cumulative visibility improvement modeling analysis that compared
installation of the NOX BART determinations found in EPA's
2013 re-proposal versus the State BART determinations found in the
Wyoming Regional Haze SIP. See Gebhart Report, at 17-24. Mr. Gebhart's
visibility modeling results show that installation of the BART
determinations in EPA's 2013 re-proposal will result in significant
visibility improvement at numerous Class I areas when compared to the
Wyoming SIP. For example, installation of the BART determinations in
EPA's 2013 re-proposal would consistently result a total deciview
improvement of 1.0 deciview or greater over the Wyoming SIP at Badlands
National Park, Savage Run Wilderness, and Wind Cave National Park. In
addition, significant visibility improvements exceeding 0.5 deciviews
were predicted at Badlands National Park, Bridger Wilderness, Mount
Zirkel Wilderness, Rawah Wilderness, Rocky Mountain National Park,
Savage Run Wilderness, and Wind Cave National Park. In summary, the
Conservation Organizations' cumulative visibility improvement modeling
analysis provides further support that significant visibility benefits
can be achieved from the finalization of the BART determinations
contained in EPA's 2013 re-proposal. EPA's 2013 re-proposed rule
advances (without entirely fulfilling) the goals of the regional haze
program to reduce visibility impairment using BART during the first
regional haze five-year planning period. In contrast, the Wyoming
Regional Haze SIP would fall far short of these goals.
    Response: First, we note that the modeling performed by the
Conservation Organizations' contractor used the 2 ppb background
ammonia concentration, and did not correct the model results for
ammonia limiting conditions, and therefore predicts greater visibility
impairment than did EPA's revised modeling. EPA provided information
about the visibility improvement modeled for different BART scenarios
at multiple Class I areas within 300 km of each BART source. EPA
primarily relied on the benefits at the area with the greatest
visibility improvement from controls, but we also considered the
cumulative impacts and benefits at multiple Class I areas. EPA agrees
that considering cumulative visibility benefits by aggregating the
expected improvement from over multiple Class I areas is a useful
metric that can further inform a BART determination. Such an approach
can be useful, for example, in simplifying a complex array of
visibility impacts, especially where a source has significant impacts
on multiple Class I areas.
    Comment: EPA's proposed rule fails to present the cumulative
visibility benefits of installation of SCR at Wyoming's EGUs. Instead,
EPA only presents the visibility benefits for a single Class I area per
source (Wind Cave National Park for all sources except the Jim Bridger
plant (Mount Zirkel Wilderness Area)). The cumulative impact of a
source's emissions on visibility as well as the cumulative benefit of
emission reductions is a necessary consideration as part of the fifth-
step in the BART analysis. The statutory direction and goal of the
regional haze program is to remedy any existing impairment of
visibility in mandatory Class I areas. 42 U.S.C. 7491(1). The
implementing regulations plainly anticipate the need to reduce impacts
in multiple Class I areas, including those outside a state's borders,
and the obligation to assess what is necessary to do so. 40 CFR
51.308(d)(3). Further, states are required to establish reasonable
progress goals for each Class I area, not just the one most impacted by
a single source. Id. section 51.308(d)(1). EPA's own regional haze
guidance document states that a cumulative visibility benefit analysis
is generally consistent with the CAA. 70 FR 39105, 39107 (we believe
that a State's decision to use a cumulative analysis at the eligibility
stage is consistent with the CAA); 40 CFR Part 51, App Y. While the
Guidelines also contemplate and even allow analysis of only the most
impacted Class I area, such an analysis contradicts the regional
approach towards the restoration of visibility. Moreover, given the
number of Class I areas impacted by Wyoming sources, it is illogical
and baseless to fictitiously limit the spectrum of source impact and
emission control benefit. Based upon the guidance and the requirements
of the CAA, the cumulative impact of a source's

