For every kiln, the standard deviation in the monthly NOX
emission rate was lower after the application of SNCR than before,
indicating a lower variation in NOX emissions.
    Comment: Holcim argued that a detached plume may result from
operation of the SNCR in the winter months, which will make it
necessary to not operate the SNCR system or to allow a condition where
visibility is adversely impacted to continue. The detached plume could
be the result of the formation of ammonium salt reactions with sulfate
or chlorides.
    Response: We disagree. As discussed by Miller,\13\ there are
several factors that could contribute to a visible detached plume, and
these include moisture, temperature, and availability of the
constituents that contribute to the plume--ammonia, sulfates and
chlorides. Ammonia slip from the SNCR process can be well controlled in
a cement kiln, and the SNCR system would not affect the amount of
ammonia contributed by raw materials.
---------------------------------------------------------------------------

    \13\ Miller, F. M., ``Management of Detached Plumes in Cement
Plants'' 2001 IEEE-IAWPCA Cement Industry Technical Conference
Vancouver, British Colombia, Canada April 2001.
---------------------------------------------------------------------------

    Sulfates and chlorides are largely the result of impurities in the
raw materials, and ammonia can be contributed by raw materials.
Holcim's SO2 emissions are low indicating low levels of
sulfates in the exhaust. Therefore, the risk of an ammonium sulfate
plume, even with ammonia present, is small. The presence of chlorides
will depend upon the raw materials and whether the chlorides become
bound to alkaline material before being emitted up the stack.
    Chlorides, if present, will typically preferentially be bound to
alkaline material that is present rather than be emitted. Holcim did
not provide any information on stack chloride emission levels at this
site to support their concerns about detached plume from ammonium
chloride.
    Because of the importance of impurities in the raw materials in
contributing to the chemical constituents that form a plume, the
experience at one kiln cannot be directly applied to another without
more information. Therefore, while there may be a risk of a visible
plume at the Trident kiln, Holcim has not provided enough data to
indicate that addition of an SNCR system would increase this risk
significantly. Furthermore, a localized plume would not necessarily
impact a Class I area and Holcim has not provided any information
indicating such an impact.
    Comment: Holcim indicated that EPA failed to consider the
NOX control technology already installed at the Trident
plant. Holcim explains that they changed the burner at Trident in May
2009 to a multichannel LNB design as part of the company's burner
system modification for NOX control, as detailed in Holcim's
2007 BART analysis.
    Holcim stated that EPA's BART analysis ignored the installation of
the multichannel LNB at the Trident plant, in contravention of EPA's
obligation to consider ``any existing pollution control

technology in use at the source'' as part of the five-factor BART
analysis. 42 U.S.C. 7491(g)(2). Holcim's BART analysis was prepared and
submitted in 2007, before the multichannel LNB technology was
installed.
    Holcim explains that they originally installed a multichannel
burner in April 2008 but it caused operational issues and was removed
in July 2008. The multichannel burner was redesigned, installed in May
2009, and has operated continuously since that time. According to
Holcim, the multichannel design allows the fuels to be separated into
different channels and enables Holcim to more precisely control the
amount of air passing through each of the channels. Consequently,
Holcim says, they can better control the flame characteristics in the
kiln, which results in higher thermal efficiency of the kiln and
improved product quality.
    Holcim stated that they also anticipated that the multichannel
design would reduce NOX and SO2 emissions. Holcim
acknowledges that the effects of the technology are difficult to
quantify. Based on a comparison of NOX emissions pre- and
post-installation of the LNB technology where the fuel mix was
generally the same, Holcim says the plant's NOX emissions
decreased by approximately 13% with the installation of the
multichannel LNB. In addition to the multichannel LNB, Holcim stated
that they installed an indirect firing system for the petroleum coke
system.
    Holcim notes that EPA used a baseline for the Trident plant of
years 2008 through 2011, a period of time that already includes the
effects of the LNB technology at the plant. Holcim stated that EPA
assumed in its BART proposal for the Trident plant that the combination
of LNB and indirect firing would achieve a NOX reduction of
15%. However, Holcim stated that a 13% reduction in NOX
emissions has already been achieved through prior installation of the
multichannel LNB. Holcim states there is no basis to assume that
indirect firing would improve NOX emissions reductions at
Trident and that additional NOX reductions can only be
obtained through installation of SNCR. As a result, Holcim concludes
that EPA's analysis of the cost-effectiveness and visibility impact for
the installation of indirect firing is, ``clearly erroneous and should
be disregarded''.
    Response: We agree with aspects of this comment, but disagree with
others. As described in more detail below, Holcim has not provided
enough information to demonstrate that the installed multi-channel
burner that Holcim installed is in fact a low NOX burner. In
any case, the baseline used for the BART analysis included emissions
averaged over a four year period (2008-2011), which would have included
the time that the multi-channel burner was installed. We have decided
that the incremental cost of indirect firing and a low NOX
burner is not justified and have revised the BART emission limit
accordingly.
    We agree that our BART proposal, did not consider installation of
the new burners that Holcim describes as ``multichannel LNB'' in its
March 20, 2008 letter to Vickie Walsh of the MDEQ. As the June 9, 2009
letter from Holcim to EPA notes, ``a low NOX burner
modification would require low primary air and, thus, a conversion of
Trident's firing system from a direct to an indirect system.'' Based on
the information we have, it appears that the Trident kiln has not
installed an indirect firing system for coal and therefore the
multichannel burner does not meet the definition of LNB in Holcim's
letter. The burner is not capable of operating at low primary air
levels on pulverized coal and cannot achieve the NOX
reductions that an indirect firing system would achieve.
    However, we disagree that we must credit the newly installed burner
with a 13% reduction in NOX emissions, because we are
lacking validation data that such a reduction has been achieved. Holcim
has only presented summary information to support the claim of 13%
reduction and has not provided the underlying data to validate its
claim. Our examination of NOX emissions data provided by
Holcim on March 2, 2012, covering the period from 2008 through 2011
(referenced in our proposal at 77 FR 24018, footnote 93), does not
reveal any evidence of sustained NOX emission reduction
after May of 2009. We have used data from the time period 2009-2011,
after the new burner was installed, in calculating baseline emissions.
77 FR 24014, Table 39, footnote 1. This baseline accurately reflects
current conditions and is appropriate for comparison to available
control scenarios.
    Nevertheless, since a switch to indirect firing to accommodate
installation of LNB, as described in our FIP proposal, would have an
unreasonably high incremental cost-effectiveness of $8,029/ton, with
minimal visibility benefits (see our response below), we are not
requiring a switch to indirect firing and LNB as BART in the final FIP.
We also are clarifying that we intended this option to include
switching to indirect firing and a LNB. We have recalculated the
proposed BART limit for NOX to reflect a 50% reduction in
NOX emissions from that baseline by addition of SNCR alone,
rather than the 58% reduction we previously used, which reflected
switching to indirect firing and adding a LNB plus SNCR.
    In recalculating our proposed BART emission limit for
NOX, we continue to rely on the estimate of baseline
NOX emissions in lb/ton clinker provided in Holcim's 2012
submittal, cited in our proposal at 77 FR 24018, footnote 93. That
submittal listed a 99th percentile 30-day rolling average
NOX emission rate of 12.6 lb/ton clinker, for the period
2008-2011. Applying a 50% reduction to the 99th percentile figure
yields 6.3 lb/ton clinker. To allow for a sufficient margin of
compliance for a 30-day rolling average limit that would apply at all
times, including startup, shutdown and malfunction (as explained in our
proposal at 77 FR 24018), we are setting the BART limit at 6.5 lb/ton
clinker in our final rule.
    Since the estimated baseline NOX emissions have not
changed from our proposal, and since our estimate of 50% NOX
reduction for SNCR alone has not changed from our proposal, our
estimate of 556 tons per year of expected NOX reduction for
SNCR alone has also not changed from our proposal.
    Comment: Holcim stated that EPA underestimated the costs of
installing and maintaining a SNCR system. Holcim stated that the
company calculated the direct annual costs of SNCR to be $443,341 and
the indirect annual costs for SNCR to be $227,538, and that these
calculations employed a 15-year amortization schedule, as requested by
EPA in 2007.\14\ Holcim noted that EPA's estimated direct annual costs
and indirect annual costs for SNCR are lower than Holcim's estimates by
approximately 67% and 46%, respectively and suggested that the
difference may be at least in part due to EPA's use of a 20-year period
in the proposal.
---------------------------------------------------------------------------

    \14\ August 2009 Submittal (EPA-R08-OAR-2011-0851-0038); Letter
from Callie A. Videtich to Ned Pettit (Nov. 26, 2007) (EPA-R08-OAR-
2011-0851-0038).
---------------------------------------------------------------------------

    Holcim stated that it is unclear how EPA derived its numbers and
that EPA provided no explanation in the FIP proposal. Holcim requested
clarification of EPA's method for calculating these costs and urged EPA
to instead use the cost calculation numbers provided by Holcim.
    Also, Holcim stated that if EPA reviews selective catalytic
reduction (SCR) for cement kilns in subsequent reasonable progress
planning periods, and determines that Holcim must install SCR instead
of SNCR at that time then

the 20-year amortization for SNCR costs would not accurately reflect
the annual costs of installing SNCR. Holcim also stated that since the
company conducted its original analysis, Holcim has installed SNCR at
its plant in Hagerstown, Maryland in 2011, which also has a long kiln.
Holcim stated that the total capital costs for the SNCR installation at
Hagerstown were approximately $1,920,000, including the cost of
commissioning and spare parts and that, in addition, Hagerstown
budgeted $591,000 for 2012 operating costs ($1.35 per metric ton of
clinker or $1.23 per metric ton of cement). Holcim stated that actual
operating costs for 2012 through the end of April have been $179,000
($1.40 per metric ton of clinker or $1.28 per metric ton of cement).
Holcim anticipates that similar capital and operating costs would apply
to the installation of SNCR at Trident. Holcim requested that EPA use
these updated figures in its analysis of the costs of SNCR at Trident.
    Response: We agree with aspects of this comment, but disagree with
others. We note that the letter to which Holcim refers requested that
Holcim reanalyze annualized costs using a 15-year amortization period
for a scrubber, not SNCR. We agree that EPA underestimated the cost of
SNCR and that clarification on cost is needed, but we disagree with the
statement that EPA provided no explanation in its proposal on how EPA
derived its cost numbers. We also disagree with the statement that EPA
provided no explanation for use of a 20-year amortization period. We
also disagree with the statement that SNCR costs at the Trident kiln
should be similar to Holcim's Hagerstown kiln.
    We agree that we underestimated the cost of SNCR and that
clarification is needed. The underestimate arose from our omission of
cost of reagent. In Holcim's August 12, 2009 submittal, two versions of
a SNCR cost spreadsheet were included. In one version, Holcim redacted
the line item for reagent cost, on the basis of a Confidential Business
Information (CBI) claim. This was the version we used for our proposal.
However, in its cover letter for the August 12, 2009 submittal, Holcim
stated that it later retracted its CBI claim. So the submittal included
a second version of the same SNCR cost spreadsheet, in which the
reagent line item now appears. The reagent cost is listed by Holcim in
this second version at $379,183.
    We have recalculated the annual costs of SNCR to include the cost
of reagent. Relying on the second version of the cost spreadsheet in
Holcim's August 12, 2009 submittal, we now calculate the annual costs
other than capital recovery at $526,471 and the total annual cost,
including capital recovery, at $650,399. Using an estimated emission
reduction of 556 tons per year of NOX, as we did in our
proposal (which is a 50% reduction from the NOX emissions
baseline of 1,112 tons per year), we have recalculated the cost-
effectiveness of SNCR at $1,170/ton. At this cost-effectiveness, we
still consider SNCR to be BART for NOX. Holcim has given us
no reason to think otherwise.
    We disagree with the statement that EPA provided no explanation in
its proposal on how EPA derived its cost numbers. We explained that we
relied on cost estimates supplied by Holcim for capital costs and
annual costs of SNCR, with the exception of the Capital Recovery Factor
(CRF) used. 77 FR 24015. We included a footnote to Table 44 to explain
that we relied on Holcim's capital cost estimate for SNCR. We included
a second footnote to that table to explain what CRF we used. We also
included a footnote to Table 45 to explain that we relied on Holcim's
estimate of direct annual operating costs. 77 FR 24016.
    We disagree with the statement that EPA provided no explanation for
use of a 20-year amortization period. As explained at 77 FR 24015, we
relied on Holcim's estimates of SNCR capital cost and annual costs,
with the exception of the capital recovery factor (CRF). We acknowledge
that we wrote to Holcim in 2007 to recommend 15-year amortization, and
that our decision since then to use 20-year amortization instead needs
clarification. We now clarify that after reviewing EPA national
guidance on CRFs in more detail since 2007, we determined that it would
be more appropriate to use a CRF consistent with 20 years for the
useful life of the kiln and associated SNCR controls. As explained
below, our use of a 20-year period was not arbitrary.
    The guidance we relied on was EPA's Air Pollution Control Cost
Manual (CCM), which says, in regard to SNCR, that ``In general,
indirect annual costs (fixed costs) include the capital recovery cost,
property taxes, insurance, administrative charges, and overhead.
Capital recovery cost is based on the anticipated equipment lifetime
and the annual interest rate employed. An economic lifetime of 20 years
is assumed for the SNCR system.'' EPA Air Pollution Control Cost
Manual, Sixth Edition, EPA/452/B-02-001, January 2002, Section 4.2,
Chapter 1, page 1-37. We explained in our FIP proposal that without
commitments for an early shutdown, EPA cannot consider a shorter
amortization period. 77 FR 24014. For consistency in comparing control
options for NOX and SO2 for all Montana BART
sources, our FIP proposal uses a 20-year equipment life in all the BART
analyses (provided that the equipment life of each control option is 20
years or more). The CRF for a 20-year equipment life and 7% discount
rate (the latter being recommended in Office of Management and Budget
(OMB) Circular A-4, which we cited at 77 FR 24016) is 0.0944. As shown
in Table 44 at 77 FR 24016, we multiplied Holcim's estimated capital
cost of $1,312,800 by this CRF to yield a capital recovery cost of
$123,928.
    With regard to Holcim's comment that a 20-year amortization would
misrepresent actual costs in the event that SCR rather than SNCR were
to be required in the next planning period, we cannot anticipate every
event that might happen in the future and we are not required to do so
in establishing an amortization period.
    We disagree with the statement that SNCR costs at the Trident kiln
should be similar to Holcim's Hagerstown kiln. The Trident kiln is much
smaller than the Hagerstown kiln. The Trident kiln is permitted at
425,000 tons per year of clinker production. Montana Air Quality Permit
0982-11, Condition II.B.6. The Hagerstown kiln is rated at
630,114 tons per year of clinker production capacity. Prevention of
Significant Deterioration (PSD) Permit Application for Approval, Holcim
Hagerstown, October 30, 2008. Also, the Hagerstown kiln--a dry kiln--
likely has different emission rates than the Trident kiln. Without more
information, it is not possible to determine how much of the claimed
$1,920,000 capital cost of the Hagerstown kiln SNCR system, as well as
operating costs, would be costs that are permissible for inclusion in a
BART cost estimate. For these reasons, without more information, the
costs of the SNCR system at the Hagerstown kiln are not useful for
estimating the costs at the Trident kiln. Therefore, we continue to
rely on the SNCR capital cost estimate of $1,312,800 and operating cost
estimate of $147,288 for Trident, already supplied to us by Holcim in
the August 2009 submittal. We also note that, even with a capital cost
of $1,920,000, it appears SNCR would remain cost-effective; Holcim has
provided no reason why our BART selection would change. This comment
has not resulted in any changes to our regulatory text for
NOX BART.
    Comment: Holcim indicated that EPA underestimated the costs of
installing indirect firing at Trident. Holcim stated that the company
did not include indirect firing in its 2007 BART analysis

