yellowstone Energy Limited Partnership Facility Pursuant to
Section 114(a) of the CAA (42 U.S.C. Section 7414(A)) Prepared for
Billings Generation, Inc. (``YELP Additional Response''), p. 2-1
February 24, 2011.
---------------------------------------------------------------------------

SO2
Step 1: Identify All Available Technologies
    We identified that the following technologies to be available:
limestone injection process upgrade, a SDA, DSI, a CDS, HAR, a wet lime
scrubber, a wet limestone scrubber, and/or a dual alkali scrubber.
    YELP currently controls SO2 emissions using limestone
injection. Crushed limestone is injected with the petroleum coke prior
to its combustion in the two CFB boilers. When limestone is heated to
1550[emsp14][deg]F, it releases CO2 and forms lime (CaO),
which subsequently reacts with the SO2 in the combustion gas
to form calcium sulfates and calcium sulfites. The calcium compounds
are removed as PM by the baghouse. Depending on the fuel fired in the
boilers and the total heat input, YELP must achieve, under a Montana
operating permit, 70% to 90% reduction of SO2 emissions.
YELP states that, during 2008 through 2009, SO2 reduction
averaged 95%. Increasing the limestone injection rate beyond current
levels could theoretically result in a modest increase in
SO2 control.
    SDAs were described in our analysis for CELP. SDAs have
demonstrated the ability to achieve 90% to 94% SO2
reduction. SDA plus limestone injection can achieve between 98% and 99%
SO2 reduction.\297\ Due to the high degree of SO2
control efficiency already achieved by limestone injection at this
facility (95%), we have used 80% control efficiency for SDA in this
analysis, downstream of limestone injection.
---------------------------------------------------------------------------

    \297\ Deseret Bonanza SOB, p. 92.
---------------------------------------------------------------------------

    DSI was described in our BART analysis for Corette. SO2
control efficiencies for DSI systems by themselves (not downstream of
limestone injection systems) are approximately 50%, but if the sorbent
is hydrated lime, then 80% or greater removal can be achieved. These
systems are commonly called lime spray dryers.
    A description of a CDS was provided in our analysis for CELP. A CDS
can achieve removal efficiency similar to that achieved by SDA on CFB
boilers.\298\
---------------------------------------------------------------------------

    \298\ Id.
---------------------------------------------------------------------------

    The HAR process was described in our analysis for CELP. HAR
downstream of a CFB boiler that utilizes limestone injection can reduce
the remaining SO2 by about 80%.\299\
---------------------------------------------------------------------------

    \299\ Id., p. 93.
---------------------------------------------------------------------------

    A general description of wet lime scrubbing was provided in our
BART analysis for Ash Grove.
    Wet lime and wet limestone scrubbers involve spraying alkaline
slurry into the exhaust gas to react with SO2 in the flue
gas. Insoluble salts are formed in the chemical reaction that occurs in
the scrubber and the salts are removed as a solid waste by-product. Wet
lime and limestone scrubbers are very similar, but the type of additive
used differs (lime or limestone). The use of limestone
(CaCO3) instead of lime requires different feed preparation
equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas
ratio typically requires a larger absorbing unit. The limestone slurry
process also requires a ball mill to crush the limestone feed. Wet lime
and limestone scrubbers have been demonstrated to achieve greater than
99% control efficiency.\300\
---------------------------------------------------------------------------

    \300\ Deseret Bonanza SOB, p. 94.
---------------------------------------------------------------------------

    Dual-alkali scrubbers use a sodium-based alkali solution to remove
SO2 from the combustion exhaust gas. The process uses both
sodium-based and calcium-based compounds. The sodium-based reagents
absorb SO2 from the exhaust gas, and the calcium-based
solution (lime or limestone) regenerates the spent liquor. Calcium
sulfites and sulfates are precipitated and discarded as sludge, and the
regenerated sodium solution is returned to the absorber loop. The dual-
alkali process requires lower liquid-to-gas ratios than scrubbing with
lime or limestone. The reduced liquid-to-gas ratios generally mean
smaller reaction units; however, additional regeneration and sludge
processing equipment is necessary. A sodium-based scrubbing solution,
typically consisting of a mixture of sodium hydroxide, sodium
carbonates, and sodium sulfite, is an efficient SO2 control
reagent. However, the process generates a sludge that can create
material handling and disposal issues. The control efficiency is
similar to the wet lime/limestone scrubbers at approximately 95% or
greater.
Step 2: Eliminate Technically Infeasible Options
    The current limestone injection system is operating at or near its
maximum capacity. The boiler feed rates are approximately 740 tons/day
of petroleum coke and 415 tons/day of limestone. Increasing limestone
injection beyond the current levels would result in plugging of the
injection

lines, and increased bed ash production, which can reduce combustion
efficiency, and increased particulate loading to the baghouses.
Therefore, increasing limestone injection beyond its current level
would require major upgrades to the limestone feeding system and the
baghouses.\301\ Only modest increases in SO2 removal
efficiency, if any, would be expected with this scenario, compared to
add-on SO2 control systems discussed below. Therefore, a
limestone injection process upgrade is eliminated from further
consideration.
---------------------------------------------------------------------------

    \301\ YELP Additional Response, p. 2-2.
---------------------------------------------------------------------------

    CDS systems result in high particulate loading to the unit's
particulate control device. Because of the high particulate loading,
the pressure drop across a fabric filter would be unacceptable;
therefore, ESPs are generally used for particulate control. YELP has
two high efficiency fabric filters (baghouses) in place. Based on
limited technical data from non-comparable applications and engineering
judgment, we are determining that CDS is not technically feasible for
this facility.\302\ Therefore, CDS is eliminated from further
consideration.
---------------------------------------------------------------------------

    \302\ Deseret Bonanza SOB, p. 92.
---------------------------------------------------------------------------

    A DSI system is not practical for use in a CFB boiler such as YELP,
where limestone injection is already being used upstream in the boiler
for SO2 control. With limestone injection, the CFB boiler
flue gas already contains excess unreacted lime. Fly ash containing
this unreacted lime is reinjected back into the CFB boiler combustion
bed, as part of the boiler operating design. A DSI system would simply
add additional unreacted lime to the flue gas and would achieve little,
if any, additional SO2 control.\303\ If used instead of
limestone injection (the only practical way it might be used), DSI
would achieve less control efficiency (50%) than the limestone
injection system already being used (70 to 90%). Therefore, DSI is
eliminated from further consideration.
---------------------------------------------------------------------------

    \303\ Id., p. 93.
---------------------------------------------------------------------------

    Regarding wet scrubbing, there is limited area to install
additional SO2 controls that would require high quantities
of water and dewatering ponds. The wet FGD scrubber systems with the
higher water requirements (wet lime scrubber, wet limestone scrubber,
and dual alkali wet scrubber) would require an on-site dewatering pond
or an additional landfill to dispose of scrubber sludge. Due to the
limited available space, its proximity to the Yellowstone River and
limited water availability for these controls,\304\ we consider these
technologies technically infeasible and do not evaluate them further.
---------------------------------------------------------------------------

    \304\ YELP Additional Response, p. 2-5.
---------------------------------------------------------------------------

    The remaining technically feasible SO2 control options
for YELP are SDA and HAR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NOX emissions from YELP are 1,826 tpy. A
summary of emissions projections for the various control options is
provided in Table 192. Since limestone injection is already in use at
the YELP facility, the control efficiencies and emissions reductions
shown below are those that might be achieved beyond the control already
being achieved by the existing limestone injection system.