emissions on visibility, as well as the cumulative benefit of emission
reductions, should be considered as part of the fifth-step in the BART
analysis. The FLMs, too, have urged EPA Region 8 to consider the
cumulative visibility benefits of requiring stricter controls on BART-
eligible units in Montana. For example, at a public meeting in
Billings, regarding the Montana Regional Haze SIP, Valerie Naylor,
Superintendent of Theodore Roosevelt National Park stated, ``EPA placed
too much emphasis on incremental costs and incremental benefits, while
eliminating consideration of cumulative benefits that would be realized
in the numerous Class I National Parks, National Wildlife Refuges, and
Wilderness Areas impacted by Colstrip.'' The National Park Service
(NPS) has consistently requested that cumulative visibility benefit
analyses be conducted in other regional haze determinations. In
addition, EPA must consider the cumulative visibility benefit of BART
controls on multiple units of a single source. EPA's BART guidelines
make clear that states must consider emissions from an entire source in
determining whether a source is subject to BART, and further clarify
that multiple units at a single utility constitute a single source. 40
CFR Part 51, App Y, sect. II.A.
    The Conservation Organizations retained Air Resource Specialists,
Inc. (ARS) to evaluate the cumulative visibility impact of
NOX BART controls, and found that the cumulative benefit of
SCR at all Wyoming BART-subject EGUs is very significant. In conducting
its supplementary modeling, ARS used an SCR-controlled NOX
emission rate to 0.05 lb/MMBtu to reflect the level of control
achievable with SCR and recalculated baseline emissions to comply with
the BART guidelines, as described in sections I.A.2 and I.C. Otherwise,
ARS employed the same assumptions used by EPA in its analysis.
    ARS's visibility modeling addresses impacts to 18 Class I areas,
including Savage Run Wilderness Area (which is not a mandatory Class I
area but is managed as such by Wyoming). The ARS report addresses the
cumulative benefit of installation of SCR at multiple units at a single
power plant location (ex. the cumulative benefits of installation of
SCR at all four Bridger units). The ARS Report also calculates the
cumulative visibility benefit of installation of SCR on all BART units
in Wyoming. Id. It should not be assumed that ARS's results document
the highest impacts. Rather, they are presented to demonstrate
widespread and far-reaching visibility impacts and improvements that
can be achieved through the use of SCR.
    The cumulative visibility benefit from installation of SCR on all
BART units in Wyoming is significant. The application of SCR control on
Wyoming's subject-to-BART emission units is predicted to improve worst-
case visibility impairment by up to 8 deciviews at the Savage Run Class
I area, with 4 deciviews of improvement or better at six Class I areas.
ARS Report, Table 3-13. For the 98th percentile day, the improvement
after SCR emissions control at all Wyoming BART-subject EGUs is as high
as 3.5 deciviews at Wind Cave National Park. Id. At least six different
Class I areas show improvement of 3 deciviews or more based on the 98th
percentile day after SCR emissions control at all Wyoming BART-subject
EGUs. Id.
    SCR controls at Wyoming's subject-to-BART units are also predicted
to significantly reduce the number of days with visibility impacts
above 0.5 deciview and 1.0 deciview compared to baseline emissions
scenario. Over all 18 Class I areas modeled, the cumulative improvement
from application of SCR on all Wyoming BART-subject EGUs is 721 fewer
days with visibility impairment exceeding 0.5 deciview and 595 fewer
days with visibility impairment exceeding 1.0 deciview. Id., Table 3-
14. These improvements are relatively uniformly distributed across the
seven Class I areas most impacted by Wyoming's subject-to-BART EGUs:
Badlands National Park, Bridger Wilderness Area, Mt. Zirkel Wilderness
Area, Rawah Wilderness Area, Rocky Mountain National Park, Savage Run
Wilderness Area, and Wind Cave National Park.
    Response: As described in another response, EPA did not limit its
analysis of visibility impairment to a single Class I area. We
evaluated visibility impairment from each BART source at multiple Class
I areas. We presented the results for each Class I area, and we
considered the visibility impairment at multiple Class I areas in our
BART determination. The estimates of visibility impairment presented by
the commenter relied on an overly conservative estimates of background
ammonia concentrations, and therefore are likely to overestimate
cumulative visibility benefits.
    In regard to the comment concerning the cumulative visibility
benefit of BART controls on multiple units at a single source, see the
response to a subsequent comment below.
    Comment: It is appropriate to consider both the degree of
visibility improvement in a given Class I area as well as the
cumulative effects of improving visibility across all of the Class I
areas affected. If reducing emissions from a BART source impacts
multiple Class I areas, then a BART determination should incorporate
those benefits. It is not justified to evaluate impacts at one Class I
area, while ignoring others that are similarly significantly impaired
by the BART source. If emissions from the BART source are reduced, the
benefits will be spread well beyond only the most-impacted Class I
area, and these benefits are an integral part of the BART
determination. The BART Guidelines attempt to create a workable
approach to estimating visibility impairment. The Guidelines do not
attempt to address the geographic extent of the impairment, but in
effect assume that all Class I areas are created equal, i.e.,
widespread impacts in a large Class I area and isolated impacts in a
small Class I area are given equal weight for BART determination
purposes. To address the problem of geographic extent, we look at the
cumulative impacts of a source on all Class I areas affected, as well
as the cumulative benefits from reducing emissions. While there may be
more sophisticated approaches to this problem, we believe that this is
the most practical, given current modeling techniques and information
available.
    Response: Contrary to the commenter's assertion, we did assess
cumulative visibility impacts for multiple Class I areas. In our
analysis of visibility impacts, we considered the visibility
improvement at multiple Class I areas within the 300 kilometers of the
modeling domain. For example, in our analysis of BART control options
for Naughton, we considered the visibility improvement at seven Class I
areas (Bridger Wilderness Area, Fitzpatrick Wilderness Area, Grand
Teton National Park, North Absaroka Wilderness Area, Teton Wilderness
Area, Washakie Wilderness Area, and Yellowstone National Park).
    Therefore, our proposed rule did not ignore the visibility
improvement that would be achieved at areas other than the most
impacted Class I area, and we disagree with the assertions that we did
not consider the impacts at multiple Class I areas. In the proposed
rule, we did however focus on the visibility benefits at the most
impacted Class I area.
    Comment: EPA has incorrectly estimated visibility improvement from
all NOX control options at the Laramie River Station.
Wyoming DEQ evaluated visibility improvements at the two nearest Class
I areas and reported the