and did not consider indirect firing to be an appropriate technology to
evaluate to achieve NOX reductions at Trident. Holcim stated
that at EPA's request, the company submitted an estimate to EPA of the
costs of installing indirect firing at Trident.\15\ Holcim stated that
in EPA's own analysis, the Agency ``inexplicably and arbitrarily''
eliminated a significant portion of the costs from Holcim's analysis.
Nonetheless, even using EPA's underestimated costs for the installation
of indirect firing and mistaken assumption that indirect firing could
reduce NOX emissions at Trident by 15%, neither the average
cost-effectiveness of indirect firing nor the incremental cost-
effectiveness of indirect firing warrant a determination that indirect
firing should be selected as BART.
---------------------------------------------------------------------------

    \15\ Letter from Greg Gannon to Laurel Dygowski, June 9, 2009.
(See EPA-R08-OAR-2011-0851-0038).
---------------------------------------------------------------------------

    Holcim pointed out that EPA is proposing to require that Holcim
install both SNCR and indirect firing at Trident based on its analysis
of the average cost-effectiveness of installing both technologies
together. Holcim stated that the overwhelming majority of
NOX emissions reductions and improvements in visibility
would result from the installation of SNCR alone and that by ignoring
the incremental costs of SNCR + indirect firing, and focusing solely on
the average cost effectiveness, Holcim states that EPA tries to make
the costs of SNCR + indirect firing appear reasonable. Holcim stated
that the average cost-effectiveness for the installation of SNCR at
Trident is well within the range of what EPA has considered for BART,
but that EPA estimated the average cost effectiveness of indirect
firing to be $4,279/ton, which is far outside the range of what EPA has
considered to be reasonable for BART. With such high costs for indirect
firing, the incremental cost-effectiveness of SNCR + indirect firing as
compared to SNCR alone is $8,029/ton. Holcim stated that EPA should
consider both the average and incremental cost effectiveness of its
BART analysis for Trident. Holcim stated that, although EPA clearly
identified the incremental cost effectiveness of SNCR + indirect
firing, EPA ``inexplicably ignored this unreasonable figure in
concluding that the combination of technologies constitutes BART for
Trident''. Holcim stated that the incremental cost effectiveness of
SNCR + indirect firing is unreasonable given the slight to nonexistent
improvement in visibility that it would achieve and that EPA should
eliminate this combination of technologies as BART.
    Holcim further stated that, based on modeling, the installation of
indirect firing and SNCR at Trident, even if it could achieve EPA's
claimed 58% reduction in NOX emissions, would result in an
improvement of visibility of only 0.424 deciview in Gates of the
Mountains WA and that this does not constitute a significant or
perceptible improvement in visibility. Holcim stated that EPA's
conclusion is even more unjustifiable considering the actual percentage
reduction that Trident could be expected to achieve with the
installation of SNCR of approximately 35% on an annual average basis.
    Finally, Holcim stated that the average cost effectiveness
estimates for indirect firing alone ($4,279/ton) and for SNCR +
indirect firing ($1,528/ton) are well above what EPA used as a cost-
effectiveness threshold for NOX in the Cross-State Air
Pollution Rule (CSAPR), which EPA promulgated last year to address
health-based standards. Holcim stated that the company does not
understand why EPA believes it appropriate to use a higher cost
threshold for an aesthetic standard than it has for a health-based
standard.
    Response: We agree with aspects of this comment, but disagree with
others. We agree that an incremental cost effectiveness of $8,029/ton,
for LNB/indirect firing + SNCR, versus SNCR alone makes LNB/indirect
firing + SNCR unreasonable for BART at the Trident kiln.
    As explained in a previous response above, we have removed
switching to indirect firing and a LNB from consideration as an option
for further reducing NOX emissions and are treating any
NOX emission reduction that may have been achieved from
installation of a new burner as part of the emissions baseline. We have
recalculated the proposed BART limit for NOX to reflect a
50% reduction in NOX emissions from that baseline by
addition of SNCR alone, rather than the 58% reduction we previously
used, which reflected a switch to indirect firing and a LNB plus SNCR.
The recalculated NOX BART limit is 6.5 lb/ton clinker.
    We disagree, however, with the statement that EPA analyzed for
indirect firing as a separate control option. We did not. Throughout
our proposal, we refer to the control option as LNB and are now
clarifying that this option was intended to include switching to
indirect firing and a LNB. We explained at 77 FR 24015 that the capital
cost estimate of $4,385,307 for LNB includes the cost of converting
from a direct to an indirect firing system to accommodate LNB,
including installation of a baghouse, additional explosion prevention,
pulverized coal storage, and dosing equipment. We cited Holcim's
additional response of August 2009 as the source of this information.
    We disagree with the statement that SNCR could be expected to
achieve only a 35% reduction in NOX emissions. See our
response to Holcim's comment above.
    We also disagree with the statement that any controls required by
our action must demonstrate a perceptible visibility improvement. In a
situation where the installation of BART may not result in a
perceptible improvement in visibility, the visibility benefit may still
be significant. The July 6, 2005 BART Guidelines state:

    even though the visibility improvement from an individual source
may not be perceptible, it should still be considered in setting
BART because the contribution to haze may be significant relative to
other source contributions in the Class I area. Thus, we disagree
that the degree of improvement should be contingent upon
perceptibility. Failing to consider less-than-perceptible
contributions to visibility impairment would ignore the CAA's intent
to have BART requirements apply to sources that contribute to, as
well as cause, such impairment.

70 FR 39129. Visibility impacts below the thresholds of perceptibility
cannot be ignored because regional haze is produced by a multitude of
sources and activities which are located across a broad geographic
area.
    With regard to Holcim's comment comparing the cost-effectiveness of
controls required under the CSAPR, with cost-effectiveness of controls
required under the Regional Haze Rule and the BART Guidelines, we
reject the comparison. The two rules address different requirements of
the CAA.
    Comment: Holcim agreed with EPA's proposal that no additional
controls constitute BART for SO2 at Trident but objected to
the imposition of a 30-day SO2 limit. In Holcim's view,
imposing a 30-day limit is neither reasonable nor necessary. Holcim's
Trident plant relies on inherent scrubbing to achieve its extremely low
SO2 emissions. EPA's modeling confirms that SO2
emissions from Trident have effectively zero visibility impact. Trident
could more than double its current SO2 emissions and still
not have any reliably predictable impact on visibility (less than 0.1
deciview). Even if all SO2 emissions from Trident were
eliminated, visibility would improve in Gates of the Mountains WA by
less than 0.05 deciview; less than one-twentieth of a perceptible
change in visibility. See

77 FR at 24021. Id. at 24021, Table 63. Holcim stated that the kiln
could not increase its emissions sufficiently to affect visibility
without exceeding its currently enforceable limit. Consequently, Holcim
stated that there simply is no need to impose short term SO2
limits to protect visibility.
    Second, Holcim stated that because Trident relies on inherent
scrubbing to control SO2, the plant has no real control over
the short-term emissions variability that results from the natural
variability in limestone from its quarry. The emissions variability
would never rise to a level that could affect visibility, but it could
cause Trident to exceed the proposed 30-day limit. Thus, the only
effect of the 30-day limit would be to impose unnecessary regulatory
burdens on the plant and expose it to potential penalties for short-
term emissions variability, over which Holcim has no control and which
would not impact visibility.
    Holcim also commented that EPA is proposing to impose an
SO2 limit that is not based on the installation of retrofit
control technology or a process change and that offers no improvement
in visibility. Holcim stated that because the proposed limit is based
on current emissions and will not improve visibility, it cannot be
considered BART; the CAA and EPA's own BART Guidelines require that, in
determining BART, the Administrator consider the degree of improvement
in visibility which may reasonably be anticipated to result from the
use of such technology. Holcim requested that EPA eliminate its
proposed 30-day SO2 limit as it does not represent BART and
would impose unnecessary regulatory burdens and new compliance risks
while serving no visibility purpose.
    Response: We disagree. The July 6, 2005 BART Guidelines state that
``* * * you must establish an enforceable emission limit for each
subject emission unit at the source and for each pollutant subject to
review that is emitted from the source.'' 70 FR 39172. Our FIP proposal
states that ``States, or EPA if implementing a FIP, must address all
visibility-impairing pollutants emitted by a source in the BART
determination process. The most significant visibility impairing
pollutants are SO2, NOX and PM.'' 77 FR 23993.
Similarly, the BART Guidelines identify SO2, NOX
and PM as visibility-impairing pollutants. 70 FR 39160. Since these
pollutants are subject to review, emission limits must be established.
This comment has not resulted in any changes to our proposal. We note
that Holcim has not provided any specific data to demonstrate that they
may exceed the emission limit established for SO2.
    Comment: Holcim disagreed with EPA's proposal to impose an emission
limit for PM at Trident of 0.77 lb/ton clinker. Holcim stated that the
proposed limit, which is based on Trident's current emissions, is
unjustified because it would result in no visibility impact and that as
the company had already explained, the selected BART must consider the
degree of improvement in visibility. Holcim stated that adding a
duplicative applicable requirement to Trident's Title V permit would
serve no purpose other than to ``create the potential for multiple
penalties if the requirement were violated.''
    Response: See the previous response.

F. Comments on CFAC

    Comments: CFAC requested that EPA conduct a BART analysis for their
facility now, rather than in the future, so that CFAC has more
information for planning a restart. The NPS commented similarly. CFAC
also commented that not knowing what the BART controls may or may not
be for their facility makes it difficult to know whether those controls
could be installed within the five-year timeframe. Another commenter
stated that we must either set BART limits for CFAC in the FIP, or we
must require plant shutdown as part of the FIP.
    Response: We disagree that it is necessary to conduct the BART
analysis at this time. The information necessary to complete such a
BART analysis is not available until CFAC's future operational plans
are known. The requirements for CFAC at 40 CFR 52.1396(n) are
sufficient at this time. With regard to CFAC's comment that not knowing
what the BART controls may or may not be for their facility makes it
difficult to know whether those controls could be installed within the
five-year timeframe, the BART Guidelines state that we must require
compliance with emission limits no later than five years following the
final FIP. 70 FR 39172. CFAC can provide the necessary information to
EPA to conduct a BART analysis at any time.