                Table 192--Summary of YELP SO2 Reasonable Progress Analysis Control Technologies
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
SDA.......................................................                80             1,461               365
HAR.......................................................                50               913               913
----------------------------------------------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
Factor 1: Costs of compliance
    Table 193 provides a summary of estimated annual costs for the
various control options. All costs shown are for the two boilers
combined.

   Table 193--Summary of YELP SO2 Reasonable Progress Cost Analysis as
                           Recalculated by EPA
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
SDA with baghouse replacement.......         6,237,065             4,211
SDA without baghouse replacement....         4,709,504             3,182
HAR with baghouse replacement.......         4,660,376             5,104
HAR without baghouse replacement....         3,132,815             3,431
------------------------------------------------------------------------

    We have relied on the control costs provided by YELP,\305\ with two
exceptions. First, we calculated the annual cost of capital using 7%
annual interest rate and a 20-year equipment life (which yields a CRF
of 0.0944), as specified in the Office of Management and Budget's
Circular A-4 Regulatory Analysis.\306\ Second, we calculated the cost
of SDA and HAR in two ways: (1) With baghouse replacement, and (2)
without baghouse replacement, see Table 193 above.
---------------------------------------------------------------------------

    \305\ Id., p. 7-3.
    \306\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

Factor 2: Time Necessary for Compliance
    We have relied on YELP's estimates that the time necessary to
complete the modifications to the two boilers to accommodate SDA or
HAR, without replacing the baghouses, would be

approximately one year and that a boiler outage of approximate two to
three months per boiler would be necessary to perform the installation
of either system. The installation of the controls would need to be
staggered to allow one boiler to remain in operation while the
retrofits are applied to the other boiler. YELP states that complete
replacement or major modifications to the existing baghouses would be
necessary, however, the company does not explain why the existing
baghouses would need to be replaced or modified to accommodate SDA or
HAR.\307\
---------------------------------------------------------------------------

    \307\ YELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

Factor 3: Energy and Non-air Quality Environmental Impacts of
Compliance
    Wet FGD systems are estimated to consume 1% to 2.5% of the total
electric generation of the plant and can consume approximately 40% more
than dry FGD systems (SDA). Electricity requirements for a HAR system
are less than FGD systems. DSI systems are estimated to consume 0.1% to
0.5% of the total plant generation.\308\ For reasons explained above,
wet FGD systems and DSI systems have already been eliminated as
technically infeasible.
---------------------------------------------------------------------------

    \308\ Id., p. 4-2.
---------------------------------------------------------------------------

    SO2 controls would result in increased ash production at
the YELP facility. Boiler ash is currently either sent to a landfill or
sold for beneficial use, such as oil well reclamation. Changes in ash
properties due to increased calcium sulfates and calcium sulfites could
result in the ash being no longer suitable to be sold for beneficial
uses. If the ash properties were to change such that the ash could no
longer be sold for beneficial use, the loss of this market would cost
approximately $2,300,000 per year at the current ash value and
production rates (approximately 170,000 tons of ash per year). The loss
of this market could also result in the company having to dispose of
the ash at its current landfill, which is approximately 80 miles from
the plant. The cost to dispose of the ash would be approximately
$96,000 per year. The total cost from the loss of the beneficial use
market and the increase in ash disposal costs would be a total of
$2,400,000 per year.\309\ This potential cost has not been included in
the cost described above, as it is only speculative, being based on an
undetermined potential future change in ash properties.
---------------------------------------------------------------------------

    \309\ Id.
---------------------------------------------------------------------------

    As described above, wet FGD scrubber systems with the higher water
requirements (Wet Lime Scrubber, Wet Limestone Scrubber, and Dual
Alkali Wet Scrubber) would require construction of an on-site
dewatering pond or an additional landfill to dispose of scrubber
sludge.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: the cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the sources. We are also taking into account the size of the
facility, the baseline Q/D of the facility, and the potential reduction
in Q/D from the controls. Given the cost of $3,182 per ton of
SO2 (at a minimum) for the most cost-effective option (SDA),
the relatively small size of YELP, and the small baseline Q/D of 14, we
find it reasonable to not impose any of the SO2 control
options. Therefore, we are proposing that no additional controls will
be required for this planning period.
NOX
    Currently, there are no NOX controls at the YELP
facility.
Step 1: Identify All Available Technologies
    We identified that the following technologies to be available: SCR,
SNCR, LEA, FGR, OFA, LNB, non-thermal plasma reactor, and carbon
injection into the combustion chamber.
    SCR, SNCR, LNB, LEA, OFA, FGR, non-thermal plasma reactor, and
carbon injection into the combustion chamber were described in our
analysis for CELP.
    The temperature range for proper operation of an SCR is between 480
[deg]F and 800 [deg]F. Many of the CFBs in the United States have
baghouses for particulate control. The normal maximum allowable
temperature for a baghouse is 400 [deg]F.
    Therefore, on some installations, RSCR is installed. RSCRs are
expensive to install and expensive to operate, because an RSCR requires
the use of burners to heat up the flue gas stream in order for the
NOX capture to occur. This is often an efficiency decrease
for the boiler, significant increase in operating cost, and often not a
practical solution. For this reason, RSCR was not evaluated as a
control option for YELP. Instead, high dust SCR was evaluated.
Step 2: Eliminate Technically Infeasible Options
    LEA, FGR, and OFA are typically used on Pulverized Coal (PC) units
and cannot be used on CFB boilers due to air needed to fluidize the
bed.\310\ While LEA may have substantial effect on NOX
emissions at PC boilers, it has much less effect on NOX
emissions at combustion sources such as CFBs that operate at low
combustion temperatures. FGR reduces NOX formation by
reducing peak flame temperature and is ineffective on combustion
sources such as CFBs that already operate at low combustion
temperatures. For these reasons, LEA, FGR and OFA are eliminated from
further consideration.
---------------------------------------------------------------------------