``The cumulative visibility improvement for SCR, as compared to LNB/
OFA, across Wind Cave National Park and Badlands National Park (based
on the 98th percentile modeled results) was 0.52-0.54 delta deciview
for each of the three units.'' EPA R8 evaluated the five closest Class
I areas but reported results for only the Wind Cave National Park.
    Response: As described in a previous response, in our analysis of
visibility impacts, we considered the visibility improvement at four
Class I areas within 300 kilometers of Laramie River. Modeling results
for all Class I areas considered for each BART source for the re-
proposal were available to the public during the comment period upon
request. (See ``Summary of EPA's Additional Visibility Improvement
Modeling''). Therefore, our proposed rule did not ignore the visibility
improvement that would be achieved at areas other than the most
impacted Class I area, and we disagree with the assertions that we did
not consider the impacts at multiple Class I areas. In the proposed
rule, we did however focus on the visibility benefits at the most
impacted Class I area.
    Comment: EPA rejected Oklahoma's visibility analyses which ``relied
upon pollutant specific modeling to evaluate the benefits from the use
of available SO2 emission controls.'' 76 FR 81728, 81740.
Rather, EPA modeled in Oklahoma ``all visibility impairing pollutants
to fully assess the visibility improvement anticipated from the use of
controls.'' EPA argued this modeling took into account ``the complexity
of atmospheric chemistry and chemical transformation among
pollutants.'' In Wyoming, EPA noted that Wyoming provided ``visibility
improvement modeling results that combine[d] the visibility improvement
from NOX, PM and SO2 control options'' and that
``EPA could not ascertain what the visibility improvement would be from
an individual NOX or PM control option.'' 77 FR 33031. EPA
appears to take contrary positions in Oklahoma and Wyoming. EPA's
inconsistent positions are arbitrary and capricious.
    Response: As described in a response to a previous comment, it
appears that the commenter has confused (1) whether all pollutants were
modeled together; and (2) whether all control technologies were
modeled. All pollutants were modeled together both in modeling
performed by Wyoming and by EPA for BART sources in Wyoming and
Oklahoma, consistent with IWAQM Phase 2 report recommendations. The
additional modeling performed by EPA was designed to evaluate
visibility improvements from certain emissions reduction technologies.
Each of these simulations also included all other visibility impairing
pollutants, so the approach used by EPA in Wyoming and Oklahoma is
consistent.
    Comment: We are concerned about the emissions modeled by EPA as
presented in the ``Summary of EPA's Additional Visibility Improvement
Modeling.'' For example, sulfuric acid mist
(H2SO4) emissions from each PacifiCorp unit are
assumed to double from the baseline and control scenarios that do not
include SCR versus scenarios with SCR. The only explanation provided by
EPA is that ``the emission rate for . . . total sulfate rates were
increased to account for the additional production that results from
SCR controls.'' EPA's approach in Wyoming is not consistent with its
approach elsewhere. For example, in its modeling analysis of addition
of SCR at Colstrip Units 1 and 2 in Montana, EPA assumed no additional
sulfate emissions from the addition of SCR.
    Because H2SO4 must be reported as a hazardous
air pollutant, the Electric Power Research Institute has developed a
widely-accepted method for estimating those emissions. Our analyses
indicate a two-orders-of-magnitude overestimation by EPA of these
visibility-impairing emissions, which results in an underestimation of
the visibility benefit of adding SCR.
    Response: While the method established by the Electric Power
Research Institute may yield more accurate H2SO4
emission rates, we have not found, and the commenter has not
substantiated, that our treatment of H2SO4 led to
meaningfully different modeled visibility improvement, or for that
matter, influenced the BART determination in a material manner. In the
modeling conducted by EPA, we set the sulfuric acid emission rates
equal to those in the State's modeling analyses which typically doubled
the H2SO4 emission rate between the baseline and
SCR modeling scenarios. In comparison to the emission rates for
SO2 and NOX, the emission rates for
H2SO4 were trivial. For example, consider Dave
Johnston Unit 3, where the modeled emission rates for SO2
and NOX in the baseline scenario were 420.0 lbs/hr and
1671.0 lbs/hr, respectively, while the modeled emission rate for
H2SO4 was 2.6 lbs/hr. Here, in comparison to
SO2 and NOX emissions, the emissions rate of
H2SO4 is clearly insignificant and would have a
limited impact on modeled visibility. The same can be said for the SCR
scenario where the modeled emission rates for SO2 and
NOX were 420.0 lbs/hr and 163.3 lbs/hr, respectively, while
the modeled emission rate for H2SO4 was 5.1 lbs/
hr. In short, the H2SO4 emission rates used in
the modeling were so low that it is apparent that they have no more
than a negligible impact on the modeled visibility improvement.
    Comment: EPA must consider the cumulative visibility benefit of
BART controls on multiple units of a single source. EPA's BART
guidelines make clear that states must consider emissions from an
entire source in determining whether a source is subject-to-BART, and
further clarify that multiple units at a single utility constitute a
single source. 40 CFR part 51, App Y, sect. II.A. This is not by
accident or oversight. As EPA stated in its preamble to the BART
Guidelines, ``[a]pplying de minimis levels on a unit by unit basis . .
. could exempt hundreds of tons of emissions of a visibility-impairing
pollutant from BART analysis. [I]t is possible that while emissions
from each unit are relatively trivial, the costs of controlling
emissions from multiple units might be cost-effective in light of the
BART-eligible source's total emissions of the pollutant at issue.'' 70
FR 39104, 39117. With respect to the RHR requirement that states must
project visibility impacts of BART controls, the BART Guidelines state:
``Once you have determined that your source or sources are subject to
BART, you must conduct a visibility improvement determination for the
source(s) as part of the BART determination.'' 40 CFR part 51, App Y,
sect. IV.D.5. Thus, it is clear that both visibility impacts and
visibility benefits are to be considered cumulatively for multiple
units at a single source.
    This is also consistent with EPA's practice in other states. For
example, EPA found it appropriate to consider the combined visibility
impact of pollution controls on multiple units at a single facility in
determining that BART is SNCR for Units 1 and 2 of the Colstrip
facility in Montana. Failure to consider cumulative visibility impacts
discounts the very real effect of source-specific pollution on regional
haze and likewise the cumulative benefits of potential retrofits. EPA
cannot demonstrate that it has properly evaluated BART controls for
affected sources without producing and presenting such a cumulative
analysis.
    Response: EPA notes that, in considering the visibility
improvements reflected in our revised modeling, EPA interprets the BART
Guidelines to require consideration of the visibility improvement from
BART applied to the entire BART-eligible source. The BART Guidelines
explain that, ``[i]f the

emissions from the list of emissions units at a stationary source
exceed a potential to emit of 250 tons per year for any visibility-
impairing pollutant, then that collection of emissions units is a BART-
eligible source.'' In other words, the BART-eligible source (the list
of BART emissions units at a source) is the collection of units for
which one must make a BART determination. The BART Guidelines state
``you must conduct a visibility improvement determination for the
source(s) as part of the BART determination.'' This requires
consideration of the visibility improvement from BART applied to the
BART-eligible source as a whole. We note, however, that while our
regulations require states and EPA to assess visibility improvement on
a source-wide basis, they provide flexibility to also consider unit-
specific visibility improvement in order to more fully inform the
reasonableness of a BART determination, but that does not replace the
consideration of visibility benefit from the source (facility) as a
whole.
    In making the BART determinations in this final action we have
considered visibility improvements at the source, and then also at the
units that comprise the source. The approach that we used in our BART
decisions for Wyoming is consistent with the approach that we used for
Montana.
    Comment: The commenter submitted results of back trajectory HYSPLIT
modeling showing that pollutants reaching certain Class I areas on the
high nitrate haze days did not originate from Laramie River Station.
The commenter concludes that this analysis confirms that reducing
NOX emissions from Laramie River would not improve
visibility at these Class I areas.
    Response: We disagree with the comment that the HYSPLIT results
submitted by the commenter can be used to evaluate the contribution of
Laramie River to visibility impairment at Wind Cave National Park. The
commenter performed HYSPLIT back-trajectory modeling for 10 days with
high ammonium nitrate concentrations at Wind Cave National Park. The 10
days were selected from the period from 2001 to 2010, and only two of
these days occurred during 2001 to 2003 baseline period used for the
BART visibility modeling. These two days were February 24, 2001 and
February 14, 2003, when the observed ammonium nitrate at the IMPROVE
monitoring site at Wind Cave National Park was 41 and 33 inverse
Megameters (Mm-1), respectively. We note that there were many days
during the 2001 to 2003 period on which observed ammonium nitrate
levels at Wind Cave National Park were in the range from 10 to 30 Mm-
1,\133\ but the commenter did not submit HYSPLIT results for these
days.
---------------------------------------------------------------------------