G. Comments on Colstrip Units 1 and 2

    Comment: A commenter stated that PPL's modeling files related to
the June 2008 Addendum to PPL Montana's Colstrip BART Report should be
placed in the docket.
    Response: We requested the modeling files from PPL and PPL
responded that they could not locate those files. We based our
decisions on the more recent modeling described at 77 FR 24002.
    Comment: Commenters stated that they object to our proposed BART
determinations for NOX and SO2 because it would
impose emission limits based on SNCR and an additional scrubber vessel,
respectively. Commenters stated that EPA's proposed BART analysis for
Colstrip Units 1 and 2 is inconsistent with our statutory obligations
and our own Guidelines. Commenters suggested that our BART
determinations contain significant errors. Commenters stated that we
did not properly or correctly consider the costs of the proposed
controls, the incremental cost-effectiveness of the controls, and the
lack of any reasonably expected visibility improvements resulting from
the proposed controls. Instead of the BART proposed by EPA, commenters
supported the installation of SOFA for NOX control with an
emission limit of 0.20 lb/MMbtu, and lime injection for SO2
control with an emission limit of 0.20 lb/MMBtu (both as a 30-day
rolling average).
    Response: In proposing our BART determinations, we met the
statutory requirements under section 169A of the CAA and also followed
the BART Guidelines. Based on our consideration of the five statutory
BART factors, we continue to find that BART for NOX is
SOFA+SNCR with an emission limit of 0.15 lb/MMBtu (30-day rolling
average). Similarly, based on our consideration of the five statutory
BART factors, we continue to find that BART for SO2 is lime
injection and an additional scrubber vessel with an emission limit of
0.08 lb/MMBtu (30-day rolling average). Each specific issue raised by
the commenters is addressed in a separate response to comments.
    Comment: Several commenters asserted that EPA's costs for SNCR on
Colstrip Units 1 and 2 were inaccurate and that SNCR is not cost
effective. Commenters asserted that this was due to a number of errors,
including use of an incorrect baseline, overstating the emission
benefits that can be achieved with SNCR, and using improper cost
estimation techniques. The commenters submitted their own cost
estimates challenging those reported by EPA.
    Response: EPA estimated a cost effectiveness for SNCR+SOFA of about
$1,550/ton. This estimate has been confirmed after the proposal through
information supplied by SNCR vendors.\16\ For this control combination,
Nalco Mobotec Inc. (Mobotec) estimated a cost effectiveness of roughly
$1,395/ton, while Fuel Tech Inc. (Fuel Tech) estimated a cost
effectiveness of $1,642/

ton. The average vendor cost effectiveness of $1,518/ton is slightly
lower than what was previously estimated by EPA. Likewise, EPA
estimated a cost effectiveness for SNCR (after SOFA) of about $3,300/
ton. For SNCR (after SOFA) Nalco Mobotec estimated a cost effectiveness
of roughly $2,800/ton, while Fuel Tech estimated a cost effectiveness
of $3,500/ton.\17\ The average vendor cost effectiveness of $3,150/ton
is slightly lower than what was previously estimated by EPA.
---------------------------------------------------------------------------

    \16\ Memo from Jim Staudt, Andover Technology Partners, to Doug
Grano, July 10, 2012.
    \17\ Id.
---------------------------------------------------------------------------

    Further, the cost effectiveness of SNCR is of course highly
dependent on the emission benefits that the control technology can
achieve. The discrepancy between our cost effectiveness and that
supplied by the commenters is largely driven by this factor. We address
this issue, as well as other issues raised by commenters in regard to
our SNCR cost estimates for Colstrip Units 1 and 2, separately below.
    Comment: Two commenters claimed that EPA used an incorrect baseline
of 2008-2010 for Colstrip pollutant emissions in our BART analyses. One
commenter stated that the BART Guidelines require a baseline for BART
analyses of 2000-2004, while another stated it requires a baseline of
2001-2003. Both of these baseline periods were prior to the
installation of additional combustion controls at Colstrip Units 1 and
2. In addition, one commenter claimed that the 2008-2010 baseline
emissions are not representative as they reflect a period of economic
downturn.
    Response: We disagree with these comments. The BART Guidelines
require you to choose a representative baseline period, but do not
specify that this period must be 2000-2004 or 2001-2003:

    The baseline emissions rate should represent a realistic
depiction of anticipated annual emissions for the source. In
general, for the existing sources subject to BART, you will estimate
the anticipated annual emissions based upon actual emissions from a
baseline period.

70 FR 39167.
    As we discussed in our proposed rule, in 2007 PPL installed
additional combustion controls on Colstrip Units 1 and 2 in order to
meet new Acid Rain Program emission limits. As these controls were not
installed to meet BART requirements, we find that it is appropriate to
reflect them in the baseline emissions.
    Furthermore, annual heat input data contained in the CAMD emissions
system shows the baseline period of 2008-2010 is representative of the
operation of the Colstrip Unit 1 and 2. For example, the 2000-2010
annual heat input for Colstrip Unit 1 ranged from a low of 24,003,758
MMBtu/yr in 2006 to a high of 30,770,151 MMBtu/yr in 2004. The 2008-
2010 annual average heat input used by EPA in our BART analysis of
26,578,089 MMBtu/yr falls about in the middle of this range. Therefore,
the baseline period chosen by EPA is a realistic depiction of the heat
input (and thereby annual emissions) of the Colstrip Units 1 and 2.
    Finally, the 2000-2004 annual average heat input (the period that
one commenter asserted we should have used), was 26,966,516 MMBtu/yr,
and only slightly higher than the heat input used by EPA of 26,578,089
MMBtu/yr. Therefore, even if we had used the 2000-2004 heat input, it
would not have affected the BART analysis in a meaningful way.
    Comment: Commenters asserted that EPA overstated the emissions
benefit of SNCR and that it cannot achieve the level of control
claimed. The commenters stated that SNCR cannot achieve a 25% emission
reduction. They also stated that SNCR (in combination with combustion
controls) cannot achieve an emission limit of 0.15 lb/MMBtu on a 30-day
rolling average.
    PPL based their assertions on analyses which they obtained from
SNCR vendors, Nalco Mobotec, Inc. and Fuel Tech Inc. They stated that
these analyses show that the lowest feasible emissions limit for these
units on a 30-day rolling average would be in the range of 0.17 to 0.18
lbs/MMBtu. PPL estimates that only a 10% reduction in NOX
emissions could be achieved since ammonia slip must be limited to 0.5
ppm.
    NPS questioned whether SNCR can achieve 0.15 lb/MMBtu on a 30-day
rolling average due to the sensitivity of SNCR to boiler operation,
size, and configuration. NPS did not provide any data or information to
support their concerns other than to state that a query of the CAMD
emissions system revealed only two EGUs that are consistently meeting
0.15 lb/MMBtu on monthly basis.
    Response: We disagree that we have overstated the emissions benefit
of SNCR. Neither the vendor analyses nor the SNCR performance data
contained in the CAMD emissions system support a conclusion that we
overstated the emission benefits of SNR.
    The vendor analyses provided by PPL confirm the assumptions made by
EPA regarding the emissions benefits that can be achieved with SNCR.
Both vendors indicate that a control efficiency of 25%, as assumed by
EPA, can be achieved. For example, Fuel Tech indicates that a ``10 ppm
ammonia slip would result in ~25% NOX reduction.'' \18\
Similarly, Mobotec indicates that ``[a]t 7 ppm of ammonia slip,
NOX emissions could be reduced up to 25%, provided there
would be no impact on the performance of the air preheater, or other
plant systems.'' \19\ We realize that the control efficiency of SNCR is
highly dependent on the level of ammonia slip. However, we find no
reason that an ammonia slip level of 5 to 10 ppm is unacceptable for
the Colstrip Unit 1 and 2. These levels of ammonia slip are typical for
SNCR. In fact, Fuel Tech stated that ``[i]n the coal-fired Utility
market segment, the SNCR systems have been historically designed for a
minimum of 5 ppm ammonia slip with some lower sulfur applications with
NH3 slip levels of 10 ppm.'' \20\ (We address the potential
impacts from ammonia slip in a separate response to comments).
---------------------------------------------------------------------------

    \18\ Letter from Dale T Pfaff, Fuel Tech, Inc. to Gordon
Criswell, PPL Montana, May 29, 2012.
    \19\ Letter from Gary Tonnemacher, Mobotec, to Gordon Criswell,
PPL Montana, May 25, 2012.
    \20\ Fuel Tech, May 29, 2012.
---------------------------------------------------------------------------

    Further, we note that the control efficiencies provided by the
vendors are for operation at full load, and that higher control
efficiencies can be achieved at lower loads. For instance, Mobotec
relates that ``[h]igher NOX reductions can be achieved at
mid to low load heat inputs, possibly up to 40%.'' \21\ Given that the
Colstrip Unit 1 and 2 frequently operate at below full load, it is
likely that on an annual basis SNCR can achieve better than the 25%
emission reduction assumed by EPA.
---------------------------------------------------------------------------

    \21\ Mobotec, May 25, 2012.
---------------------------------------------------------------------------

    PPL has erred in stating that the control efficiency of SNCR is no
more than 10% since ammonia slip levels must be limited to 0.5 ppm. The
commenter bases this claim on what they believe to be a precedent set
in the Centralia Power Plant BART determination. However, the Centralia
BART determination prepared by Washington stated that, ``TransAlta's
cost analysis uses a urea-based SNCR system providing a nominal 25%
reduction in NOX levels with a 5 ppm ammonia slip.'' \22\
And as established by the vendor analyses discussed above, much higher
emission reductions than 10% can be achieved with SNCR at ammonia slip
levels of 5 to 10 ppm.
---------------------------------------------------------------------------

    \22\ BART Determination Support Document for Transalta Centralia
Generation LLC Power Plant, Centralia, Washington, Prepared by
Washington State Department of Ecology, Revised November 2011, p.
14; Region 10 clarified the typographical error in their Federal
Register notice via email from Steve Body to Aaron Worstell dated
July 26, 2012.

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

    Similarly, the performance data contained in CAMD emissions system
only serves to reinforce the assumptions made by EPA regarding the
emission benefits of SNCR. Based on our review of the CAMD emissions
data, there are many EGUs equipped with SNCR (with combustion controls)
that are achieving an emission rate of 0.15 lb/MMBtu or lower on a
monthly basis. One unit in particular, Boswell Unit 4, is very
comparable to the Colstrip Unit 1 and 2. Boswell Unit 4, like the
Colstrip Unit 1 and 2, burns sub-bituminous coal and is tangentially
fired. In addition, Boswell Unit 4 had a baseline annual emission rate
(with LNB and CCOFA, but prior to the installation of SNCR and SOFA)
similar to the Colstrip Unit 1 and 2 of approximately 0.35 lb/MMBtu.
Since the installation of full combustion controls and SNCR, the
Boswell Unit has achieved a monthly emission rate of below 0.15 lb/
MMBtu. For example, between April 2011 and April 2012, the most recent
full year of emissions data available in the CAMD emissions system, the
monthly emission rates for Boswell Unit 4 were between 0.11 and 0.14
lb/MMbtu. This is a strong indicator of the performance rates that can
be expected for Colstrip Units 1 and 2.
    We acknowledge that a range of performance rates are currently
being achieved with SNCR, and are in some cases not as low as at
Boswell Unit 4. However, without a showing that there are circumstances
unique to the Colstrip Unit 1 and 2 that would prevent SNCR from
achieving the same reductions as at Boswell Unit 4, we find no reason
that an emission limit higher than 0.15 lb/MMBtu on a 30-day rolling
average is warranted. This is consistent with the BART Guidelines:

    Without a showing of differences between the source and other
sources that have achieved more stringent emissions limits, you
should conclude that the level being achieved by those other sources
is representative of the achievable level for the source being
analyzed.

70 FR 39166.
    Finally, due to the smaller size of Colstrip Unit 1 and 2 (333 MW
each), we expect that SNCR would be more effective than at Boswell Unit
4 (525 MW). This is because the effectiveness of SNCR on large boilers
is somewhat reduced as the relatively larger cross-section of the
boiler makes distribution of the reagent difficult.
    For the reasons stated here, we find no basis in claims that we
overestimated the emission benefits for SNCR.
    Comment: Commenters stated that EPA did not properly consider the
incremental cost-effectiveness of SNCR at Colstrip Units 1 and 2.
Commenters stated that EPA improperly assessed the costs of SNCR when
combined with SOFA, and not as an individual technology. Commenters
stated that the incremental cost of adding SNCR to SOFA outweighs the
benefits. One commenter cited portions of the BART Guidelines that
address consideration of incremental costs between competing
technologies.
    Response: We disagree with these comments. We addressed why these
control technologies were analyzed together in our proposed rule:

    The post-combustion control technologies, SNCR and SCR, have
been evaluated in combination with combustion controls. That is, the
inlet concentration to the post-combustion controls is assumed to be
0.20 lb/MMBtu. This allows the equipment and operating and
maintenance costs of the post-combustion controls to be minimized
based on the lower inlet NOX concentration.

77 FR 22043.
    If we had not combined the control technologies, then the cost
effectiveness would have been more favorable to SNCR. This is because
the inlet to the SNCR would reflect the current annual baseline
emissions (e.g., 0.308 lb/MMbtu for Colstrip Unit 1, 2008-2010), as
opposed to the anticipated post-combustion (i.e., with SOFA) rate of
0.20 lb/MMBtu assumed by EPA. This would lead to larger emission
reductions being achieved by SNCR, and thereby, more favorable cost
effectiveness.
    Regardless, EPA did disclose the costs of SNCR alone (after SOFA)
in our proposed rule. Consider for example our BART analysis for
Colstrip Unit 1. See 77 FR 24025-24027 and spreadsheet entitled ``EPA
SNCR Cost Colstrip Unit 1 Final'' located in the docket. The total
annual cost of SNCR given in our proposed rule was $2,188,569, while
the emission reductions were 664 tpy. This results in a cost
effectiveness of $3,291/ton, essentially the incremental cost
effectiveness between SNCR+SOFA and SOFA as given in Table 77 of the
proposed rule. EPA selected SNCR as BART in consideration of these
costs, all of which were presented to the public in our proposed rule.
    Comment: Various commenters stated that EPA disregarded, or did not
properly account for, issues associated with ammonia slip from SNCR
systems. The commenters expressed concerns about both potential
operational and environmental impacts. In regard to potential
operational impacts, commenters expressed concerns about fouling of the
air preheater. In regard to potential environmental impacts, commenters
expressed concerns related to a visible wet plume, greenhouse gases,
and toxic emissions.
    Response: We disagree with these comments. In our proposed rule, we
explicitly considered issues associated with ammonia slip from SNCR
systems. For example:

    As Colstrip Unit 1 burns sub-bituminous PRB coal having a low
sulfur content of 0.91 lb/MMBtu (equating to a SO2 rate
of 1.8 lb/MMBtu), [citation omitted] it was not necessary to make
allowances in the cost calculations to account for equipment
modifications or additional maintenance associated with fouling due
to the formation of ammonium bisulfate. These are only concerns when
the SO2 rate is above 3 lb/MMBtu.[citation omitted]
Moreover, ammonium bisulfate formation can be minimized by
preventing excessive NH3 slip. Optimization of the SNCR
system can commonly limit NH3 slip to levels less than
the 5 parts per million (ppm) upstream of the pre-air heater.