    \310\ Id.
---------------------------------------------------------------------------

    LNBs are typically used on PC units and cannot be used on CFB
boilers because the combustion occurs within the fluidized bed.\311\
CFB boilers do not use burners during normal operation. Therefore, LNBs
are eliminated from further consideration.
---------------------------------------------------------------------------

    \311\ Id.
---------------------------------------------------------------------------

    While a non-thermal plasma reactor may have practical potential for
application to coal-fired CFB boilers as a technology transfer option
at Step 1 of the analysis, it is not known to be commercially available
for CFB boilers.\312\ Therefore, a non-thermal plasma reactor is
eliminated from further consideration.
---------------------------------------------------------------------------

    \312\ Deseret Bonanza SOB, pp. 46, 48.
---------------------------------------------------------------------------

    Although carbon injection is an emerging technology used to reduce
mercury emissions, it has not been used anywhere to control
NOX. Therefore, it is eliminated from further consideration.
    The remaining technically feasible NOX control options
for YELP are HDSCR and SNCR.
Step 3: Evaluate Control Effectiveness of Remaining Control Technology
    Baseline NOX emissions from YELP are 396 tpy. A summary
of emissions projections for the various control options is provided in
Table 194.

                Table 194--Summary of YELP NOX Reasonable Progress Analysis Control Technologies
----------------------------------------------------------------------------------------------------------------
                                                                 Control
                      Control option                          effectiveness       Emissions         Remaining
                                                                   (%)         reduction (tpy)   emissions (tpy)
----------------------------------------------------------------------------------------------------------------
HDSCR.....................................................                80               317                79
SNCR......................................................                50               198               198
----------------------------------------------------------------------------------------------------------------

Step 4: Evaluate Impacts and Document Results
Factor 1: Costs of Compliance
    Table 195 provides a summary of estimated annual costs for the
various control options.

    Table 195--Summary of YELP NOX Reasonable Progress Cost Analysis
------------------------------------------------------------------------
                                                              Cost
           Control option               Total annual    effectiveness ($/
                                          cost ($)            ton)
------------------------------------------------------------------------
HDSCR...............................         3,883,020            12,249
SNCR................................           529,810             2,689
------------------------------------------------------------------------

    We have relied on the NOX control costs provided by
YELP,\313\ with one exception. We calculated the annual cost of capital
using a 7% annual interest rate and 20-year equipment life (which
yields a CRF of 0.0944), as specified in the Office of Management and
Budget's Circular A-4, Regulatory Analysis.\314\
---------------------------------------------------------------------------

    \313\ YELP Additional Response, Appendix A.
    \314\ Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/.
---------------------------------------------------------------------------

Factor 2: Time Necessary for Compliance
    We have relied on YELP's estimates that HDSCR would take
approximately 26 months to install and that SNCR would take 24 to 30
weeks to install.\315\
---------------------------------------------------------------------------

    \315\ YELP Additional Response, p. 3-1.
---------------------------------------------------------------------------

Factor 3: Energy and Non-Air Quality Environmental Impacts of
Compliance
    The energy impacts from SNCR are expected to be minimal. SNCR is
not expected to cause a loss of power output from the facility. SCR,
however, could cause significant backpressure on the boiler, leading to
lost boiler efficiency and, thus, a loss of power production. If LDSCR
was to be installed instead of HDSCR, YELP would be subject to the
additional cost of reheating the exhaust gas.
    Regarding other non-air quality environmental impacts of
compliance, SCRs can contribute to airheater fouling from the formation
of ammonium sulfate. Airheater fouling could reduce unit efficiency,
increase flue gas velocities in the airheater, cause corrosion, and
erosion. Catalyst replacement can lengthen boiler outages, especially
in retrofit installations, where space and access is limited. This is a
retrofit installation in a high dust environment, thus fouling is
likely, which could lead to unplanned outages or less time between
planned outages. On some installations, catalyst life is short and SCRs
have fouled in high dust environments. For both SCR and SNCR, the
storage of on-site NH3 could pose a risk from potential
releases to the environment. An additional concern is the loss of
NH3, or ``slip'' into the emissions stream from the
facility. This ``slip'' contributes another pollutant to the
environment, which has been implicated as a precursor to
PM2.5 formation.
Factor 4: Remaining Useful Life
    EPA has determined that the default 20-year amortization period is
most appropriate to use as the remaining useful life of the facility.
Without commitments for an early shut down, EPA cannot consider a
shorter amortization period in our analysis.
Step 5: Select Reasonable Progress Controls
    We have considered the following four factors: The cost of
compliance; the time necessary for compliance; the energy and non-air
quality environmental impacts of compliance; and the remaining useful
life of the source. For the more expensive option (SCR), we have
concluded that the costs per ton of pollutant reduced are excessive for
this facility. The less expensive option (SNCR) would reduce emissions
by 198 tpy, which equates to approximately an 8.9% reduction in overall
emissions of SO2 + NOX from this facility, or a
reduction of Q/D from 14 to 13. Given the small size of the facility,
the baseline Q/D, and the potential reduction in Q/D, we find it
reasonable to eliminate this option. Therefore, we are proposing to not
require any NOX controls on this unit for this planning
period.
d. Establishment of the Reasonable Progress Goal
    40 CFR 51.308(d)(1) of the Regional Haze Rule requires states to
``establish goals (in deciviews) that provide for Reasonable Progress
towards achieving natural visibility conditions'' for each Class I area
of the state. These RPGs are interim goals that must provide for
incremental visibility improvement for the most impaired visibility
days, and ensure no degradation for the least impaired visibility days.
The RPGs for the first planning period are goals for the year 2018.
    Based on (1) the results of the WRAP CMAQ modeling, and (2) the
results of the four-factor analysis of Montana point sources, we
established RPGs for the most impaired days for all of Montana's Class
I areas, as identified in Table 196 below. Also shown in Table 197 is a
comparison of the RPGs to the URP for Montana Class I areas. The RPGs
for the 20% worst days fall short

of the URP by the amounts shown in the table.