    \133\ Document with Wind Cave IMPROVE data, in the docket.
---------------------------------------------------------------------------

    HYSPLIT is a trajectory model similar to CALPUFF in that both
models use modeled and observed wind field data to predict the
trajectory of pollutants transported from a source area to a receptor
location. There are differences in the formulation of the HYSPLIT and
CALPUFF models and differences in the meteorological data used as input
data for each model, so the predicted trajectory from each model may
vary somewhat as a result of these differences. The most notable
difference in the two models is that CALPUFF is designed to predict
both the trajectory and the chemical conversion of precursor emissions
to fine particulates and to estimate the concentrations of ammonium
nitrate and other species at receptor sites, while HYSPLIT simply
predicts the trajectory of the emissions but does not predict the
chemical transformations nor the concentration of ammonium nitrate at
receptor sites.
    We evaluated the CALPUFF results for February 24, 2001 and February
14, 2003, and found that the HYSPLIT and CALPUFF results were
consistent, i.e., the CALPUFF model did not attribute high levels of
ammonium nitrate at Wind Cave National Park on these two days to
Laramie River. The table of CALPUFF modeling results \134\ shows that
the model predicted a contribution of nitrate from Laramie River of
0.02 deciview on Feb 24, 2001, or 0.05% of the observed value, and on
Feb 14, 2003, 1.697 deciview, or 5% of the observed. The small modeled
contribution on these days is consistent with uncertainty in the
HYSPLIT model. Because the HYSPLIT model does not estimate the
formation of ammonium nitrate, and because HYSPLIT results were only
submitted for two days during the 2001 to 2003 baseline modeling
period, these HYSPLIT results are neither useful nor reliable for
identifying emissions sources that contribute to visibility impairment
at Wind Cave National Park. The HYSPLIT and CALPUFF results do indicate
that sources other than Laramie River contribute to visibility
impairment on the two days with the very highest ammonium nitrate
levels at Wind Cave during the 2001 to 2003 baseline period. However,
the CALPUFF results indicate that Laramie River contributes to
visibility impairment at Wind Cave National Park.
---------------------------------------------------------------------------

    \134\ EPA CALPUFF modeling results for Laramie Rivers Station,
in docket: CALPUFF--WY--BART--bextNO3--BE--LR--Baseline--WindCave--
12112013.
---------------------------------------------------------------------------

    Comment: EPA improperly considered ``cumulative visibility
improvement'' when it rejected Wyoming's BART NOX analyses
and required SCR at Naughton Unit 1 and Naughton Unit 2. (78 FR 34782).
Other comments asserted that EPA improperly considered ``cumulative
visibility improvement'' when it rejected Wyoming's BART NOX
analyses and required SCR at Dave Johnston Unit 3 (78 FR 34778).
Finally, a third set of comments asserted that EPA R8 has incorrectly
estimated visibility improvement from all NOX control
options at Wyodak: Wyoming DEQ evaluated cumulative visibility
improvements at the two nearest Class I areas (Wind Cave and Badlands
National Parks) while EPA R8 reported results for only one Class I
area.
    Response: We disagree with these comments. In evaluating the
visibility improvement associated with various control options, EPA
interprets the CAA to require consideration of visibility improvement
at all impacted Class I areas. Consideration of improvement at multiple
Class I areas, as opposed to just benefits at the most impacted Class I
area, has often been described as ``cumulative visibility
improvement.'' Despite this terminology, however, an analysis of
cumulative visibility improvement does not necessarily require that the
deciview improvement at each area be summed together. While states or
EPA are free to take such a quantitative approach, they are also free
to use a more qualitative approach. Here, we chose to rely primarily on
the visibility improvement at the most impacted Class I area, while
also considering the number of additional Class I areas that would see
improvement, as well as the level of improvement at each area. We did
not expressly rely on a summation of visibility benefits across Class I
areas, as we have done in other regional haze actions, although this
metric was included in some tables. Finally, in our analysis of
visibility impacts, we considered the visibility improvement at both
Class I areas within 300 kilometers of Wyodak. The modeling results for
the second proposal for all Class I areas considered for each BART
source were available to the public during the comment period upon
request. (See ``Summary of EPA's Additional Visibility Improvement
Modeling'').

C. Overarching Comments on BART

1. BART-Eligible Sources
    Comment: OCI Wyoming commented that it was listed as a BART-
eligible source, but that the facility has an enforceable cumulative
annual NOX emission limit of 175.2 tons/year. Therefore, the
facility is not a ``major stationary source'' and is not BART-eligible.
    Response: We agree with this comment and acknowledge that OCI
Wyoming is not a BART-eligible source.
2. Costs of Controls
    Comment: One commenter stated that it supported EPA's use of the
CCM and the Integrated Planning Model (IPM) to calculate costs.
    Response: It is noted that EPA has revised the cost estimates found
in the proposed rule based upon input from various commenters. The
differences in cost for individual units may result from: (1)
Accounting for site elevation in the SCR capital cost; (2) Change in
SCR reagent to anhydrous ammonia from urea; (3) Change in urea SNCR
chemical utilization for Laramie River units due to high furnace
temperature; (4) Incorporation of some of the costs provided in
comments; (4) Change in auxiliary electrical cost from market price to
generating, or ``busbar,'' cost; (5) Correction of dilution water cost
equation for SNCR; and (6) Consideration of shorter plant lifetimes in
some instances.
    More detailed descriptions of these changes and how they were
addressed are discussed in a report (Andover Report) and spreadsheets
\135\ developed for EPA's responses to comments, as well as in our
responses to the specific comments that are associated with these
changes below.
---------------------------------------------------------------------------

    \135\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013; Wyoming EGU BART and
Reasonable Progress Costs--10/28/2013; Wyoming EGU BART and
Reasonable Progress Costs for Jim Bridger--10/28/2013.
---------------------------------------------------------------------------