77 FR 24025.
    This observation has been verified by the vendor analyses submitted
by PPL. For example, Fuel Tech stated that ``[s]ince the Colstrip 1&2
coal has low sulfur, there is less concern of ammonium bisulfate
formation and its associated air preheater pluggage issues.'' \23\
---------------------------------------------------------------------------

    \23\ Fuel Tech, May 29, 2012.
---------------------------------------------------------------------------

    We also find that concerns about the potential for adverse
environmental impacts, such as a visible wet plume, toxic ammonia
emissions, or greenhouse gas emissions, are unfounded or exaggerated.
As previously discussed, optimization of the SNCR system would limit
ammonia slip to acceptable levels (i.e., 5-10 ppm). Moreover, as noted
in the BART determination for the Transalta Centralia Power Plant in
Washington, ammonia in the gas stream is further removed when a wet
scrubber is present.\24\ Since the Colstrip Units 1 and 2 utilize wet
scrubbers, no additional plume visibility or other local impacts would
be anticipated.
---------------------------------------------------------------------------

    \24\ BART Determination Support Document for Transalta Centralia
Generation LLC Power Plant, Centralia, Washington, Washington State
Department of Ecology, revised November 2011, p. 13.
---------------------------------------------------------------------------

    While we did not quantify increases in greenhouse gases associated
with SNCR in our proposed rule, we did quantify the additional amount
of coal that is needed to account for the loss in thermal efficiency
and found it to be insignificant. For example:

    SNCR reduces the thermal efficiency of a boiler as the reduction
reaction uses thermal energy from the boiler.[citation omitted]
Therefore, additional coal must be burned to make up for the
decreases in power generation. Using CCM calculations we

determined the additional coal needed for Unit 1 equates to 77,600
MMBtu/yr.

77 FR 24026.
    We note that 77,600 MMBtu/yr is only 0.3% of the 2008-2010 annual
average heat input for Colstrip Unit 1. The increase in CO2
emissions would be proportional (that is, 0.3%). The formation of other
greenhouse gases, such as nitrous oxide, would be highly dependent upon
the reagent used, the amount of reagent injected and the injection
temperature. Regardless, we note that the potential for CO2
increases also exists for SCR, the technology favored by some
commenters. This is due to the energy penalty associated with the large
pressure drop across the SCR reactor. Therefore, consideration of
greenhouse gases would not have necessarily favored SNCR over SCR.
    Comment: MDEQ stated that EPA failed to provide analysis or
consideration of the impact SNCR installation may have on mercury
controls at Colstrip 1 & 2. MDEQ stated that this failure ignores
factor 3 of the five-factor analysis, ``Any existing pollution control
technology in use at the source.'' MDEQ contended that the application
of SNCR will require these units to displace the sorbent injection
systems which limit mercury emissions, and that this displacement will
compromise the Montana Mercury Rule.
    Response: We disagree with this comment. SNCR should have no impact
on mercury capture in the scrubber or with mercury capture from sorbent
injection and will neither improve nor harm any efforts at Colstrip
Units 1 and 2 to comply with Montana's Mercury Rule. There is no reason
why Colstrip Units 1 and 2 cannot utilize both SNCR and sorbent
injection (if sorbent injection is what PPL chooses to use at Colstrip
1 and 2). Injection points for SNCR and for sorbent injection are at
different locations--the furnace for SNCR and the downstream ductwork
for sorbent injection. A review of EPA's National Electric Energy Data
System (NEEDS) reveals that are currently 17 utility boilers equipped
with both SNCR and activated carbon injection systems.\25\ The list of
facilities includes units ranging from 65 MW to 405 MW and burning both
bituminous and subbituminous coals. Therefore, there is no basis for
the assertion that these two pollution control systems cannot be used
together on the same facility.
---------------------------------------------------------------------------

    \25\ Memo from Jim Staudt, Andover Technology Partners, to Doug
Grano, July 13, 2012, p. 9.
---------------------------------------------------------------------------

    Comment: MDEQ stated that EPA lacks consideration of Montana's
existing SIP requirements. For instance, sources required to add
controls would have to provide ``de minimis'' notifications under ARM
17.8.745, or potentially a resource-intensive demonstration that the
additional control would not contribute to a violation of an air
quality standard. Additionally, MDEQ stated that some of the proposed
controls might require either a minor source permit or a major
modification under the NSR program. MDEQ expressed particular concern
over EPA's lack of analysis of PPL's estimated increase in ammonia
slip.\26\ MDEQ suggested that increases in ammonia slip could lead to
increases in PM2.5 emissions at Colstrip 1 & 2, potentially
requiring the unit(s) to submit a ``politically controversial, legally
complex, and technically challenging'' NSR major modification permit.
MDEQ also stated that an NSR major modification would significantly
alter the time and cost required to implement the proposed BART.
---------------------------------------------------------------------------

    \26\ September 23, 2011 PPL submittal titled ``NOX
Control Update to PPL Montana's Colstrip Generating Station BART
Report.''
---------------------------------------------------------------------------

    Response: We disagree with these comments. MDEQ has not provided
any data or information to substantiate that our BART determinations
would interfere with existing SIP requirements, including those for
permitting. They have only speculated that these might be concerns. In
addition, these concerns would not negate our obligation to prescribe
BART controls. We have addressed concerns related to ammonia slip in a
separate response to comments.
    Comment: Commenters stated that EPA asserted, with no analysis,
that the energy needs associated with installation SNCR or SCR on the
Colstrip Unit 1 and 2 are minimal and neither the additional energy
requirements nor the nonair quality environmental impacts associated
with disposal of the ash waste or transportation of the chemical
reagents or catalysts warranted eliminating either SCR or SNCR.
    Response: We disagree with this comment. We provided analysis of
the energy impacts associated with SNCR and SCR in our proposed rule.
For example, for the application of SNCR to Colstrip Unit 1 we
``determined the additional coal needed for Unit 1 equates to 77,600
MMBtu/yr.'' 77 FR 24026. Similarly, we determined that SCR requires
``additional electric power to meet fan requirements equivalent to
approximately 0.3% of the plant's electric output.'' [citation omitted]
77 FR 24026. We also provided analysis of the non- air-quality impacts
associated with SNCR and SCR in our proposed rule. See for example 77
FR 24026. We did not find it necessary to quantify these impacts as
they are negligible. Also, the nonair quality impacts would be no
different than those at numerous other boilers where SNCR or SCR have
been successfully applied. Regardless, the commenters did not present
any data or information that establishes that the energy or nonair
quality impacts of SNCR or SCR would make these control options
unacceptable.
    Comment: NPS stated that allowing five years from promulgation of
the rule to install SNCR on Colstrip Units 1 and 2 is excessive since
it can be installed in less than one year.
    Response: We agree that SNCR in some cases can be installed in less
than one year. However, the BART Guidelines require compliance with the
BART emission limit as expeditiously as possible but in no event later
than five years after promulgation of the FIP. 40 CFR 51.308(e)(1)(iv).
Our FIP is consistent with that requirement.
    Comment: The NPS agreed with EPA that an annual emission rate of
0.05 lb/MMBtu is achievable with SCR.
    Response: Comment noted.
    Comment: EarthJustice stated that EPA incorrectly rejected SCR as
BART for NOX pollutant control for Colstrip Units 1 and 2.
They asserted that EPA's analysis was biased against the selection of
SCR as BART. They also asserted that we manipulated data, made
assumptions, and performed calculations where the results are specified
but the calculation itself is absent from the public record.
    Response: We disagree with these comments. Our selection of
SNCR+SOFA, and not SCR+SOFA, as BART was based on our objective
consideration of the five statutory factors. Moreover, all of our
analyses and assumptions were supported by the docket which was
available for public review.
    Comment: EarthJustice stated EPA underestimated the NOX
reductions that can be achieved with SCR technology. They stated that
major SCR catalyst vendors routinely guarantee at least 90% removal
efficiency for SCR systems.
    Response: We disagree. EarthJustice has incorrectly assumed that a
90% control efficiency can be achieved in all applications regardless
of the input NOX emission rate or other parameters. The
baseline annual emission rate for Colstrip BART units is around 0.31
lb/MMBtu (annually). After the installation of SOFA, the emission rate
is expected to be 0.20 lb/MMBtu (annually). Therefore, a 90% control
efficiency for SCR would correspond to a controlled emission rate of
0.02 lb/MMBtu

(annually). We find that this is an unrealistic expectation of the
level of control that can be achieved with SCR.
    Comment: EarthJustice stated that EPA incorrectly used the
Integrated Planning Model (IPM) for the direct capital costs of SCR for
Colstrip Units 1 and 2 and that we failed to explain why we did so.
They stated that the BART Guidelines require that the CCM be used for
BART cost analyses, except for the site-specific cost of the equipment
itself which will vary depending on site-specific conditions.
EarthJustice also stated that our use of IPM led to the double counting
of installation costs.
    Response: We disagree with these comments. We explained our
rationale for using IPM for direct costs for SCR in the proposed rule:

    We relied on a number of resources to assess the cost of
compliance for the control technologies under consideration. In
accordance with the BART Guidelines (70 FR 39166 (July 6, 2005)),
and in order to maintain and improve consistency, in all cases we
sought to align our cost methodologies with the EPA's Control Cost
Manual (CCM).[citation omitted] However, to ensure that our methods
also reflect the most recent cost levels seen in the marketplace, we
also relied on control costs developed for the Integrated Planning
Model (IPM) version 4.10.[citation omitted] These IPM control costs
are based on databases of actual control project costs and account
for project specifics such as coal type, boiler type, and reduction
efficiency. The IPM control costs reflect the recent increase in
costs in the five years proceeding 2009 that is largely attributed
to international competition. Finally, our costs were also informed
by cost analyses submitted by the sources, including in some cases
vendor data.

77 FR 24024.

    As noted in the proposed rule, our use of IPM was intended to
ensure that the direct capital costs reflect the most recent cost
levels seen in the marketplace. Therefore, we disagree that this led to
an overestimation of the costs of SCR. Also as noted in the proposal,
while we did use IPM for direct capital costs, the remainder of our
analysis for SCR conformed to the CCM.
    EarthJustice is mistaken in asserting that our use of IPM led to
the double counting of installation costs. EarthJustice is also
mistaken in asserting that ``in the Cost Control Manual, those
installation costs [direct installation costs] are included as indirect
capital costs.'' Direct installation costs are treated in the same way
whether using the CCM or IPM. That is, both provide direct capital
costs that are inclusive of the direct installation costs. For example,
the CCM states:

    Direct capital costs (DCC) include purchased equipment costs
(PEC) such as SCR system equipment, instrumentation, sales tax and
freight. This includes costs associated with field measurements,
numerical modeling and system design. It also includes direct
installation costs such as auxiliary equipment (e.g., ductwork,
fans, compressor), foundations and supports, handling and erection,
electrical, piping, insulation, painting, and asbestos removal.\27\
(emphasis added)
---------------------------------------------------------------------------

    \27\ CCM, Section 4, Chapter 2, p. 2-41.

    Similarly, the IPM documentation states the bare module costs
include equipment, installation, buildings, foundations, electrical,
and the retrofit factor.\28\ Since we used the bare module capital
costs to replace the direct capital costs in the CCM calculations, we
did not double count direct installation costs. For example, for
Colstrip Unit 1 we used the bare module capital cost of $55,578,137
(2010 dollars) as input for the direct capital cost.
---------------------------------------------------------------------------

    \28\ IPM, Chapter 5, Appendix 5-2A, p. 2.
---------------------------------------------------------------------------

    Comment: EarthJustice stated that EPA overestimated capital costs
of SCR on Colstrip Units 1 and 2 by using an inflated capital recovery
factor (CRF) that is not based on accurate, available, site-specific
information and by underestimating the lifetime of SCR. EarthJustice
asserted that EPA should have used a CRF based on a 5% interest rate
and an equipment life of 30 years
    Response: We disagree that the CRF used by EPA led to an
overestimation of capital costs for SCR. In our cost analysis for
Colstrip Units 1 and 2, we used an interest (discount) rate of 7% for
all control options. This is consistent with guidance contained in the
Office of Management and Budget, Circular A-4, for regulatory
analysis.\29\ In regard to the equipment life assumed by EPA for SCR,
the BART Guidelines state:
---------------------------------------------------------------------------

    \29\ Office of Management and Budget, Circular A-4, Regulatory
Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.

    For example, the methods for calculating annualized costs in
EPA's OAQPS Control Cost Manual require the use of a specified time
period for amortization that varies based upon the type of control.
If the remaining useful life will clearly exceed this time period,
the remaining useful life has essentially no effect on control costs
and on the BART determination process. Where the remaining useful
life is less than the time period for amortizing costs, you should
---------------------------------------------------------------------------
use this shorter time period in your cost calculations.