Table 196--Comparison of Reasonable Progress Goals to Uniform Rate of Progress on Most Impaired Days for Montana
                                                  Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                      Visibility conditions on 20% worst days
                                                                    (deciview)
                                                 ------------------------------------------------  Percentage of
              Montana class I area                  Average for                                    URP achieved
                                                  20% worst days                     RPG (WRAP          (%)
                                                  (baseline 2000-  2018 URP goal    projection)
                                                       2004)
----------------------------------------------------------------------------------------------------------------
Anaconda-Pintler WA.............................           13.41           12.02           12.94              34
Bob Marshall WA.................................           14.48           12.91           13.83              41
Cabinet Mountains WA............................           14.09           12.56           13.31              51
Gates of the Mountains WA.......................           11.29           10.15           10.82              41
Glacier NP......................................           22.26           19.21           21.48              26
Medicine Lake WA................................           17.72           15.42           17.36              16
Mission Mountain WA.............................           14.48           12.91           13.83              41
Red Rock Lakes WA...............................           11.76           10.52           11.23              43
Scapegoat WA....................................           14.48           12.91           13.83              41
Selway-Bitterroot WA............................           13.41           12.02           12.94              34
U.L. Bend WA....................................           15.14           13.51           14.85              18
Yellowstone NP..................................           11.76           10.52           11.23              43
----------------------------------------------------------------------------------------------------------------

    Our RPGs for each Class I area for 2018 for the 20% worst days
represents the improvement shown in Table 197. Our RPGs establish a
slower rate of progress than the URP. The number of years necessary to
attain natural conditions was calculated by dividing the amount of
improvement needed by the rate of progress established by the RPGs.
Table 197 shows the number of years it would take to attain natural
conditions if visibility improvement continues at the rate of progress
established by the RPGs.

                Table 197--Number of Years To Reach Natural Conditions for Montana Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                 Average for                     RPG Rate of
                                2064 natural   20% worst days    Improvement     improvement    Number of years
     Montana class I area        conditions    (Baseline 2000-     needed        (deciview/     to reach natural
                                 (deciview)         2004)        (deciview)         year)          conditions
----------------------------------------------------------------------------------------------------------------
Anaconda-Pintler WA..........            7.43           13.41            5.98            0.03                204
Bob Marshall WA..............            7.73           14.48            6.75            0.04                166
Cabinet Mountains WA.........            7.52           14.09            6.57            0.05                135
Gates of the Mountains WA....            6.38           11.29            4.91            0.03                167
Glacier NP...................            9.18           22.26           13.08            0.05                268
Medicine Lake WA.............            7.89           17.72            9.83            0.02                437
Mission Mountain WA..........            7.73           14.48            6.75            0.04                166
Red Rock Lakes WA............            6.44           11.76            5.32            0.03                161
Scapegoat WA.................            7.73           14.48            6.75            0.04                166
Selway-Bitterroot WA.........            7.43           13.41            5.98            0.03                204
U.L. Bend WA.................            8.16           15.14            6.98            0.02                385
Yellowstone NP...............            6.44           11.76            5.32            0.03                161
----------------------------------------------------------------------------------------------------------------

    Table 198 provides a comparison of our RPGs for Montana to baseline
conditions on the least impaired days. This comparison demonstrates
that our RPGs will result in no degradation in visibility conditions in
the first planning period.

  Table 198--Comparison of Reasonable Progress Goals to Baseline Conditions on Least Impaired Days for Montana
                                                  Class I Areas
----------------------------------------------------------------------------------------------------------------
                                                            Visibility conditions on 20% best
                                                                    days  (deciview)
                                                          ------------------------------------   Achieved ``No
                   Montana class I area                     Average for 20%                    degradation''  (Y/
                                                               best days         RPG (WRAP             N)
                                                            (Baseline 2000-     projection)
                                                                 2004)
----------------------------------------------------------------------------------------------------------------
Anaconda-Pintler WA......................................              2.58              2.48                 Y
Bob Marshall WA..........................................              3.85              3.60                 Y
Cabinet Mountains WA.....................................              3.62              3.27                 Y
Gates of the Mountains WA................................              1.71              1.54                 Y

Glacier NP...............................................              7.22              6.92                 Y
Medicine Lake WA.........................................              7.26              7.11                 Y
Mission Mountain WA......................................              3.85              3.60                 Y
Red Rock Lakes WA........................................              2.58              2.36                 Y
Scapegoat WA.............................................              3.85              3.60                 Y
Selway-Bitterroot WA.....................................              2.58              2.48                 Y
U.L. Bend WA.............................................              4.75              4.57                 Y
Yellowstone NP...........................................              2.58              2.36                 Y
----------------------------------------------------------------------------------------------------------------

    The Regional Haze Rule states that if we establish a RPG that
provides for a slower rate of improvement in visibility than the rate
that would be needed to attain natural conditions by 2064, we must
demonstrate that the rate of progress for the implementation plan to
attain natural conditions by 2064 is not reasonable; and that the
progress goal we adopt is reasonable. 40 CFR 51.308(d)(1)(B)(ii).
    We are proposing that the RPGs we established for the Montana Class
I areas are reasonable, and that it is not reasonable to achieve the
glide path in 2018, for the following reasons:
    1. Findings from our four-factor analyses resulted in limited
opportunities for reasonable controls for point sources.
    2. As described previously in section V.D.2., significant
visibility impairment is caused by non-anthropogenic sources in and
outside Montana.
    We could not re-run the WRAP modeling, but anticipate that the
additional controls would result in an increase in visibility
improvement during the 20% worst days and the 20% best days. As noted
in our analyses, many of our proposed controls would result in
significant incremental visibility benefits when modeled against
natural background. We anticipate that this would translate into some
measurable improvement if modeled on the 20% worst days as well. We are
confident that this improvement would not be sufficient to achieve the
URP at Montana Class I areas.
    For purposes of this action, we are proposing RPGs that are
consistent with the additional controls we are proposing. While we
would prefer to quantify the RPGs, we note that the RPGs themselves are
not enforceable values. The more critical elements of our FIP are the
enforceable emissions limits we are proposing.
e. Reasonable Progress Consultation
    In accordance with 40 CFR 51.308(d)(3)(i) and (ii), each state that
causes or contributes to impairment in a Class I area in another state
or states is required to consult with other states and demonstrate that
it has included in its SIP all measures necessary to obtain its share
of the emission reductions needed to meet the progress goals for the
Class I area. If the state has participated in a regional planning
process, the state must ensure it has included all measures needed to
achieve its apportionment of emission reduction obligations agreed upon
through that process.
    In this case, where EPA is promulgating a FIP, we take on the
responsibilities of the state. We propose that we have met the
requirement for consultation with other states through our
participation in the WRAP process. Through this processes, we worked
with neighboring states, and relied on the technical tools, policy
documents, and other products that all western states used to develop
their regional haze plans. The WRAP Implementation Work Group was one
of the primary collaboration mechanisms. Discussions with neighboring
states included the review of major contributing sources of air
pollution, as documented in numerous WRAP reports and projects. The
focus of this review process was interstate transport of emissions,
major sources believed to be contributing, and whether any mitigation
measures were needed. All the states relied upon similar emission
inventories, results from source apportionment studies and BART
modeling, review of IMPROVE monitoring data, existing state smoke
management programs, and other information in assessing the extent to
which each state contributes to visibility impairment other states'
Class I areas.
    The Regional Haze Rule at 40 CFR 51.308(d)(3)(ii) requires a state
to demonstrate that its regional haze plan includes all measures
necessary to obtain its fair share of emission reductions needed to
meet RPGs. Based on the consultation described above, we identified no
major contributions that supported developing new interstate
strategies, mitigation measures, or emission reduction obligations.
Both EPA and neighboring states agreed that the implementation of BART
and other existing measures in state regional haze plans were
sufficient for the states to meet the RPGs for their Class I areas, and
that future consultation would address any new strategies or measures
needed.
f. Mandatory Long-Term Strategy Requirements
    40 CFR 51.308(d)(3)(v) requires that we, at a minimum, consider
certain factors in developing our LTS (the LTS factors). These are: (a)
Emission reductions due to ongoing air pollution control programs,
including measures to address RAVI; (b) measures to mitigate the
impacts of construction activities; (c) emissions limitations and
schedules for compliance to achieve the RPG; (d) source retirement and
replacement schedules; (e) smoke management techniques for agricultural
and forestry management purposes including plans as currently exist
within the state for these purposes; (f) enforceability of emissions
limitations and control measures; and (g) the anticipated net effect on
visibility due to projected changes in point, area, and mobile source
emissions over the period addressed by the LTS.
i. Reductions Due to Ongoing Air Pollution Programs
    In addition to our BART determinations, our LTS incorporates