    Comment: Sargent & Lundy's analysis provides realistic information
regarding what it likely would cost to install and operate an SCR
system at Laramie River Station. They include a cost analysis by
Sargent & Lundy that, unlike EPA's consultant's work, follows the BART
Guidelines and EPA's CCM, and takes into account key site-specific
conditions at Laramie River Station. This analysis is far more accurate
and reliable than what was done by EPA's consultant--it is a site-
specific, from-the-ground-up analysis done by an engineering firm that
has done more NOX control projects for EGUs than any other
firm in the U.S. Sargent & Lundy's analysis provides realistic
information regarding what it likely would cost to install and operate
an SCR system at Laramie River. This analysis strongly supports
Wyoming's decision to select new LNBs and OFA as BART for Laramie River
Station, not SNCR or SCR.
    Response: We do not agree with this comment. The BART Guidelines
provide that: ``You should include documentation for any additional
information used for the cost calculations, including any information
supplied by vendors that affects your assumptions regarding purchased
equipment costs, equipment life, replacement of major components, labor
productivity and rates and any other element of the calculation that
differs from the Control Cost Manual.'' 40 CFR part 51, app. Y, at
IV.4.a.
    Thus, detailed cost documentation is necessary to the extent that
cost assumptions differ from the CCM. In this case, several of Sargent
& Lundy's cost assumptions for control costs at Basin Electric's
Laramie River Station differed from the CCM, but the necessary
supporting documentation was not provided as part of their report.
Detailed descriptions of the deficiencies in the cost assumptions are
described in comments specific to the units. As explained elsewhere in
this document, EPA has accepted some of the revised costs developed for
Basin Electric, but not others.
    Comment: We found that EPA's consultant had added 1.2% to the total
capital investment of SCR to account for ``taxes and insurance.'' The
CCM says: ``In many cases property taxes do not apply to capital
improvements such as air pollution control equipment, therefore, for
this analysis, taxes are assumed to be zero. The cost of overhead for
an SCR system is also considered to be zero. An SCR system is not
viewed as risk-increasing hardware (e.g., a high energy device such as
a boiler or a turbine). Consequently, insurance on an SCR system is on
the order of a few pennies per thousand dollars annually.'' The BART
submittal by PacifiCorp included a 1.1% sales tax and Basin Electric
included a 4% sales tax, both of which were applied to the purchased
equipment costs. It is unclear if application of a sales tax is
appropriate in Wyoming and, if so, what the correct tax rate is.
    Response: To the extent that sales or property taxes are actually
incurred and increase the cost of the project, they should be accounted
for in the cost. See CCM at <IP_ADDRESS> and <IP_ADDRESS>. However, air pollution
control improvements often do not result in increased property taxes.
When these taxes are not in fact applied, they should not be included
in the estimate. The use of 1.2% as an estimate of property taxes and
insurance is a conservative estimate that is consistent with EPA's
assumptions in the IPM documentation. According to the IPM
documentation (version 4.10, Chapter 8, page 8-11): ``U.S. state
property taxes are approximately 0.9% based on a national average
basis. This is based on extensive primary and secondary research
conducted by ICF using property tax rates obtained from various state
agencies. . . . Insurance costs are approximately 0.3%. This is based
on estimates of insurance costs on a national average basis.'' \136\
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    \136\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

    As noted by the commenter, these costs may not in fact apply for
environmental upgrades or may be much less than estimated. EPA did not
have information on the applicability of property taxes at the time we
conducted our cost estimates and conservatively assumed a reasonable
amount. We also note that the commenter did not provide sufficient
information to support a different property tax or insurance rate.
    With regard to sales tax, the IPM algorithm for SCR cost is based
upon historical projects and incorporates typical levels of sales tax.
That is, the capital costs provided by the algorithm(s) are inclusive
of sales tax. Accordingly, for the purpose of the BART cost estimates,
and without additional data to determine what sales taxes would
actually apply, EPA has relied on the assumptions in the IPM algorithm.
    Comment: EPA states in its FIP Action (78 FR 34749): ``For all
control technologies, EPA has identified instances in which Wyoming's
source-based cost analyses did not follow the methods set forth in the
EPA Control Cost Manual. For example, Wyoming included an allowance for
funds used during construction and for owners costs and did not provide
sufficient documentation such as vendor estimates or bids.''
    With respect to AFUDC, another utility (Oklahoma Gas and Electric)
argued in a similar regional haze setting that: ``AFUDC provides a way
of measuring the real cost of interest over the construction period.
AFUDC accounts for the time value of money associated with the
distribution of construction cash flows over the construction period,
which may be approximately 18 months for an SCR project.'' Total
capital investment, as