70 FR 39169 (emphasis added).

    And in regard to SCR, the CCM states:
    Capital recovery cost is based on the anticipated equipment
lifetime and the annual interest rate employed. An economic lifetime
of 20 years is assumed for the SCR system. The remaining life of the
boiler may also be a determining factor for the system lifetime.\30\
(emphasis added)
---------------------------------------------------------------------------

    \30\ CCM, Section 4, Chapter 2, p. 2-48.
---------------------------------------------------------------------------

    The equipment life assumed by EPA is consistent with that specified
by the CCM for SCR (that is, 20 years). In addition, the consistent use
of a 7% interest rate and 20 year equipment life ensures that the costs
are comparable between all of the control options considered (provided
that each option has an equipment life of at least 20 years). It also
ensures that the costs are comparable to other BART analyses where
similar assumptions have been made. However, we acknowledge that there
may be circumstances where it is reasonable to assume a shorter or
longer equipment life. In particular, it may be appropriate to consider
a shorter equipment life where the owner plans to shut a unit down in
less than 20 years.
    Further, assuming a 30 year economic life would not change our
conclusions regarding BART for Colstrip Units 1 and 2. For example, for
Colstrip Unit 1 we have recalculated the cost-effectiveness amortizing
over 30 years. The resulting cost effectiveness for SCR+SOFA is $2,879/
ton, as compared to the cost effectiveness of $3,195/ton amortizing
over 20 years which we cited in our proposed rule. We find that the
cost of SOFA+SCR is reasonable regardless of the assumed equipment
life. However, we find that the limited visibility benefits would
continue to preclude our selection of SCR+SOFA as BART.
    Comment: EarthJustice claimed that EPA skewed the cost
effectiveness results away from SCR for Colstrip Units 1 and 2 by
overestimating the operations and maintenance costs associated with SCR
by approximately $600,000. In particular, EarthJustice questioned our
costs for maintenance, catalyst replacement, and reagent use.
    Response: We disagree. While EarthJustice has suggested alternate
assumptions that could be made when estimating each of the operation
and maintenance costs (that is, direct annual costs) noted, they have
not substantiated that their assumptions are superior to those used by
EPA. Moreover, they have not substantiated that EPA erred in making any
of the cost assumptions related to operations and maintenance. They
have only pointed out instances in which they would make different
assumptions. Therefore, we see no reason that our cost assumptions for
O&M should be supplanted by those that EarthJustice would otherwise
choose in order to arrive at lower cost effectiveness.
    Regardless, if we were to incorporate each of the changes to the
O&M costs

suggested by EarthJustice, it would not change our BART determination.
For example, for Colstrip Unit 1, reducing the O&M costs of SCR by
$600,000 would only moderately lower the cost effectiveness of SNR+SOFA
from $3,195/ton to $3,019/ton. Though we find that both of these costs
are reasonable, we continue to find that there is insufficient
visibility benefit (0.404 deciview for Unit 1 and 0.423 deciview for
Unit 2 at the most improved Class I area) to support the selection of
SCR as BART.
    Comment: EarthJustice stated that EPA made multiple errors in our
SCR cost analysis for Colstrip Units 1 and 2. EarthJustice claims that
EPA made errors in relation to the baseline NOX emissions,
the control efficiency of SCR, the cost estimation method for direct
capital costs (CCM vs. IPM), specific operation and maintenance costs,
and the calculation of indirect annual costs (by way of the CRF).
EarthJustice provided their own cost estimates for SCR, addressing the
errors which they claimed EPA made. EarthJustice's cost effectiveness
is 55-65% lower than the values calculated by EPA, making SCR+SOFA
significantly more cost effective.
    Response: We disagree that we made multiple errors in our SCR cost
analysis for SCR for Colstrip Units 1 and 2 which led to inaccurate
cost effectiveness. Each of the errors which EarthJustice claims EPA
made has been addressed in separate responses. Therefore, we find that
the cost effectiveness for SCR in the proposed rule was accurate and a
correct basis for rejecting SCR as BART (in consideration of the
remaining statutory BART factors).
    Comment: The NPS commented that EPA has placed undue weight on the
incremental cost effectiveness of SOFA+SCR at Colstrip Units 1 and 2.
    Response: We disagree. In our proposed rule, we estimated the
incremental cost effectiveness of SCR+SOFA (over SNCR+SOFA) to $5,770/
ton and $5,887/ton, respectively. These costs far exceed the
corresponding average cost effectiveness of $3,195/ton and $3,235/ton.
Given these costs, we continue to find that SCR+SOFA is not justified
by the visibility improvement that would be provided.
    Comment: Some commenters stated that EPA properly concluded that
SCR does not constitute BART for Colstrip Units 1 and 2, but that EPA
incorrectly analyzed the capital costs and cost-effectiveness of SCR.
Commenters stated that EPA failed to consider SCR costs estimates which
PPL submitted in February 2012.\31\ Commenters also stated that EPA's
reliance on outdated information is not consistent with its own
guidance to use engineering estimates and that EPA should modify its
rationale in the final rule to conclude that, when the actual costs of
the technology are taken into consideration, SCR is not a cost-
effective technology. In particular, commenters noted that EPA
estimates the capital cost of the SCR at $78 million and rejects PPL's
cost estimate of $190 million
---------------------------------------------------------------------------

    \31\ Letter from David Bowen, Burns & McDonnell, to James
Parker, PPL Montana, February 7, 2012.
---------------------------------------------------------------------------

    Response: We disagree that we incorrectly analyzed the capital
costs and cost-effectiveness of SCR. We did not accept the SCR cost
estimates submitted by PPL in February 2012 that were based on cost
estimates provided to PPL by a consultant. EPA rejected these cost
estimates for a number of reasons.
    First, the cost estimates provided to PPL by the consultant do not
represent site-specific costs. The BART Guidelines state that ``[t]he
basis for equipment cost estimates also should be documented, either
with data supplied by an equipment vendor (i.e., budget estimates or
bids) or by a referenced source (such as the OAQPS CCM Fifth Edition,
February 1996, EPA 453/B-96-001).'' 70 FR 39166. Since the costs
submitted by PPL were simply adapted from another (undisclosed) utility
boiler, and are not specific to Colstrip Units 1 and 2, they should not
be considered a budgetary bid as described in the BART Guidelines. In
fact, PPL's consultant represents the costs as a ``feasibility capital
cost estimate'' and not as a budgetary bid.\32\
---------------------------------------------------------------------------

    \32\ Bowen letter.
---------------------------------------------------------------------------

    Second, the capital costs for SCR claimed in PPL's February 2012
submittal are far in excess of the range of capital costs documented by
various studies for actual installations. Five industry studies
conducted between 2002 and 2007 have reported the installed unit
capital cost of SCRs, or the costs actually incurred by owners, to
range from $79/kW to $316/kW (2010 dollars).\33\ These studies show
actual capital costs are much lower than estimated by PPL for Colstrip
Units 1 and 2 ($571/kW for each unit; 2011 dollars). Moreover, the
capital costs surveyed by the studies represent a range of retrofit
difficulties, including very difficult retrofits having significantly
impeded construction access, extensive relocations, and difficult
ductwork transitions. Therefore, to the extent that similar retrofit
difficulties may exist for Colstrip Units 1 and 2, the high end of the
range documented in the reports is representative.
---------------------------------------------------------------------------

    \33\ Dr. Phyllis Fox, Revised BART Cost-Effectiveness Analysis
for Tail End Selective Catalytic Reduction at Basin Electric Power
Cooperative Leland Olds Station Unit 2. Report Prepared for U.S.
EPA, RTI Project Number 0209897.004.095, March 2011.
---------------------------------------------------------------------------

    Third, we are concerned about the disparity among the various cost
estimates submitted by PPL. Between August 2007 and February 2012, PPL
submitted four separate SCR cost estimates for the Colstrip Unit 1 and
2. In the first SCR cost estimate, submitted in August 2007, PPL
estimated capital costs of $25,282,233 ($76/kW), total annual costs of
$7,289,482 and a cost effectiveness of $2,272/ton (each unit; 2007
dollars).\34\ In the second SCR cost estimate, submitted in June 2008,
PPL estimated capital costs of $29,581,465 ($88/kW), total annual costs
of $7,987,179 and a cost effectiveness of $1,735/ton (each unit; 2008
dollars).\35\ PPL's first and second cost estimates were generally
performed in conformance with EPA's CCM. The lower cost effectiveness
in the second submittal was driven primarily by a change in the assumed
maximum control level (from 0.15 lb/MMBtu to 0.06 lb/MMbtu), and
thereby greater annual emission reductions. In the third SCR cost
estimate, submitted in September 2011, PPL estimated capital costs of
$152,508,328 ($457/kW), total annual costs of $16,733,719 and a cost
effectiveness of $7.405/ton (each unit; 2011 dollars).\36\ The third
cost estimates were largely based on control costs developed for the
Integrated Planning Model.\37\ PPL assumed a retrofit factor of 2 when
using the IPM approach. We note that this retrofit factor, equating to
100% over the IPM base model capital costs, was unsupported and far in
excess of the range described in the IPM documentation: ``Retrofit
difficulties associated with an SCR may result in capital cost
increases of 30 to 50% over the base model.'' \38\ In the fourth SCR
cost estimate, submitted in February 2012, PPL estimated capital costs
of $190,000,000 ($571/kW), total annual

costs $19,956,767, and a cost effectiveness of $8,884/ton (each unit;
2011 dollars).\39\ The fourth cost estimate was also largely based on
control costs taken from IPM, but was augmented by capital cost
estimates provided to PPL by a consultant. In all, the capital costs
varied by a factor of more than seven ($76/kW to 571/kW), and the cost
effectiveness varied by a factor of more than 5 ($1,735/ton and $8,884/
ton). The large disparity between PPL's February 2012 cost estimates
and those in their previous submittals led us to question their
accuracy.
---------------------------------------------------------------------------

    \34\ BART Assessment Colstrip Generating Station, prepared for
PPL Montana, LLC, by TRC (``Colstrip Initial Response''), August
2007, Table A4-8(c).
    \35\ Addendum to PPL Montana's Colstrip BART Report Prepared for
PPL Montana, LLC; Prepared by TRC, (``Colstrip Addendum''), June
2008, Table 5.3-3.
    \36\ NOX Control Update to PPL Montana's Colstrip
Generating Station BART Report Prepared for PPL Montana, LLC, by
TRC, September 2011, Table 2-3b.
    \37\ Documentation for EPA Base Case v.4.10 Using the Integrated
Planning Model, August 2010, EPA 430R10010.
    \38\ IPM, Chapter 5, Appendix 5-2A, p. 1.
    \39\ Letter from Mark M. Hultman, P.E., TRC, February 9, 2012.
---------------------------------------------------------------------------

    Finally, PPL's February 2012 cost estimates contained cost items
that are either speculative in nature or not well documented. For
example, they include capital costs for duct and boiler reinforcement
even though the potential for boiler implosion was not evaluated by
PPL's consultant.\40\
---------------------------------------------------------------------------

    \40\ Bowen letter, p. 2.
---------------------------------------------------------------------------

    For the reasons stated above, EPA finds that no changes to the BART
determinations or to the FIP are needed in response to this comment.
    Comment: Various commenters objected to EPA`s BART determinations
for Colstrip 1 and 2. EarthJustice urged EPA to require selective
SCR+SOFA as the best system of continuous emission control to meet a
0.05 lb/MMBtu NOX emission limit applicable on a 30-day
rolling average basis. NPS also recommended that we require SCR+SOFA.
PPL supported a BART emissions rate for NOX of 0.20 lb/MMBtu
on a 30-day rolling average basis, reflecting the installation of SOFA.
    Response: Based on our consideration of the five statutory BART
factors, we continue to find that BART for NOX at each of
the Colstrip Unit 1 and 2 is an emission limit of 0.15 lb/MMBtu (30-day
rolling average) achievable with SNCR+SOFA.
    Comment: PPL stated that EPA's proposed emission limit for PM of
0.10 lb/MMbtu on a 30-day rolling average for each of the Colstrip Unit
1 and 2 is flawed. PPL asserted that the current PM limit is 0.10 lbs/
MMBtu as an annual average, based on a compliance assurance monitoring
plan together with annual stack testing. In order to accommodate the
shorter averaging period, the PPL suggested that the 30-day rolling
average emission limit proposed in the FIP be increased to 0.12 lb/
MMBtu.
    Response: We disagree with some aspects of this comment, but agree
with others. PPL has erred in stating that the current PM limit is 0.10
lb/MMBtu as an annual average. The Final Title V Operating Permit
(OP0513-06) indicates that the emission limit is 0.10 lb/
MMbtu, but does not provide an averaging period. The Title V permit
requires that compliance with the emission limit be demonstrated by a
Method 5 or Method 5B stack test once per year. As these stack test
methods typically consist of three sampling runs of at least 120
minutes in duration, and are not long-term continuous measurements, it
is not possible to average the emissions over 30-days or a year. For
this reason, we corrected the proposed PM emission limits in a
correction notice. 77 FR 29270. We clarified that that emission limits
for NOX and SO2, but not PM, shall apply on a 30-
day rolling average.
    As we are not requiring that PM emission limits apply on a 30-day
rolling average, PPL's suggestion that the emission limit be increased
to 0.12 lb/MMBtu is no longer relevant. The PM emission limits will
remain unchanged from those in the proposed rule which are identical to
those in the Title V permit.
    Comment: EarthJustice stated that EPA's exemption of Colstrip Units
1 and 2 from BART for PM is improper and unsupported. EarthJustice
asserts that EPA has not complied with its statutory and regulatory
obligations to determine BART for PM emissions from Colstrip Units 1
and 2 in that EPA simply made a declaration and skipped the statutory
process. EarthJustice stated that the existing venturi scrubbers are
not best technology and have not been considered such for a long time
because particle scrubbers do not remove particulates sufficient to
comply with basic CAA requirements. In addition, EarthJustice stated
that EPA should have considered more effective technologies, such as
baghouses.
    Response: We disagree. As with existing SO2 controls, we
do not find that it is necessary to consider the replacement of
existing PM controls with new controls. This is particularly true for
PM as the existing controls for Colstrip Units 1 and 2 currently reduce
emissions by more than 98%. Moreover, the contribution to the baseline
visibility impact from PM is very small (e.g., for Colstrip Unit 1,
less than 4% of 0.922 deciview, or 0.037 deciview). The most visibility
improvement that could be expected, even if all PM were eliminated, is
0.037 deciview. The visibility improvement that could be expected with
upgrades to the existing PM controls is only a fraction of 0.037
deciview. Therefore, it was reasonable for us to conclude that the
existing controls represent BART.
    In addition, EarthJustice has conflated the most stringent controls
with BART. BART is not necessarily the most stringent controls, but the
best system of continuous emission reduction taking into consideration
the five statutory factors.
    Comment: NPS stated that they disagree with the PM emissions that
we used in modeling the visibility impacts for Colstrip Units 1 and 2.
They stated that the PM emissions data provided by PPL is more
representative because it included both condensable and filterable PM
emissions, while the PM data used by EPA did not measure condensable
PM.
    Response: The difference in the approach used to characterize PM
emissions for visibility modeling purposes is negligible. Moreover, as
the PM emissions were held constant for all of the control scenarios
that EPA modeled, they had no impact on our BART determinations for
NOX and SO2.
    Comment: EarthJustice stated that EPA made the same error in
calculating baseline emissions in its SO2 BART determination
for Colstrip Units 1 and 2 as it did in its NOX BART
determination. EarthJustice asserted that EPA should have used a
baseline of 2001-2003.
    Response: We disagree with this comment. As discussed in a separate
response to comments, we have established a baseline which provides a
realistic depiction of anticipated annual emissions for the source. For
example, the 2008-2010 baseline we used for Colstrip Unit 1 reflects
annual average emissions of 5,548 tons/yr. By comparison the annual
average emissions for 2000-2010, 5,504 tons/yr, were only slightly
lower.
    Comment: PPL stated that EPA's estimate of the performance that can
be achieved with lime addition on Colstrip Units 1 and 2 was wrong. The
commenter stated that EPA's assumed emission rate for SO2 of
0.15 lbs/MMBtu was overly optimistic, and that a rate of 0.20 lbs/MMBtu
on a 30-day rolling average basis is achievable.
    Response: We disagree with this comment. The emission rate which
EPA assumed for limestone lime addition (injection) on Colstrip Units 1
and 2 was 0.15 lb/MMBtu on an annual basis, not on a 30-day rolling
average basis. This was based on PPL's amended BART submittal of August
of June 2008.\41\ We did not specify a 30-day rolling average