emission reductions due to a number of ongoing air pollution control
programs.
a. Prevention of Significant Deterioration/New Source Review Rules
    The two primary regulatory tools for addressing visibility
impairment from industrial sources are BART and the PSD New Source
Review rules. The PSD rules protect visibility in Class I areas from
new industrial sources and major changes to existing sources. Title 17,
Chapter 8 of the ARM contain requirements for visibility impact
assessment and mitigation associated with emissions from new and
modified major stationary sources. A primary responsibility of Montana
under these rules is visibility protection. ARM 17.8.1106 requires an
owner or operator of a major source or major modification to
demonstrate that the emissions will not cause or contribute to adverse
impact on a Class I area or the Department shall not issue a permit.
ARM 17.8.1107 describes the modeling methods.
b. Montana's Phase I Visibility Protection Program
    Montana's Visibility SIP was approved as meeting the requirements
of 40 CFR 51.305 (Monitoring for RAVI) and 40 CFR 51.307 (New Source
Review) on June 6, 1986 (51 FR 20646). On February 17, 2012, Montana
submitted a revised Visibility SIP, which as explained in the
submittal, includes administrative updates to rule citations, board
affiliation, and grammar/punctuation edits to these sections.
    EPA will act on the revisions to the sections addressing monitoring
for RAVI, new source review, and other sections in a future action.
c. On-going Implementation of State and Federal Mobile Source
Regulations
    Mobile source NOX and SO2 emissions are
expected to decrease in Montana from 2002 to 2018.\316\ This reduction
will result from numerous ``on the books'' federal mobile source
regulations described below. This trend is expected to provide
significant visibility benefits. Beginning in 2006, EPA mandated new
standards for on-road (highway) diesel fuel, known as ultra-low sulfur
diesel. This regulation dropped the sulfur content of diesel fuel from
500 ppm to 15 ppm. Ultra-low sulfur diesel fuel enables the use of
cleaner technology diesel engines and vehicles with advanced emissions
control devices, resulting in significantly lower emissions.
---------------------------------------------------------------------------

    \316\ WRAP TSD. and Final Report, WRAP Mobile Source Emission
Inventories Updated, dated May 2006.
---------------------------------------------------------------------------

    Diesel fuel intended for locomotive, marine, and non-road (farming
and construction) engines and equipment was required to meet a low
sulfur diesel fuel maximum specification of 500 ppm sulfur in 2007
(down from 5000 ppm). By 2010, the ultra-low sulfur diesel fuel
standard of 15 ppm sulfur applied to all non-road diesel fuel.
Locomotive and marine diesel fuel will be required to meet the ultra-
low sulfur diesel standard beginning in 2012, resulting in further
reductions of diesel emissions.
ii. Measures to Mitigate the Impacts of Construction Activities
    In developing our LTS, we have considered the impact of
construction activities. Based on our general knowledge of construction
activity in the State, and without conducting extensive research on the
contribution of emissions from construction activities to visibility
impairment in Montana Class I areas, we propose to find that current
State regulations adequately address construction activities because
the regulations already require controls for these sources. Current
rules addressing impacts from construction activities in Montana
include ARM 17.8.308, which regulates fugitive dust emissions. The rule
requires that ``no person shall operate a construction site or
demolition project unless reasonable precautions are taken to control
emissions of airborne particulate matter.'' The SIP rule also requires
that ``[s]uch emissions of airborne particulate matter from any
stationary source shall not exhibit an opacity of 20% or greater
averaged over six consecutive minutes.'' Additionally, emissions from
vehicles at construction site are expected to decrease due to on-going
implementation of federal mobile source regulations. ARM 18.8.743
requires permits for asphalt concrete plants, mineral crushers, and
mineral screens that have a potential to emit that is greater than 15
tpy.
iii. Emission Limitations and Schedules for Compliance
    For those sources subject to BART: Ash Grove Cement Company; PPL
Montana, LLC Colstrip Steam Electric Station (Unit 1 and Unit 2);
Holcim (US), Inc.; and PPL Montana, LLC JE Corette Steam Electric
Station, we have included proposed emission limits and schedules of
compliance in regulatory text at the end of this proposal.
    As described earlier in Section V.C.3.b.iii, we are proposing that
we make a BART determination in the future for CFAC if the sources at
that facility begin operating. Additionally, we also are proposing that
those sources at CFAC will be required to implement that determination
within five years of our final FIP for this action.
    For the source that is subject to additional controls for RP
requirements, Devon, we have included proposed emission limits and
schedules of compliance in regulatory text at the end of this proposal.
    We are proposing to determine whether additional controls will be
required for Green Investment Group, Inc. (previously owned by Smurfit
Stone Container Enterprises Inc.) if the sources at that facility begin
operating. We also are proposing that those sources will be required to
implement any additional controls that are required by those
determinations within this planning period. The proposed schedules for
implementation of additional controls for this source is identified
within the four factor analyses for this source.
iv. Sources Retirement and Replacement Schedules
    Even though the sources at CFAC and Green Investment Group Inc. are
not currently operating, we are not relying on those source retirements
or replacements in the LTS. Replacement of existing facilities will be
managed according to Montana's existing PSD program. The 2018 modeling
that WRAP conducted included one new power plant in Montana that is
unlikely to be built.\317\ Construction of new power plants or
replacement of existing plants prior to 2018 is unlikely.
---------------------------------------------------------------------------

    \317\ Email from Debbie Skibicki to Vanessa Hinkle dated January
4, 2012 regarding Roundup Power.
---------------------------------------------------------------------------

v. Agricultural and Forestry Smoke Management Techniques
    We are proposing to use the WRAP's estimates of fire emissions in
our analysis for Montana. Table 199, below, shows WRAP's estimate of
emissions from fire in Montana for the 2000-2004 baseline period.