defined in the CCM, includes all costs required to purchase equipment
needed for the control system (purchased equipment costs), the costs of
labor and materials for installing that equipment (direct installation
costs), costs for site preparation and building, working capital, and
off-site facilities.
    A cost breakdown of total capital investment (as defined above) is
presented in several examples in the CCM. For example, Table 1.4 (page
1-32 of Section 4--NOX Controls) and Table 2.5 (page 2-44 of
Section 4--NOX Controls) therein explicitly identify AFUDC
as component ``E'' of the TCI, where TCI = D + E + F + G + H + I,
where: D = Total Plant Cost; E = AFUDC; F = Royalty Allowance; G =
Preproduction Cost; H = Inventory Capital; I = Initial Catalyst and
Chemicals.
    References 9 and 10 on page 2-38 of the CCM explicitly include
AFUDC as a cost component and reference two reports, by Shattuck and
Kaplan, in support of its use. The EPA built upon this knowledge base
and costing methodology in its publication of the CCM in 2002. Thus,
the CCM allows the time value of money, measured by the real discount
rate, to be incorporated into the cost estimate.
    Section 2.3.1 of the CCM (Elements of Total Capital Investment)
describes the need for total capital investment to include all
expenditures incurred during the construction phase of the project,
including direct costs, indirect costs, fuel and consumables expended
during start-up and testing, and other capitalized expenses. The only
items explicitly mentioned to be excluded are common facilities that
already exist at the site. AFUDC is part of the expense that will be
incurred with the installation of a large air pollution control system,
and the accepted practice in the utility industry and by financial
institutions is to treat AFUDC as a capitalized expenditure. This
approach is recognized in publications by the U.S. Department of
Energy--Energy Information Administration, such as the Annual Energy
Outlook, and in publications by the Electric Power Research Institute,
such as the Technical Assessment Guide (EPRI TAG). As previously
mentioned, the EPA clearly followed this approach in its studies of
retrofit costs of SO2 and NOX in the years
leading up to its publication of the CCM. Furthermore, AFUDC has been
included in several other coal-fired boiler BART determinations, and
AFUDC is included as a line item in EPA's Coal Quality Environmental
Cost (CUECost) worksheets for flue gas desulfurization (FGD) control
systems. In cases where the time value of money during the construction
period would be significant (e.g., projects with longer construction
periods such as the installation of SCR), the CCM clearly allows
inclusion of AFUDC.
    PacifiCorp supports and adopts by reference Oklahoma Gas and
Electric's argument regarding including AFUDC in project cost
estimates. Whether or not AFUDC is included in project cost estimates
does not materially impact the results reached under the EPA CCM
method, its inclusion should not constitute a basis for EPA to reject
Wyoming's entire cost assessments. PacifiCorp has provided tables that
provide comparisons of PacifiCorp's project specific EPA CCM method
results where AFUDC is excluded in one set of costs and is included in
the other to demonstrate this point.
    Response: We disagree with commenters' assertions that AFUDC is a
cost that should be incorporated into our cost analysis, as it is
inconsistent with CCM methodology. The utility industry uses a method
known as ``levelized costing'' to conduct its internal comparisons,
which is different from the methods specified by the CCM. Utilities use
``levelized costing'' to allow them to recover project costs over a
period of several years and, as a result, realize a reasonable return
on their investment. The CCM uses an approach sometimes referred to as
overnight costing, which treats the costs of a project as if the
project were completed ``overnight'', with no construction period and
no interest accrual. Since assets under construction do not provide
service to current customers, utilities cannot charge the interest and
allowed return on equity associated with these assets to customers
while under construction. Under the ``levelized costing'' methodology,
AFUDC capitalizes the interest and return on equity that would accrue
over the construction period and adds them to the rate base when
construction is completed and the assets are used. Although it is
included in capital costs, AFUDC primarily represents a tool for
utilities to capture their cost of borrowing and return on equity
during construction periods. AFUDC is not allowed as a capitalized cost
associated with a pollution control device under CCM's overnight
costing methodology, and is specifically disallowed for SCRs (i.e., set
to zero) in the CCM.\137\ Therefore, in reviewing other BART
determinations, EPA has consistently excluded AFUDC.\138\ EPA's
position regarding exclusion has been upheld in the United States Tenth
Circuit Court of Appeals.\139\
---------------------------------------------------------------------------

    \137\ CCM (Tables 1.4 and 2.5 show AFUDC value as zero).
    \138\ See, e.g., 77 FR 20894, 20916-17 (Apr. 6, 2012)
(explaining in support of the North Dakota Regional Haze FIP, ``we
maintain that following the overnight method ensures equitable BART
determinations * * *.''); 76 FR 52388, 52399-52400 (August 22, 2011)
(explaining in the New Mexico Regional Haze FIP that the Manual does
not allow AFUDC)
    \139\ Oklahoma v. U.S. EPA, 723 F.3d 1201 (10th Cir. 2013).
---------------------------------------------------------------------------

    The fact that CUECost, the EPRI TAG, and the Department of Energy
cost estimates, and even cost estimates used as the basis for IPM
typically include AFUDC is immaterial in this case because, for this
purpose, overnight cost methodology is used and AFUDC is not included
in that methodology.
    Finally, we reject the commenter's assertion that Wyoming's
inclusion of AFUDC did not provide a material basis for EPA to
disapprove portions of the State's SIP. Inclusion of AFUDC increases
total project costs of SCR by several million dollars. For example,
Attachment 4 to PacifiCorp's comment letter shows that AFUDC for Dave
Johnston Unit 4 would add more than $9.5 million dollars to the capital
costs of SCR. We find that amounts of this magnitude are not trivial
when assessing the costs of compliance.
    Comment: Sargent & Lundy's cost estimate does include AFUDC, which
accounts for the interest charges that would be incurred by Basin
Electric during SCR construction. AFUDC is a real and a significant
cost on capital intensive, long-term projects such as SCR installation,
which require financing over a construction period of up to four years.
Indeed, to exclude AFUDC would inappropriately bias the cost estimate
in favor of high capital intensity projects. Therefore, consistent with
industry practice, Sargent & Lundy included AFUDC, calculated based on
a typical SCR construction project cash flow assuming a real interest
rate of 7%.
    The inclusion of AFUDC is not, as EPA asserts, inconsistent with
either the BART Guidelines or the CCM. See 78 FR 34749. The CCM simply
references ``Total Capital Investment,'' which includes ``all costs
required to purchase equipment needed for the control system,'' as well
as ``working capital.'' CCM 2.3.1, page 2-5 (emphasis added). This
includes costs required to purchase equipment needed for the control
system (purchased equipment costs), the costs of labor and materials
for installing that equipment (direct installation costs), costs for
site preparation and building, working