emission limit for limestone injection since we did not select it as
BART.
---------------------------------------------------------------------------

    \41\ Colstrip Addendum, p. 4-1.
---------------------------------------------------------------------------

    Comment: PPL commented that installation of an additional scrubber
vessel is technically impracticable, if not infeasible, due to space
constraints and the potential for equipment scaling.
    Response: First, addition of a fourth scrubber vessel for each of
Colstrip units 1 and 2 does not appear to be impracticable due to space
constraints. PPL's argument that there is no space availability for an
additional scrubber vessel is not supported by its own consultant. In
addition, the site visit conducted by EPA \42\ verified and the site
plan provided by PPL shows ample space for locating additional
equipment. A satellite image of units 1 and 2 located in the
docket.\43\ In fact, PPL's consultant, Burns & McDonnell was able to
find space for a new vessel with associated ductwork: ``[t]here is
sufficient space behind the stacks for installation of the fourth
scrubber module, ID fan, ductwork and accessories.'' \44\ As URS
pointed out, this might require an additional booster fan, which is
included in the Burns & McDonnell estimate.\45\
---------------------------------------------------------------------------

    \42\ On September 27, 2011 Aaron Worstell and Vanessa Hinkle
conducted a site visit at Colstrip.
    \43\ Staudt memo, p. 4.
    \44\ Report on the Fourth Scrubber Module Cost Estimate for PPL,
Burns and McDonnell, p. 4-3.
    \45\ Letter from Jonas Klingspor, URS Corporation, to Gordon
Criswell, PPL Montana, June 15, 2012.
---------------------------------------------------------------------------

    Second, an additional scrubber vessel may not be necessary to avoid
scaling. It is possible to inject lime and mitigate the risk of scaling
through addition of a forced oxidation system or by use of chemical
additives that mitigate scaling. The current system uses natural
oxidation. Forced oxidation will enable higher lime injection rates
while avoiding scaling. Forced oxidation systems will require blowers
and piping, and agitators that could be retrofit on the existing
scrubber vessels at what is likely to be a much lower cost than the
cost of a new absorber vessel. An alternative to forced oxidation is
use of chemical additives that address scaling. These additives are
available from companies such as Nalco Chemical Company.
    We find that it is acceptable for PPL to reduce emissions by means
other than installing an additional scrubber vessel, provided that the
emission limit of 0.08 lb/MMBtu on a 30-day rolling average is met.
    Comment: PPL stated that EPA overstated the emissions benefit of an
additional scrubber vessel.
    Response: PPL argues that an additional vessel would not in fact
reduce emissions because velocity through the existing scrubber vessel
tray will be reduced. As noted in responses to other comments, an
additional scrubber vessel may not be necessary to achieve 95%
SO2 capture. Nevertheless, with regard to addition of
another scrubber vessel and the impact on SO2 reduction, PPL
relies on a June 15, 2012, letter from Jonas Klingspor of URS
Corporation that states the reduced gas velocity would reduce
SO2 reduction. The URS letter and PPL, however, overlook the
fact that the openings in the tray for the existing vessels could be
reduced to restore gas velocity to the original level.
    URS provided estimates of emission rates possible under different
conditions. The analyses performed by URS were limited either by
increased scaling (the lowest rate of 0.13 lb/MMBtu with three vessels)
or lower absorber gas velocity (0.16 lb/MMBtu with four vessels). Since
URS did not evaluate addition of a forced oxidation system or any other
means to address scaling, it is likely that a significantly lower
emission rate than 0.13 lb/MMBtu is possible while using three vessels.
And, addition of a fourth scrubber vessel, with tray openings in the
three original vessels adjusted to maintain gas velocity, in
combination with a forced oxidation system would certainly increase
SO2 capture performance even more.
    Regardless, if PPL uses the additional scrubber vessel as a spare
in a manner similar to that for Colstrip Units 3 and 4, then gas flow
will remain unchanged. In this mode of operation, the spare scrubber
vessel helps allow for maintenance that is needed due to the scaling
caused by the additional lime. Without the spare vessel, the unit must
be shut down to perform the maintenance. This is the mode of operation
proposed by PPL in their August 2007 submittal.
    Comment: Commenters stated that an additional scrubber vessel costs
far more than EPA proposed and is therefore not cost-effective.
Commenters stated that it was inappropriate for EPA to rely on outdated
costs for an additional scrubber vessel in our proposed rule. PPL
provided cost estimates obtained from Burns & McDonnell \46\ showing
higher costs than estimated by EPA.
---------------------------------------------------------------------------

    \46\ Burns and McDonnell, p. 1-1.
---------------------------------------------------------------------------

    Response: Foremost, we note that the costs that we cited for an
additional scrubber vessel in our proposed rule were costs provided by
PPL in their BART submittals of August 2007 and June 2008. PPL did not
explain why the cost estimates submitted by PPL during the comment
period are more than two and a half times their original cost
estimates.
    The cost estimated by Burns & McDonnell of adding a single module
to treat 25% of the flue gas is unreasonable, equating to around $213/
kW ($71 million divided by 333,000 kW),- or the equivalent of $853/kW
when adjusting for the fact that only one fourth of the flue gas is
being treated. To put this in perspective, this is more costly on a $/
kW basis than the typical cost of a complete limestone forced oxidation
wet FGD system (around $500/kW) that would provide over 95% removal for
100% of the flue gas.\47\ Also, according to the 2010 EIA Form 860
Enviroequip data, the original scrubber structure with three modules
for Colstrip Unit 1 cost $34 million in 1975 (slightly over $100/kW).
Using the Chemical Engineering Plant Cost Index (CEPCI) to escalate to
2011 dollars, the cost in today's dollars would be about $109 million
($34 million times 585.7/182.4, or about $327/kW). This would suggest
the cost of an additional vessel to be on the order of $27 million, or
about 38% of what Burns & McDonnell estimated and consistent with what
EPA has previously estimated. Moreover, the difference in cost between
EPA's estimate and what Burns & McDonnell has estimated is far too
large to be explained by the additional ductwork and fans associated
with the retrofit, which PPL asserts are necessary. Additionally, Table
4-1 of the documentation from Burns & McDonnell has several costs that
are questionable or high ($900,000 for Owner's Project Management and
$400,000 for Owner's Legal Counsel and $3.4 million in Escalation) and
others that are very high and therefore require better explanation
($8.1 million for furnish and erect packages plus the estimates for
Mechanical, Electrical and Civil and Structural Construction that total
over $12 million). Engineering costs as well as many other costs are
typically determined as a percentage of the other costs, therefore the
effect of overestimation of one cost is compounded because it
contributes to overestimation of other costs. Because the estimate by
Burns & McDonnell is so much higher than what is reasonably expected
and includes several unsubstantiated and questionable cost elements. In
any event, an additional scrubber vessel may not be necessary if a
forced oxidation system or other means to control scaling is used on
the existing three scrubber vessels. PPL may determine that other means
may be

better than adding an additional scrubber vessel in terms of cost or
other factors for achieving the BART emission rate.
---------------------------------------------------------------------------

    \47\ IPM, Chapter 5, Table 5-4 shows a range of illustrative $/
kW costs.
---------------------------------------------------------------------------

    Comment: Commenters stated that EPA did not properly consider the
incremental cost-effectiveness of additional scrubber vessels at
Colstrip Units 1 and 2. Commenters stated that while the average cost-
effectiveness of lime injection and an additional scrubber vessel is
$912/ton, the incremental cost-effectiveness of a scrubber vessel is
$2,379/ton, nearly three times higher.
    Commenters also stated that it was improper for EPA to evaluate
lime injection and an additional scrubber vessel together. Commenters
stated that the incremental cost of adding an additional scrubber
vessel to lime injection outweighs the benefits. In particular, they
noted that use of lime injection alone would cost $1,883,200, while the
addition of a scrubber vessel adds $2,217,000 to the total cost. By
contrast, they noted that the SO2 reductions achieved from
the addition of the scrubber vessel are 929 tpy, while the use of lime
injection alone results in emission reductions of 3,557 tpy.
    Response: We agree with this comment in part. We miscalculated the
incremental cost effectiveness of an additional scrubber vessel at
Colstrip Unit 1 (which we stated to be $1,975/ton), but not at Colstrip
Unit 2 ($2,410/ton). The correct incremental cost effectiveness for an
additional scrubber vessel at Colstrip Unit 1 is $2,380/ton, not
$1,975/ton as given in our proposed rule.
    However, we disagree that it was improper to evaluate lime
injection with an additional scrubber vessel together. We also disagree
that cost of the additional scrubber vessel outweighs the benefits. For
example, for Colstrip Unit 2, individually the total annual cost of an
additional scrubber vessel is $2,210,000, while the emission reduction
is 917 tons per year. This results in a cost effectiveness of $2,410,
essentially the same as the incremental cost effectiveness between the
two control options. The visibility improvement from lime injection
alone is 0.225 deciview (at Theodore Roosevelt NP), while the
improvement from lime injection with an additional scrubber vessel is
0.280 deciview (at Theodore Roosevelt NP). We continue to find that the
cost is reasonable given the visibility benefits and that lime
injection with an additional scrubber vessel represents BART.
    Comment: PPL commented that in proposing SNCR, EPA appears to rely
on its determination that relevant Class I areas are currently above
the Regional Haze Glide Path (RHGP). 77 FR 24,038. The RHGP is an
important factor for the reasonable progress goals, but it is not one
of the five statutory factors specified for EPA to consider in its BART
analysis. Furthermore, as discussed above, there is no incremental
benefit in visibility from installation of SNCR that would affect the
area improvement in visibility relative to the glide path.
    Response: We agree with some aspects of this comment and disagree
with others. We agree that the Regional Haze glidepath is not one of
the five statutory factors specified for EPA to consider in its BART
analysis. We based our decision solely on the five statutory factors.
    Comment: EarthJustice stated that EPA settled for minor adjustments
for SO2 pollutants from Colstrip Units 1 and 2 instead of
proper BART controls. In particular, EarthJustice stated that EPA
failed to examine a full suite of options for SO2 BART,
including replacement of the existing scrubbers with state-of-the-art
scrubbers that could remove 98% of the SO2 from Colstrip
Units 1 and 2.
    In addition, EarthJustice claimed that EPA failed to consider all
feasible upgrades to the existing venturi scrubbers, including the use
of magnesium enhanced lime. EarthJustice stated that significant
emission reductions could be achieved via these upgrades, even without
the installation of an additional scrubber vessel. EarthJustice held
that an emission limit of 0.06 lb/MMbtu can be achieved with these
upgrades.
    Response: We disagree that we should have considered replacement of
the existing controls. As noted in our proposed rule, for example:

    The Colstrip Unit 1 venturi scrubber currently achieves greater
than 50% removal of SO2. For units with preexisting post-
combustion SO2 controls achieving removal efficiencies of
at least 50%, the BART Guidelines state that upgrades to the system
designed to improve the system's overall removal efficiency should
be considered.