                      Table 199--Annual Average Emissions From Fire (2000-2004) (Tons/Year)
----------------------------------------------------------------------------------------------------------------
              Source                   PM2.5         PM10         NOX          SO2           OC           EC
----------------------------------------------------------------------------------------------------------------
Natural...........................        2,911        8,496       13,770        4,634       38,324        7,743
Anthropogenic.....................          279          713        1,513          500        3,745          759
                                   -----------------------------------------------------------------------------
    Total.........................        3,190        9,209       15,283        5,134       42,069        8,502
----------------------------------------------------------------------------------------------------------------

    A more detailed description of the inventories can be found in the
docket.\318\ 40 CFR 308(d)(3)(v)(E) of the Regional Haze Rule requires
the LTS to address smoke management techniques for agricultural and
forestry burning. These two sources generally have a very small
contribution to visibility impairment in Montana Class I areas. Much of
these fire emissions are from wildfires, which fluctuate significantly
from year to year. The following paragraph summarizes source
apportionment analyses conducted by the WRAP.
---------------------------------------------------------------------------

    \318\ WRAP TSD; Development of 2000-04 Baseline Period and 2018
Projection Year Emission Inventories, FINAL dated May 2007;
Emissions Overview, for which WRAP did not include a date; 2002
Planning Simulation Version D Specification Sheet for which WRAP did
not include a date; 1996 Fire Emission Inventory dated December
2002. The actual inventories can be found in the docket in the
spreadsheets with the following title: 02d Area Source Inventory.
---------------------------------------------------------------------------

    As described previously in Sections V.D.6.b., most of the emissions
from fire are from wildfires which fluctuate significantly from year to
year. Anthropogenic fire contributes 8% to primary organic aerosol
emissions, 6% to EC emissions, less than 1% to PM2.5
emissions, less than 1% to PM10 emissions, 1% to
SO2 emissions, and less than 1% to NOX emissions.
Natural fire contributes 80% to primary organic aerosol emissions, 65%
to EC emissions, 4% to PM2.5 emissions, 1% to
PM10 emissions, 9% to SO2 emissions, and 6% to
NOX emissions. As described previously in Section V.D.2., OC
contributes 15% to 64%, EC contributes 4% to 8%, fine particulate
contributes 1% to 7%, coarse particulate contributes 4% to 8%,
SO2 contributes 8% to 28%, and NOX contributes 3%
to 27% of the total light extinction to Montana Class I areas.
    40 CFR 308(d)(3)(v)(E) of the Regional Haze Rule requires states to
consider smoke management techniques for agricultural and forestry
burning in their LTS. We are proposing to approve amendments to
Montana's existing smoking management program that will ensure that the
State's program meets the Regional Haze Rule requirement.
    Montana's existing smoke management program regulates major and
minor sources of open burning; and the State operates a year round open
burning program as well as issues air quality open burning permits for
specific types of open burning.\319\ On February 17, 2012, Montana
submitted a revised Montana Visibility Plan (Plan) that contained
revisions to the smoke management program. As described in Montana's
``Explanation of Proposed Action'' the revised Plan ``includes a
reference to BACT as the current visibility mitigation measure for open
burning administered through the Department's open burning permit
program''. The revised Plan requires Montana to consider the visibility
impact of smoke on the mandatory federal class I areas when developing,
issuing or conditioning permits and when making dispersion forecast
recommendations through the implementation of Title 17, Chapter 8,
Subchapter 6, Open Burning. These revisions appear in the paragraph of
the Plan titled ``Smoke Management''.\320\ We are proposing that to
approve the revisions to this paragraph titled ``Smoke Management'' as
meeting the requirement in 40 CFR 308(d)(3)(v)(E) because the Plan
controls emissions from these sources by requiring BACT and takes into
consideration the visibility impacts on the mandatory class I areas. We
will take action in a future notice on the additional revisions in the
Montana Visibility Plan, which as explained in the State's February 17,
2012 submittal include administrative updates to rule citations, board
affiliation, and grammar/punctuation edits.
---------------------------------------------------------------------------

    \319\ There are several key elements of Montana's existing smoke
management program, which include: (1) Smoke is monitored in Montana
(http://www.satguard.com/usfs4/realtime/MT.asp); (2) the open
burning SIP regulations require best available control technology
(BACT) as the visibility mitigation measure for open burning
administered through MDEQ's open burning permit program; and (3) the
State participates in Montana State Airshed Group, which implements
an enhanced smoke management plan (information on the Montana State
Airshed Group can be found at http://www.smokemu.org/about.cfm).
    \320\ State of Montana Air Quality Control Implementation Plan,
Volume I, Chapter 9, p. 9.6(8) (Dec. 2, 2011).
---------------------------------------------------------------------------

vi. Enforceability of Montana's Measures
    40 CFR 51.308(d)(3)(v)(F) of the Regional Haze Rule requires us to
ensure that emission limitations and control measures used to meet RPGs
are enforceable. In addition to what is required by the Regional Haze
Rule, general FIP requirements mandate that the FIP must also include
adequate monitoring, recordkeeping, and reporting requirements for the
regional haze emission limits and requirements. See CAA section 110(a).
As noted, we are proposing specific BART and other emission limits and
compliance schedules. For SO2 and NOX limits, we
are proposing to require the use of CEMS that must be operated and
maintained in accordance with relevant EPA regulations, in particular,
40 CFR part 75. For PM limits, we are requiring regular testing. We are
proposing to require that relevant records be kept for five years, and
that sources report excess emissions on a quarterly basis.
    In addition to these requirements, various requirements that are
relevant to regional haze are codified in Montana's regulations,
including Montana's PSD and other provisions mentioned above.
vii. Anticipated Net Effect on Visibility Due to Projected Changes
    The anticipated net effect on visibility due to projected changes
in point, area, and mobile source emissions during this planning period
is addressed in section V.D.4 above.