capital, and off-site facilities. Id. Nowhere in the CCM does EPA state
that AFUDC is not an appropriate cost, particularly with respect to
long-term, capital intensive pollution control projects. And even if
the CCM made such an assertion, inclusion of AFUDC in a cost estimate
cannot be grounds for SIP disapproval because: (1) the CCM is not
binding for purposes of making BART determinations, and (2) requiring
states to exclude AFUDC is not consistent with Congress' general
directive that states include ``costs of compliance'' in their BART
determinations.
    The CAA requires states to consider in their BART determinations
the ``costs of compliance,'' but does not further define the term. See
42 U.S.C. 7491. EPA's regulations codify the BART factors, but neither
the regulations nor the BART Guidelines in Appendix Y purport to
restrict in any manner the categories of costs that states should
consider when making a BART determination. See 70 FR 39166-39168. AFUDC
is a ``cost of compliance.'' Basin Electric cannot fund large capital-
intensive projects like SCR without financing, and the costs related to
such financing are real and substantial. Consideration of AFUDC is
therefore entirely consistent with the CAA's broad reference to ``costs
of compliance,'' and excluding AFUDC would be inconsistent.
    In this case, even if AFUDC is excluded from the total annual
costs, the costs of installing SCR do not decrease substantially enough
to justify SCR. Sargent & Lundy performed sensitivity analyses
demonstrating that the cost-effectiveness of SCR at Laramie River
remains at between $8,531 per ton of NOX removed and $9,048
per ton of NOX removed even if AFUDC is excluded.
Furthermore, if the maintenance cost and labor rate of 1.5% also is
factored into the analysis, consistent with the CCM, as opposed to the
lower 0.25% used by Sargent & Lundy, the cost-effectiveness remains
above $8,500 per ton of NOX removed. Sargent & Lundy also
performed a sensitivity analysis demonstrating that including property
taxes and insurance as 1.2% of total capital investment, consistent
with the approach taken by Andover but not with the CCM approach, more
than offsets the exclusion of AFUDC. S&L Evaluation section 7.1.4,
Table 10.
    Response: EPA agrees that AFUDC can be a substantial overall cost
on large capital projects that extend over a period of several years.
However, as noted in the previous response, the CCM clearly excludes
AFUDC in the overnight cost method. Furthermore, as we explain in more
detail in responses to comments that pertain to specific sources, we
disagree with the commenter's estimates for cost effectiveness for the
Laramie River units.
    Comment: Commenters assert that EPA's regional haze FIP is flawed
because it failed to provide sufficient documentation, such as vendor
estimates or bids to validate its estimates. EPA attempts to justify
its approach by stating: ``In our revised cost analyses, we have
followed the structure (emphasis added) of the EPA CCM, though we have
largely used the Integrated Planning Model cost calculations to
estimate direct capital costs and operating and maintenance costs.'' 78
FR 34749.
    EPA did not explain what it meant by following the ``structure'' of
the manual, versus simply following the manual. By contrast, PacifiCorp
solicited and incorporated vendor estimates into these comments. This
new information, which EPA must incorporate into new BART analyses to
the extent EPA issues a final regional haze FIP, validates Wyoming's
BART analyses cost of control estimates. In addition, it further
quantifies the inaccuracies in EPA's development and use of purported
new information that in no way qualifies as vendor estimates, bids, or
any type of site-specific vendor information.
    Response: We do not agree with this comment. By following the
``structure'' of the manual, EPA included all of the cost elements that
the CCM indicates should be included, while excluding those that should
not (such as AFUDC). In other words, EPA employed the overnight cost
method as is required for BART analyses. The BART Guidelines require
that the CCM be followed unless deviations from it are clearly
documented and explained.
    PacifiCorp received bids from vendors and EPA has incorporated
information from these bids into its revised cost estimates. However,
for reasons described elsewhere in response to comments, EPA has not
accepted all of the costs. The BART Guidelines state: ``You should
include documentation for any additional information you used for the
cost calculations, including any information supplied by vendors that
affects your assumptions regarding purchased equipment costs, equipment
life, replacement of major components, and any other element of the
calculation that differs from the CCM.'' 70 FR 39166.
    With regard to Basin Electric, vendor quotes for the Laramie River
Station were not supplied. As Basin Electric indicated in its comments,
``[t]he LRS cost estimates are conceptual in nature; thus, S&L did not
procure equipment quotes specifically for the LRS control systems.
Rather, equipment costs for the LRS projects are based on conceptual
designs developed for the control systems, preliminary equipment sizing
developed for the major pieces of equipment, and recent pricing for
similar equipment.''
    In effect, like the IPM cost algorithms, the method that underlies
Sargent & Lundy's estimate for Basin Electric is empirically based on
past data, and not vendor quotes developed specific to Laramie River.
We have, however, accepted some of the costs submitted by Basin
Electric and not accepted others.
    Comment: Even if EPA had the authority to require the use of the
CCM, which it does not, EPA's insistence on Wyoming's strict compliance
with the costing methodology set forth in the CCM, without adjusting
the methodology to account for important site-specific factors, leads
to an erroneous and arbitrary and capricious result. This is not
required by the CCM. Indeed, the manual expressly discounts the
usefulness of the costing methodology to power plants generally and to
SCR control systems specifically, and it acknowledges that deviation
from the methodology may be appropriate based on a user's engineering
judgment.
    The CCM provides general costing methodology for stationary source
air pollution control technologies, applicable primarily to regulatory
development where a rough order of magnitude estimate is appropriate.
The introduction to the manual also caveats its usefulness when
assessing control costs at power plants, which use different cost
accounting. Cost Manual section 1.1, page 1-3. Specifically, it states
that ``[e]lectrical utilities generally employ the EPRI Technical
Assistance Guidance (TAG) as the basis for their cost estimation
processes.'' Id. In a footnote, it explains that while power plants
might still use the manual, ``comparisons between utilities and across
the industry generally employ a process called `levelized costing' that
is different from the methodology used here.'' Id. section 1.1, page 1-
3 n.1.
    The CCM also generates rough estimates of costs that are less
accurate than the site-specific cost factors that are more appropriate
for BART determinations at a large power plant. The manual is used
heavily in regulatory development, and the costing methodology is
geared specifically to avoid the necessity of site-specific information
and to enable estimates to be prepared at ``relatively low cost with