77 FR 24028.
    The BART Guidelines only recommend evaluating constructing a new
FGD system ``[f]or coal-fired EGUs with existing post-combustion
SO2 controls achieving less than 50 percent removal
efficiencies.'' 70 FR 39171. Therefore, it was appropriate for us to
not consider new state-of-the art scrubbers, or for that matter, any
replacement technology.
    As noted in a separate response, we agree that it may not be
necessary to add an additional scrubber vessel in order to achieve an
emission limit of 0.08 lb/MMBtu on a 30-day rolling average. We
acknowledge that it may be possible to achieve the emission limit with
modifications to the existing scrubbers, such as a forced oxidation
system or by use of chemical additives that mitigate scaling. However,
these alternative approaches would likely be at a lower cost than an
additional scrubber vessel. Given that equivalent emission reductions
would be achieved at lower costs, the cost effectiveness would be even
more reasonable. Accordingly, we are extending flexibility to PPL to
meet the emission limit using the lowest cost approach.
    Regardless of whether PPL chooses to meet the emission limit with
an additional scrubber vessel or modifications to the existing scrubber
vessels, we continue to find that an emission limit of 0.08 lb/MMBtu,
and not 0.06 lb/MMBtu as suggested by the commenter, is appropriate. As
noted in the proposed rule, this is based on the level of performance
being achieved by Colstrip Units 3 and 4 which already employ scrubbing
systems similar to that being contemplated for Colstrip Units 1 and 2.
    The use of MEL is addressed in a separate response to a similar
comment from EarthJustice in regard to Colstrip Units 3 and 4.

H. Comments on Corette

    Comment: EarthJustice indicated that EPA`s decision not to impose
BART on Corette violates the statutory requirements for BART and is not
supported by the facts. EarthJustice stated that EPA engaged in the
same kind of non-BART result oriented process for Corette as it did for
Colstrip. They asserted that EPA's approach is no more legitimate or
compliant with the haze requirements in the case of Corette. Based on
their own BART analyses, they determined that BART for Corette is
installation of a dry scrubber and baghouse for the control of
SO2 and PM emissions, and SCR+SOFA for NOX.
    Response: We disagree with this comment. Our selection of BART for
Corette was based on our objective consideration of the five statutory
factors. We continue to find no additional controls are necessary for
Corette. Below, we address specific issues raised by EarthJustice in
regard to our BART determination for Corette.
    Comment: EarthJustice stated that, as with Colstrip Units 1 and 2,
we used an improper baseline in our BART evaluation of 2008-2010.
EarthJustice asserted that using these years artificially depresses the
emissions baselines, which in turn makes visibility improvement appear
less than they

actually are and thereby makes BART alternatives look less cost-
effective than they actually are.
    Response: See response to similar comments made by EarthJustice in
regard to Colstrip Units 1 and 2. Here again, as required by the BART
Guidelines, we used a baseline that is reflective of actual operations.
We acknowledge that the 2008-2010 emissions for both SO2 and
NOX were in fact somewhat lower than the long-term trend.
For example, the 2000-2010 SO2 emissions were 3,129 tpy,
while the 2008-2010 emissions were 2,723 tpy. Similarly, the 2000-2010
NOX emissions were 1,748 tpy, while the 2008-2010 emissions
were 1,625 tpy. Nonetheless, the difference in the baseline emissions
would not have impacted the cost-effectiveness calculations in an
appreciable manner.
    Comment: EarthJustice stated that EPA understated the cost
effectiveness of SCR+SOFA.
    Response: See response to similar comment made by EarthJustice in
regard to Colstrip Units 1 and 2.
    Comment: EarthJustice stated that EPA's cost-effectiveness
calculations for SO2 controls for Corette contain a number
of incorrect assumptions. In particular, EarthJustice stated that much
lower emission reductions can be achieved with LSD (90% with low sulfur
coal) than assumed by EPA. Also, EarthJustice stated that EPA's
approach of using IPM for capital costs resulted in a double counting
of installation costs.
    Response: We disagree. See response to similar comment made by
EarthJustice in regard to Colstrip Units 1 and 2.
    As we have noted previously, EarthJustice has erred in assuming
that a given control efficiency can be achieved in all applications
regardless of the input emission rate or other parameters. The level of
performance assumed by EPA for LSD (0.065 lb/MMBtu annually) is
generally reflective of what can be achieved with this technology.
    Further, we used IPM based calculations for both capital costs and
O&M costs for SO2 controls at Corette. (This is unlike for
NOX controls, where we used IPM based capital costs to
reflect recent market trends). Therefore, we could not have double
counted the installation costs for SO2 controls (from IPM
and the CCM).
    Comment: EarthJustice stated that EPA wrongly exempted Corette from
BART for PM.
    Response: See response to a similar comment made by EarthJustice in
regard to PM BART for Colstrip Units 1 and 2.
    Comment: PPL stated that they support our conclusions with respect
to BART for Corette that further controls are not justified.
    Response: Comment noted. The final FIP does not require additional
controls for Corette.
    Comment: Commenters stated that they disagree with EPA's cost
analysis for NOX and SO2 control technologies at
Corette and that EPA incorrectly concluded that a number of the control
technologies are cost-effective. Commenters noted that PPL submitted a
five factor BART analysis for Corette in August 2007, and later
supplemented with the analysis with updated information in June 2008
and September 2011.\48\ Commenters stated that in view of the
information that PPL provided, EPA incorrectly concluded that SOFA,
SOFA+SNCR, and SOFA+SCR are ``all cost effective technologies'' (77 FR
24043) and that the proposed FIP also incorrectly concluded that dry
sorbent injection (DSI) for SO2 is cost-effective at $3,940/
ton. 77 FR 24047.
---------------------------------------------------------------------------

    \48\ NOX Control Update to PPL Montana's J.E. Corette
Generating Station BART Report, September 2011, Prepared for PPL
Montana, LLC by TRC, at ES-1 (``NOX Control Update'');
SO2 Control Update to PPL Montana's J.E. Corette
Generating Station BART Report, August 2011, Prepared for PPL
Montana, LLC by TRC, at ES-1 (``SO2 Control Update'')
---------------------------------------------------------------------------

    Commenters stated that as documented in PPL's 2011 submissions, the
company used the IPM control technology cost estimation techniques,
which are more robust than those used in previous BART reports
submitted by PPL.\49\ Commenters stated that with respect to
NOX, PPL determined the cost-effectiveness of SNCR to be
approximately $13,544/ton (as compared to EPA's $2,596 for SOFA+SNCR)
and the cost-effectiveness for SCR to be $8,457/ton of additional
NOX controlled (as compared to EPA's $4,491 for SOFA +
SCR).\50\ The company stated that for SO2 controls, the
updated analysis determined that the cost-effectiveness of DSI is
$10,920/ton (as compared to EPA's $3,940/ton).\51\ Commenters stated
that the proposed FIP failed to consider that the installation of DSI
would most likely require upgrades to the existing particulate controls
to achieve the SO2 reductions that EPA evaluated and that
EPA relied on the outdated and inaccurate CCM to develop these
estimates.
---------------------------------------------------------------------------

    \49\ See NOX Control Update to PPL Montana's J.E.
Corette Generating Station BART Report, September 2011, Prepared for
PPL Montana, LLC by TRC, at ES-1 (``NOX Control
Update''); SO2 Control Update to PPL Montana's J.E.
Corette Generating Station BART Report, August 2011, Prepared for
PPL Montana, LLC by TRC, at ES-1 (``SO2 Control
Update'').
    \50\ NOX Control Update, at ES-3.
    \51\ SO2 Control Update, at 14.
---------------------------------------------------------------------------

    Response: We disagree. See our response to similar comments made by
PPL in regard to cost analyses for Colstrip Units 1 and 2. PPL's cost
estimates for Corette included many of the same incorrect methods and
assumptions that the company used when developing cost estimates for
Colstrip Units 1 and 2. In particular, PPL used unsupported retrofit
factors that were well in excess of the range described in the IPM
documentation.
    Also, we disagree that installation of DSI would most likely
require upgrades to the existing particulate controls to achieve the
SO2 reductions that EPA evaluated. In fact, DSI using trona
would ``typically either improve performance or have little impact,
even at high injection rates.'' \52\ It would not require the
replacement of the existing ESP with a new baghouse as reflected in
PPL's cost effectiveness estimate of $10,920/ton.\53\ Therefore, we
find that EPA's cost estimate of $3,490 is accurate.
---------------------------------------------------------------------------

    \52\ United Conveyer Corporation Dry Sorbent Injection FAQ
(http://unitedconveyor.com/dsi_systems/).
    \53\ Ref 2: SO2 Control Update to PPL Montana's J.E.
Corette Generating Station BART Report, Prepared for PPL Montana,
LLC, by TRC, August 2011, p. ES-2.
---------------------------------------------------------------------------

    Comment: Commenters stated that our proposed SO2 and
NOX emission limits for Corette were flawed. One commenter
stated that EPA must increase the limits to no less than 0.81 lb/MMBtu
for SO2 and 0.46 lb/MMBtu for NOX in order to
account for compliance over a 30-day rolling average. By contrast,
another commenter stated that our proposed emission limits were too
high and would actually result in increased emissions.
    Response: Based on these comments, we have reassessed our
SO2 and NOX emission limits for Corette. As we
have not prescribed any additional controls for Corette, the emission
limits should reflect emission rates currently being achieved with
existing controls. In order to establish appropriate emission limits,
we have conducted a statistical analysis of the monthly emissions data
contained in the CAMD emissions system. For the period 2000-2010, the
99th percentile monthly SO2 emission rate was 0.548 lb/
MMbtu. Similarly, the 99th percentile monthly NOX emission
rate was 0.335 lb/MMBtu. In our final action, we are establishing
emission limits slightly above these 99th percentile emission rates in
order to allow a sufficient margin for compliance. This is because the
emission limits must apply at all times,

including during startup, shutdown, and malfunction. The revised
emission rates are 0.57 lb/MMBtu for SO2 and 0.35 lb/MMBtu
for NOX, both on a 30-day rolling average. We have revised
the emission limits for Corette contained in section 52.1396(c)(1)
accordingly. Our complete analysis of SO2 and NOX
emission limits for Corette can be found in the docket.0.5480.3350.57
We have addressed the emission limit for PM at Corette in a separate
response to comments.
    Comment: PPL stated that EPA's PM emission limit for Corette was
flawed. PPL noted that over the past five years, stack test results
have shown that PM emissions have ranged from 0.059 lb/MMBtu to 0.252
lb/MMBtu. PPL stated that an emission limit of 0.30 lb/MMBtu would be
necessary to account for a 30-day rolling average.
    Response: We agree, in part. In our proposed rule, we incorrectly
specified a PM emission limit of 0.10 lb/MMBtu on a 30-day rolling
average. In consideration of the stack test data provided by PPL, we
have determined that that a limit of 0.26 lb/MMBtu is more appropriate.
In addition, and as discussed in response to a similar comment made by
PPL in regard to Colstrip, we find that it is not feasible to require
compliance with this emission limit on a 30-day rolling average. Again,
this is because compliance is shown using stack methods such as Method
5 and 5B. These stack test methods typically consist of three sampling
runs of at least 120 minutes in duration, and are not long-term
continuous measurements. As such, it is not possible to average the
emissions over 30 days or a year.
    Accordingly, we are revising our FIP to reflect a PM emission limit
for Corette of 0.26 lb/MMBtu. We are also removing the 30-day averaging
period requirement for the PM emission limit at Corette. More
specifically, we are revising section 52.1396(c)(1) to clarify that
emission limits for NOX and SO2, but not PM,
shall apply on a 30-day rolling average. Note that we are retaining the
requirement that compliance with the PM emission limit shall be
monitored in accordance with the CAM plan.
    As we are not requiring that the PM emission limit applies on a 30-
day rolling average, PPL's suggestion that the emission limit be
increased to 0.30 lb/MMBtu is no longer relevant.
    Comment: The USFWS commented that there are at least two other
similarly-sized installations implementing lime spray drying (LSD) for
SO2 control that justify the positions taken by EPA in the
proposed BART determination. USFWS stated that in justifying emission
limits of small units burning clean coal, Newmont Nevada is a 200 MW
plant that attains a 30-day rolling average 0.065 lb/MMBtu
SO2 emission limit with an SO2 control efficiency
of 93.1% and that capital cost of LSD units is corroborated by Great
River Energy's 188 MW Stanton 1 plant costing $79,514,000.
    Response: We acknowledge that the USFWS has provided information
from two other similarly-sized installations which are implementing LSD
for SO2 corroborating our LSD cost estimates for Corette.
However, as noted in our proposed rule, the cost of controls is not
justified by the visibility improvement (0.253 deciview).
    Comment: The USFWS stated that the capital costs proposed by EPA
for dry sorbent injection (DSI) and LSD should be considered as
maximums, because the costs should only decrease due to significant
curtailment of construction of air pollution control devices during the
economic downturn and cancellation or postponement of many coal burning
electrical generation units. The USFWS stated that quantified estimates
of the decreases could provide for firm reductions in the capital cost
estimates, but it is agreed that they would be difficult to affirm with
confidence at this time.
    Response: We agree that any changes in cost associated with
economic downturn would be difficult to affirm with confidence at this
time.
    Comment: The USFWS stated that the paragraph following Table 123
states that EPA considers $4,659 per ton of SO2 emissions
reduction using DSI as reasonable, but that $5,442 per ton for LSD is
not cost effective. The USFWS stated that other proposed SO2
BART determinations resulting in cost efficiency in the range of
Corette include PacifiCorp's Dave Johnston, WY-$4,743; Northshore
Mining's Silver Bay Power, MN-$7,309 and Xcel Energy's Taconite Harbor,
MN-$5,300 and as stated above, the capital cost of an LSD unit on Great
River Energy's 188 MW Stanton 1 plant is $79,514,000. USFWS
stated that such a total capital cost incorporated as the cost of LSD
at Corette would result in a cost per ton of SO2 removed of
$4,891 and that the LSD alternative might then also be considered by
EPA as being cost effective along with DSI.
    Response: We disagree. We continue to find that the cost of LSD for
Corette is not justified by the visibility improvement. Moreover, the
capital cost that we estimated for LSD is specific to Corette, and we
see no reason to supplant that cost with costs from Taconite Harbor or
other individual facilities.
    Comment: The USFWS stated that regarding the cost-effectiveness of
visibility improvement for SO2 controls, the second
paragraph after Table 123 in the draft proposed BART determination
states, `` * * * the cost of controls is not justified by the
visibility improvement'' and that this proposed conclusion warrants
further scrutiny. The USFWS stated that implementation of the DSI
alternative results in a 0.176 deciview improvement at Washakie WA, the
highest impacted Class I area, at a cost of $3.4 million per deciview
of improvement and that this is a very reasonable cost for visibility
improvement. The UFWS stated that the cost of visibility improvement
for SO2 controls proposed in other BART determinations for a
single most-impacted Class I area include: Colorado Springs Utilities,
Martin Drake, CO-$49.9 million/deciview; PacifiCorp, Wyodak, WY-$44.7
million/deciview; PacifiCorp, Jim Bridger, WY-$37.1 million/deciview;
PG&E, Boardman, OR-$35.2 million/deciview; and Dominion, Brayton Point,
MA-$33.9 million/deciview; Northshore Mining, Silver Bay Power, MN-
$26.2 million/deciview; Dominion, Salem Harbor, MA-$25.1 million/
deciview; Great River Energy, Stanton 1, ND-$21.9 million/
deciview; PacifiCorp, Naughton, WY-$18.2 million/deciview; PacifiCorp,
Dave Johnson, WY-$16.7 million/deciview. The USFWS stated that the
conclusion from the above is that since the cost per ton of
SO2 removal and the cost per deciview of visibility
improvement are both reasonable, DSI should be considered as a feasible
and cost-effective SO2 control alternative and be accepted
as BART for the PPL Montana, J.E. Corette Generating Station.
    Response: We disagree. The total annual cost of DSI for Corette, as
cited in our proposed rule was $5,363,896, while the greatest
visibility improvement was 0.176 deciview (Washakie WA). This results
in cost of $30 million per deciview, not $3.4 million per deciview. We
continue to find that the cost of LSD for Corette is not justified by
the visibility improvement.
    Comment: The USFWS commented that Table 110 states the visibility
improvement associated with each of the three NOX control
alternatives and by dividing respective Total Annual Costs by their
visibility improvements, they result in cost per deciview of visibility
improvement from $16.7 million to $17.8 million at the Washakie WA, the
highest impacted Class I area.