E. Coordination of RAVI and Regional Haze Requirements

    Our visibility regulations direct states to coordinate their RAVI
LTS and monitoring provisions with those for regional haze, as
explained in section IV.G, above. Under our RAVI regulations, the RAVI
portion of a state SIP must address any integral vistas identified by
the FLMs pursuant to 40 CFR 51.304. See 40 CFR 51.302. An integral
vista is defined in 40 CFR 51.301 as a ``view perceived from within the
mandatory Class I federal area of a specific landmark or panorama
located outside the boundary of the mandatory Class I federal area.''
Visibility in any mandatory Class I Federal area includes any integral
vista associated with that

area. The FLMs did not identify any integral vistas in Montana. In
addition, there have been no certifications of RAVI in the Montana
Class I areas, nor are any Montana sources affected by the RAVI
provisions. We commit to coordinate the Montana regional haze LTS with
our RAVI FIP LTS. We propose to find that the Regional Haze FIP
appropriately supplements and augments the EPA FIP for RAVI visibility
provisions by updating the monitoring and LTS provisions to address
regional haze. We discuss the relevant monitoring provisions further
below.

F. Monitoring Strategy and Other Implementation Plan Requirements

    40 CFR 51.308(d)(4) requires that the FIP contain a monitoring
strategy for measuring, characterizing, and reporting regional haze
visibility impairment that is representative of all mandatory Class I
Federal areas within the state. This monitoring strategy must be
coordinated with the monitoring strategy required in 40 CFR 51.305 for
RAVI. As 40 CFR 51.308(d)(4) notes, compliance with this requirement
may be met through participation in the IMPROVE network. 40 CFR
51.308(d)(4)(i) further requires the establishment of any additional
monitoring sites or equipment needed to assess whether RPGs to address
regional haze for all mandatory Class I Federal areas within the state
are being achieved. Consistent with EPA's monitoring regulations for
RAVI and regional haze, EPA will rely on the IMPROVE network for
compliance purposes, in addition to any RAVI monitoring that may be
needed in the future. Further information on monitoring methods and
monitor locations can be found in the docket.321 322 The
most recent report also can be found in the docket.\323\ Therefore, we
propose to find that we have satisfied the requirements of 40 CFR
51.308(d)(4) enumerated in this paragraph.
---------------------------------------------------------------------------

    \321\ Visibility Monitoring Guidance, EPA-454/R-99-003, June
1999, http://www.epa.gov/ttn/amtic/files/ambient/visible/r-99-003.pdf.
    \322\ Guidance for Tracking Progress Under the Regional Haze
Rule, EPA-454/B-03-004, September 2003, available at http://www.epa.gov/ttncaaa1/t1/memoranda/rh_tpurhr_gd.pdf. Figure 1-2
shows the monitoring network on a map, while Table A-2 lists Class I
areas and corresponding monitors.
    \323\ Spatial and Seasonal Patterns and Temporal Variability of
Haze and its Constituents in the United States, Report V, ISSN 0737-
5352-87, June 2011.
---------------------------------------------------------------------------

    40 CFR 51.308(d)(4)(ii) requires that EPA establish procedures by
which monitoring data and other information are used in determining the
contribution of emissions from within Montana to regional haze
visibility impairment at mandatory Class I Federal areas both within
and outside the State. The IMPROVE monitoring program is national in
scope, and other states have similar monitoring and data reporting
procedures, ensuring a consistent and robust monitoring data collection
system. As 40 CFR 51.308(d)(4) indicates, participation in the IMPROVE
program constitutes compliance with this requirement.
    40 CFR 51.308(d)(4)(iv) requires that the FIP provide for the
reporting of all visibility monitoring data to the Administrator at
least annually for each mandatory Class I Federal area in the state. To
the extent possible, EPA should report visibility monitoring data
electronically. 40 CFR 51.308(d)(4)(vi) also requires that the FIP
provide for other elements, including reporting, recordkeeping, and
other measures, necessary to assess and report on visibility. We
propose that EPA's participation in the IMPROVE network ensures that
the monitoring data is reported at least annually and is easily
accessible; therefore, such participation complies with this
requirement.
    40 CFR 51.308(d)(4)(v) requires that EPA maintain a statewide
inventory of emissions of pollutants that are reasonably anticipated to
cause or contribute to visibility impairment in any mandatory Class I
Federal area. The inventory must include emissions for a baseline year,
emissions for the most recent year for which data are available, and
estimates of future projected emissions. EPA must also include a
commitment to update the inventory periodically. Please refer to
section V.D.1, above, where we discuss EPA's emission inventory for
Montana. EPA proposes that we will update statewide emissions
inventories periodically and review periodic emissions information from
other states and future emissions projections. Additionally, during the
next planning period EPA intends to review and consider emissions from
oil and gas activities, as well as from other sources. Therefore, we
propose that this satisfies the requirement.

G. Coordination With FLMs

    The Forest Service manages Anaconda-Pintler WA, Bob Marshall WA,
Cabinet Mountains WA, Gates of the Mountains WA, Mission Mountains WA,
Scapegoat WA, and Selway-Bitterroot WA. The Fish and Wildlife Service
manages the Medicine Lake WA, Red Rocks Lake WA, and U.L. Bend WA. The
National Park Service manages Glacier NP and Yellowstone NP. Although
the FLMs are very active in participating in the RPOs, the Regional
Haze Rule grants the FLMs a special role in the review of regional haze
FIPs, summarized in section IV.H, above.
    Initially, MDEQ met the requirement of 40 CFR 51.308(i)(1) by
sending letters to the FLMs dated November 5, 1999. The letters
included the title of the official to which the FLM of any mandatory
Class I Federal area could submit any recommendations on the
implementation of the regional haze rule including the identification
of impairment of visibility in any mandatory Class I Federal area(s)
and the identification of elements for inclusion in the visibility
monitoring strategy required by 40 CFR 51.305 and the regional haze
rule.
    Under 40 CFR 51.308(i)(2), we were obligated to provide the Forest
Service, the Fish and Wildlife Service, and the National Park Service
with an opportunity for consultation, in person and at least 60 days
prior to holding a public hearing on the Regional Haze FIP. We sent a
draft of our Regional Haze FIP to the Forest Service, the Fish and
Wildlife Service, and the National Park Service on February 16, 2012
and March 5, 2012. We notified the FLMs of our public hearings (as
initially scheduled) on March 14, 2012. 40 CFR 51.308(i)(3) requires
that we provide in our Regional Haze FIP a description of how we
addressed any comments provided by the FLMs. We revised our proposed
Regional Haze FIP to incorporate comments received by the FLMs.
    Lastly, 40 CFR 51.308(i)(4) specifies the regional haze FIP must
provide procedures for continuing consultation with the FLMs on the
implementation of the visibility protection program required by 40 CFR
51.308, including development and review of implementation plan
revisions and 5-year progress reports, and on the implementation of
other programs having the potential to contribute to impairment of
visibility in mandatory Class I Federal areas. We commit to continue to
coordinate and consult with the FLMs as required by 40 CFR
51.308(i)(4). We intend to consult the FLMs in the development and
review of implementation plan revisions; review of progress reports;
and development and implementation of other programs that may
contribute to impairment of visibility at Montana and other Class I
areas.
    We are proposing that we have complied with the requirements of 40
CFR 51.308(i).

H. Periodic FIP Revisions and Five-Year Progress Reports

    Consistent with 40 CFR 51.308(g), we are committing to prepare a
progress report in the form of a FIP revision, every five years
following the final FIP. The FIP revision will evaluate progress
towards the RPG for each mandatory Class I Federal area located within
Montana and in each mandatory Class I Federal area located outside
Montana that may be affected by emissions from within Montana. The FIP
revision will include all the activities in 40 CFR 51.308(g).

VI. Proposed Action

A. Montana Visibility SIP

    B. We are proposing to approve the changes to one of the sections
of Montana's Visibility SIP that were submitted on February 17, 2012
that includes amendments to the ``Smoke Management'' section, which
adds a reference to BACT as the visibility control measure for open
burning as currently administered through the State's air quality
permit program.

Montana Regional Haze FIP

    We are proposing the promulgation of a FIP to address Regional Haze
for Montana that we have identified in this proposal. The proposed FIP
includes the following elements:
     For Ash Grove Cement:
    [cir] A NOX BART determination and emission limit of 8
lb/ton clinker that applies on a 30-day rolling average, and a
requirement that the owners/operators comply with this NOX
BART limit within five (5) years of the effective date of our final
rule.
    [cir] A SO2 BART determination and emission limit of
11.5 lb/ton clinker that applies on a 30-day rolling average, and a
requirement that the owners/operators comply with this SO2
BART limit within 180 days of the effective date of our final rule.
    [cir] The following PM BART determination and emission limit: if
the process weight rate of the kiln is less than or equal to 30 tons
per hour, then the emission limit shall be calculated using
E=4.10p\0.67\ where E = rate of emission in pounds per hour and p =
process weight rate in tons per hour; however, if the process weight
rate of the kiln is greater than 30 tons per hour, then the emission
limit shall be calculated using E = 55.0p\0.11\-40, where E = rate of
emission in pounds per hour and P = process weight rate in tons per
hour. This limit applies on a 30-day rolling average, and a requirement
that the owners/operators comply with this PM BART limit within 30 days
of the effective date of our final rule.
     For Colstrip Units 1 and 2:
    [cir] NOX BART determinations and emission limits of
0.15 lb/MMBtu that apply singly to each of these units on a 30-day
rolling average, and a requirement that the owners/operators comply
with these NOX BART limits within five (5) years of the
effective date of our final rule.
    [cir] SO2 BART determinations and emission limits of
0.08 lb/MMBtu that apply singly to each of these units on a 30-day
rolling average, and a requirement that the owners/operators comply
with these SO2 BART limits within five (5) years of the
effective date of our final rule.
    [cir] PM BART determinations and emission limits of 0.10 lb/MMBtu
that apply singly to each of these units on a 30-day rolling average,
and a requirement that the owners/operators comply with these PM BART
limits within 30 days of the effective date of our final rule.
     For Holcim:
    [cir] A NOX BART determination and emission limit of 5.5
lbs/ton clinker produced that applies on a 30-day rolling average, and
a requirement that the owners/operators comply with this NOX
BART limit within five (5) years of the effective date of our final
rule.
    [cir] A SO2 BART determination and emission limit of 1.3
lbs/ton clinker produced that applies on a 30-day rolling average, and
a requirement that the owners/operators comply with this SO2
BART limit within 180 days of the effective date of our final rule.
    [cir] A PM BART determination and emission limit of 0.77 lb/ton
clinker produced that applies on a 30-day rolling average, and a
requirement that the owners/operators comply with this PM BART limit
within 30 days of the effective date of our final rule.
     For Corette:
    [cir] A NOX BART determination and emission limit of .40
lb/MMBtu that applies on a 30-day rolling average, and a requirement
that the owners/operators comply with this NOX BART limit
within 30 days of the effective date of our final rule.
    [cir] A SO2 BART determination and emission limit of
0.70 lb/MMBtu that applies on a 30-day rolling average, and a
requirement that the owners/operators comply with this SO2
BART limit within 30 days of the effective date of our final rule.
    [cir] A PM BART determination and emission limit of 0.10 lb/MMBtu
that applies on a 30-day rolling average, and a requirement that the
owners/operators comply with this PM BART limit within 30 days of the
effective date of our final rule.
     For Devon Energy Blaine County 1 Compressor
Station, a NOX emission limit of 21.8 lb/hr that applies on
a 30-day rolling average, and a requirement, as described in our
proposed regulatory text for 40 CFR Sec.  52.1395, that the owners/
operators comply with this limit as expeditiously as practicable, but
no later than July 31, 2018.
     For CFAC, CFAC must notify EPA 60 days in advance of
resuming operation. Once CFAC notifies EPA that it intends to resume
operation, EPA will initiate and complete a BART determination after
notification and revise the FIP as necessary in accordance with
regional haze requirements, including the BART provisions in 40 CFR
51.308(e). CFAC will be required to install any controls that are
required as soon as practicable, but in no case later than five years
following the effective date of this action.
     For the M2Green Redevelopment LLC, Missoula Site, M2Green
Redevelopment LLC must notify EPA 60 days in advance of resuming
operation. Once M2 Green Redevelopment LLC notifies EPA that it intends
to resume operation, EPA will initiate and complete a four factor
analysis after notification and revise the FIP as necessary in
accordance with regional haze requirements including the ``reasonable
progress'' provisions in 40 CFR 51.308(d)(1). M2 Green Redevelopment
LLC will be required to install any controls that are required as soon
as practicable, but in no case later than July 31, 2018.
     Monitoring, recordkeeping, and reporting requirements for
the above six units to ensure compliance with these emission
limitations.
     RPGs consistent with the proposed FIP limits.
     LTS elements that reflect the other aspects of the
proposed FIP.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

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

B. Paperwork Reduction Act

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

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's (SBA) regulations at 13