The USFWS stated that when these values are compared to other single
Class I area impacts for some other NOX BART proposals as
summarized below, it would indicate that they each could be considered
as reasonable. The USFWS stated that when total annual cost for each of
the three NOX control alternatives is divided by the
respective visibility improvement for all affected Class I areas (as
discussed above for SO2) they result in cost per deciview of
visibility improvement from $4.7 million to $5.0 million, which is a
very reasonable visibility cost. USFWS stated that since the cost per
ton of NOX removal and the cost per deciview of visibility
improvement are both reasonable, at least the Separated Over-fire Air
(SOFA)-only or, preferably SOFA plus Selective Non-Catalytic Reduction
(SNCR) should definitely be considered as feasible and cost-effective
NOX control alternatives and be accepted as BART for
Corette.
    Response: We disagree that SOFA or SOFA+SNCR should be accepted as
BART for Corette. The BART Guidelines require that cost effectiveness
be calculated in terms of annualized dollars per ton of pollutant
removed, or $/ton. 70 FR 739167. The BART Guidelines list the $/
deciview ratio as an additional cost effectiveness metric that can be
employed along with $/ton for use in a BART evaluation. However, we did
not use this metric for the reasons that were explained in other
responses. As we stated in the proposed FIP, we weighed costs against
the anticipated visibility impacts and we explained that any of the
control options would have a positive impact on visibility; however,
the cost of controls was not justified by the visibility improvement.
As we have explained elsewhere, in our proposal, we considered the
visibility improvement at all Class I areas within 300 km of the
subject BART unit.
    In addition, we note that the UFWS seems to have miscalculated the
dollars per deciview values for the NOX control options.
    Comment: The USFS stated the BART determinations for Corette are
not consistent with previous BART demonstrations that have been made
for other facilities in Montana, as well as with decisions EPA has
approved in other SIPs. And that EPA has identified control options for
both NOX and SO2 that are technically feasible
and cost effective. USFS stated that it is their understanding that EPA
has also determined that the visibility improvement does not justify
the cost of the additional controls.
    Response: We disagree. As the commenter has noted, we rejected
additional controls for Corette since the visibility improvement does
not justify the cost of controls. Moreover, the USFWS has not
identified how this is inconsistent with other BART determinations in
Montana or elsewhere.
    Comment: WEG stated that EPA arbitrarily rejected requiring SCR as
BART for NOX emissions from Corette and that we stated in
the proposed FIP that the control technology would be cost-effective
and achieve greater visibility benefits--in favor of no additional
controls. WEG stated that the EPA's proposed BART determination is
inconsistent with the CAA and the Agency's own record. WEG stated that
that under the factors required to be considered by EPA in determining
BART under the CAA, SCR would constitute BART. WEG stated that EPA
found that SCR for Corette would not be cost-prohibitive and that the
Agency also identified no energy and nonair quality impacts that would
mitigate against the use of SCR, or any remaining useful life issues
that would preclude the use of SCR. WEG stated that with regard to
visibility improvement, the EPA further found that SCR, as opposed to
doing nothing, would achieve greater visibility improvements and that
given that SCR represents ``the best system of continuous emission
control technology available'' (40 CFR 51.308(e)(1)(ii)), there appears
to be no reason to dismiss SCR as BART for Corette. WEG stated that the
EPA asserted that SCR for Corette ``is not justified by the visibility
improvement.'' Yet, the proposed FIP indicates that with the use of
SCR, visibility improvements in the most impacted Class I area, the
Washakie WA, would be 264%, an enormous improvement from current
conditions. WEG stated that SCR would have a visibility improvement of
0.264 deciview and that SCR would reduce visibility impairment at seven
different Class I areas, and that SCR would cumulatively improve
visibility amongst the seven impacted Class I areas by 0.939 deciview.
77 FR 24042.
    WEG stated that such cumulative visibility improvements do not
appear to be unreasonable, but that in this case, the EPA appears to
believe that the level of visibility improvement is not significant
enough to justify the use of SCR. WEG stated that the proposed FIP
provides no information or analysis to indicate that EPA's belief is
not anything more than an arbitrary claim and that there is no
explanation as to why the EPA believed the level of improvement with
the use of SCR was somehow discountable or insignificant. WEG stated
that the EPA's logic is further belied by the fact that the FIP will
fail to achieve meaningful reasonable progress in attaining natural
visibility conditions in Class I areas in Montana and that given the
prospect of such dismal progress in achieving natural visibility, it is
reasonable to presume that any improvement in visibility, no matter how
small, would be significant. WEG stated that the EPA failed to provide
any information or analysis in the proposed FIP or the supporting
record suggesting otherwise. WEG stated that although it is true that
EPA is allowed to consider the degree in improvement in visibility in
determining BART, there is no indication that this factor could be
interpreted to allow the Agency to make arbitrary determinations that a
264% improvement in visibility under a plan that already contains
unreasonable RPGs is insignificant or otherwise not worthy of
regulatory action under the CAA's regional haze program.
    Response: We disagree. We did not arbitrarily reject SCR. Our
proposal clearly laid out the bases for our proposed BART determination
for NOX for Corette. Our regulations define BART as an
emission limitation based on the degree of reduction achievable through
the application of the best system of continuous emission reduction for
each pollutant which is emitted by an existing stationary facility. The
emission limitation must be established, on a case-by-case basis,
taking into consideration the technology available, the costs of
compliance, the energy and nonair quality environmental impacts of
compliance, any pollution control equipment in use or in existence at
the source, the remaining useful life of the source, and the degree of
improvement in visibility which may reasonably be anticipated to result
from the use of such technology. The BART analysis identifies the best
system of continuous emission reduction taking into account:
    (1) The available retrofit control options, (2) Any pollution
control equipment in use at the source (which affects the availability
of options and their impacts), (3) The costs of compliance with control
options, (4) The remaining useful life of the facility, (5) The energy
and nonair quality environmental impacts of control options (6) The
visibility impacts analysis. 70 FR 39163.
    As the final BART Guidelines explain, both the 2001 proposal and
the 2004 reproposal requested comments on two options for evaluating
the ranked options. The first option was similar to

the process that WEG implies should have been followed, where the most
stringent control option must be chosen as long as it does not impose
unreasonable costs of compliance or energy and nonair quality
environmental impacts would justify selection of an alternative control
option. 70 FR 39130. The second option was:

    An alternative decision-making approach that would not begin
with an evaluation of the most stringent control option. For
example, States could choose to begin the BART determination process
by evaluating the least stringent technically feasible control
option or by evaluating an intermediate control option drawn from
the range of technically feasible control alternatives. Under this
approach, States would then consider the additional emissions
reductions, costs, and other effects (if any) of successively more
stringent control options. Under such an approach, States would
still be required to (1) display all of the options and identify the
average and incremental costs of each option; (2) consider the
energy and nonair quality environmental impacts of each option; and
(3) provide a justification for adopting the technology selected as
the ``best'' level of control, including an explanation of its
decision to reject the other control technologies identified in the
BART determination.

    In the final guidelines, EPA ``decided that States should retain
the discretion to evaluate control options in whatever order they
choose, so long as the State explains its analysis of the CAA
factors.'' 70 FR 39130. The BART Guidelines state that we ``have
discretion to determine the order in which you should evaluate control
options for BART'' and that we ``should provide a justification for
adopting the technology that you select as the ``best'' level of
control, including an explanation of the CAA factors that led you to
choose that option over other control levels.'' 70 FR 39170.
    We explained our analysis of the five factors and explained that
the CAA factors that led to our decision were cost-effectiveness and
visibility improvement. The cost-effectiveness of SOFA + SCR was
determined to be $4,491/ton and the visibility improvement at the most
impacted Class I area, Washakie WA, was 0.264 deciview. The impact at
additional Class I areas was shown in Tables 123 and 124. 77 FR 24042.
When we weighed the costs against the anticipated visibility
improvement for Corette the cost of controls was not justified by the
limited visibility improvement. 77 FR 24043.
    With regard to WEG's claim that SCR would result in a visibility
improvement of 264%, WEG used a fundamentally flawed approach to
calculate visibility improvements. Using WEG's approach, a 0.1 deciview
change would produce a 1000% improvement in visibility compared to a
0.01 deciview change. In fact, the change would be 0.09 deciview or
about 1% relative to natural visibility conditions. The approach that
WEG used to calculate percent visibility improvement is mathematically
incorrect. WEG compared a 0.264 deciview change to a zero deciview
change and arbitrarily called this a 264% improvement in visibility. To
get a more accurate estimate, you can use the rule of thumb that 0.5
deciview is approximately equivalent to a 5% change in perceived
visibility. The 0.264 deciview change would be approximately a 2.6%
improvement in visibility relative to natural visibility conditions.
WEG makes the same mistake on page 3 in the comment on Colstrip where
they state: ``with the use of SCR, visibility improvements in the most
impacted Class I areas would be around 50% greater than with the use of
SNCR.'' Here they compared 0.784 deciview with SCR to 0.518 deciview
with SNCR, and concluded that SCR provides a 50% visibility improvement
over SNCR. Again, using the rule of thumb, this would be about a 2.6%
difference in perceived visibility between SCR and SNCR relative to
natural visibility conditions.
    The BART Guidelines state that to make the net visibility
improvement determination you should, ``assess the visibility
improvement based on the modeled change in visibility impacts for the
pre-control and post-control emission scenarios. You have flexibility
to assess visibility improvements due to BART controls by one or more
methods. You may consider the frequency, magnitude, and duration
components of impairment.'' 70 FR 39170. The BART Guidelines also state
that, ``Comparison thresholds can be used in a number of ways in
evaluating visibility improvement (e.g. the number of days or hours
that the threshold was exceeded, a single threshold for determining
whether a change in impacts is significant, or a threshold representing
an x percent change in improvement.'' 70 FR 39170. Our proposal shows
the baseline visibility impact in deciviews, the visibility improvement
in deciviews, the number of Class I areas impacted within 300 km, and
fewer days impacted more than 0.5 deciview in Tables 123 and 124 and
these are more appropriate metrics for evaluating visibility impact.
    We disagree with WEG's statement that the FIP will fail to achieve
meaningful reasonable progress in attaining natural visibility
conditions in Class I areas in Montana and that given the prospect of
such dismal progress in achieving natural visibility, it is reasonable
to presume that any improvement in visibility, no matter how small,
would be significant. We have explained in other responses that 40 CFR
51.308(d)(1)(ii) states that, ``if the State establishes a reasonable
progress goal that provides for a slower rate of improvement in
visibility that the rate that would be needed to attain natural
conditions by 2064, the State must demonstrate, based on the factors in
paragraph (d)(1)(i)(A) of this section, that the rate of progress for
the implementation plan to attain natural conditions by 2064 is not
reasonable; and that the progress goal adopted by the State is
reasonable. The State must provide the public for review as part of its