minimum data.'' Id. section 2.2, page 2-3 (internal quotations
omitted). However, the level of accuracy is much lower than that for
estimates using site-specific information. The cost estimating
procedure can provide a ``rough order of magnitude,'' estimate that is
``nominally accurate to within  30%.'' Id. section 1.2,
page 1-4. Indeed, ``EPA does not claim cost estimates for industry at a
greater than study level accuracy for industrial users'' because ``the
industrial user will necessarily have much more detailed information
than the generic cost and sizing information.'' Id. section 2.2, page
2-3, 2-4.
    Where the user has detailed site-specific information, the manual
does not contemplate strict adherence to its costing methodology. Users
may ``exercise `engineering judgment' on those occasions when the
procedures may need to be modified or disregarded.'' Id. section 1.3,
page 1-7. With respect to estimating factors used in cost estimates,
``the application of an appropriate factor requires the subjective
application of the analyst's best judgment.'' Id. section <IP_ADDRESS>, page
2-28. The manual is designed to provide a tool box for estimating costs
that can be helpful to the engineer, but ``[t]he bottom line is that
there is no clear-cut `cookbook' process through which the analyst will
be able to make the right informed decision each time, and the
formalized costing methodology employed by the Manual is only part of
that process.'' Id. section 2.6, page 2-37.
    With respect to SCR cost estimations, the CCM is no more than a
``tool to estimate study-level costs for high-dust SCR systems.'' Id.
section 2.4, page 2-40. The ``[a]ctual selection of the most cost-
effective option should be based on a detailed engineering study and
cost quotations from the system suppliers.'' Id. This requirement for a
more detailed study relying on site-specific factors is necessary
because, as EPA acknowledges, the CCM's assumptions regarding capital
investment for SCR are inaccurate. Id. section <IP_ADDRESS>, page 2-27. For
systems like SCR, ``the control in question is either so large or so
site-specific in design that suppliers design, fabricate, and construct
each control according to the specific needs of the facility.'' Id.
section <IP_ADDRESS>, page 2-27.
    Thus, for these systems, ``the Manual deviates from its standard
approach of providing study level costs and, instead, provides a
detailed description of the factors that influence the TCI [total
capital investment] for the analyst to consider when dealing with a
vendor quotation.'' Id. Under these circumstances, EPA acknowledges
that getting vendor quotes may be difficult because they cannot be done
in an ``off-the-shelf'' fashion. Id. The engineering judgment of the
manual's user is especially critical in estimating the costs of an SCR
retrofit: ``Probably the most subjective part of the cost estimate
occurs when the control system is to be installed on an existing
facility.'' Unless the original designers had the foresight to include
additional floor space and room between components for new equipment,
the installation of retrofitted pollution control devices can impose an
additional expense to ``shoe-horn'' the equipment into the right
locations. For example, an SCR reactor can occupy tens of thousands of
square feet and must be installed directly behind a boiler's combustion
chamber to offer the best environment for NOX removal. For
these boilers, there is generally little room for the reactor to fit in
the existing space and additional ductwork, fans, and flue gas heaters
may be needed to make the system work properly.
    To quantify the unanticipated additional costs of installation not
directly related to the capital costs of the controls themselves,
engineers and cost analysts typically multiply the cost of the system
by a retrofit factor. The proper application of a retrofit factor is as
much an art as it is a science, in that it requires a good deal of
insight, experience, and intuition on the part of the analyst. The key
behind a good cost estimate using a retrofit factor is to make the
factor no larger than is necessary to cover the occurrence of
unexpected (but reasonable) costs for demolition and installation. Such
unexpected costs include, but are certainly not limited to, the
unexpected magnitude of anticipated cost elements; the costs of
unexpected delays; the cost of reengineering and re-fabrication; and
the cost of correcting design errors. Id. section <IP_ADDRESS>, page 2-28.
The CCM cannot properly account for these uncertainties and thus
provides that users can apply a ``retrofit factor'' of up to 50 percent
to account for them. Id. EPA notes that ``[s]ince each retrofit
installation is unique, no general factors can be developed.'' Id.
<IP_ADDRESS>, page 2-29.
    In sum, the BART Guidelines and CCM were drafted and are to be
applied as guidelines to assist the states in their decision making,
not as inflexible mandates. Knowing this, states like Wyoming follow
the BART Guidelines generally but make the necessary localized and
individualized adjustments required to generate realistic, rather than
formalistic, cost estimates. Accordingly, EPA should expect the states
to deviate on occasion, not to slavishly follow the BART Guidelines and
CCM to the point of generating artificial (and unrealistic) cost
estimates. Yet that is now exactly what EPA contends the states must
do. EPA's current approach to using the BART Guidelines and manual as
grounds for disapproval without deference to the states' authority and
local control is unreasonable, erroneous, and arbitrary and capricious.
    Response: There are only very limited situations in which a state
or EPA can depart from the CCM cost methodology. ``The 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). In order to maintain and improve consistency,
cost estimates should be based on the OAQPS CCM, where possible. The
CCM addresses most control technologies in sufficient detail for a BART
analysis. The cost analysis should also take into account any site-
specific design or other conditions identified above that affect the
cost.'' 70 FR 39166.
    The guidelines for BART determinations make it clear that the CCM
is the intended methodology for conducting a BART cost determination.
It also states why: To maintain and improve consistency. However, the
CCM does state that site-specific conditions should be incorporated.
Site-specific conditions could include space constraints, or a design
feature that could complicate installing a control. However, the BART
Guidelines are clear that the analyst should document any deviations
from the CCM: ``You should include documentation for any additional
information you used for the cost calculations, including any
information supplied by vendors that affects your assumptions regarding
purchased equipment costs, equipment life, replacement of major
components, and any other element of the calculation that differs from
the CCM.'' 70 FR 39166.
    In fact, the record does not point to any unusual circumstances
that explain why SCR costs in Wyoming should be so much higher than
costs of SCR at other similar facilities. As will be demonstrated in
responses to comments that are specific to the individual units, the
commenters did not identify any unique features of their plants that
would make of the installation of an SCR so difficult that the cost
would be outside the range of what has been experienced elsewhere, even
accounting for such things as elevation, which is discussed later in
these responses to

comments. The BART Guidelines also provide the following explanation,
which makes it clear that other cost methods are supplemental, not
replacements for the CCM cost method: ``We believe that the CCM
provides a good reference tool for cost calculations, but if there are
elements or sources that are not addressed by the CCM or there are
additional cost methods that could be used, we believe that these could
serve as useful supplemental information.'' 70 FR 39127.
    Although the focus in the second quote is ensuring the remaining
useful life is incorporated into the amortization schedule, this
passage affirms that the CCM's annualized cost methodology should be
followed. The following quote from the same page of the BART guidelines
sheds light on the type of costing methodology employed by the CCM,
``capital and other construction costs incurred before controls are put
in place can be rolled into the first year, as suggested in EPA's OAQPS
CCM.'' Although this passage is again focused on the remaining useful
life, the text we reproduce is a reference to the basic CCM cost
methodology--the overnight method. That is what is meant with the
reference of rolling future costs into the first year. The ``all in''
method that OG&E used does not do that--it projects costs to a future
date. Although the CCM does not use the term, ``overnight cost,'' it is
widely used in industry.
    The U.S. Energy Information Administration defines ``overnight
cost'' as ``an estimate of the cost at which a plant could be
constructed assuming that the entire process from planning through
completion could be accomplished in a single day. This concept is
useful to avoid any impact of financing issues and assumptions on
estimated costs.'' \140\ In effect, the overnight cost is the present
value cost that would have to be paid as a lump sum up front to
completely pay for a construction project.
---------------------------------------------------------------------------

    \140\ EIA, ``Updated Capital Cost Estimates for Electricity
Generation Plants,'' November 2010, footnote. 2. Available at:
http://www.eia.gov/oiaf/beck_plantcosts/?src=email.
---------------------------------------------------------------------------

    As will be described in EPA's other responses to comments regarding
specific plants, commenters did not provide the documentation required
under the RHR to demonstrate why their costs were so much higher than
costs for other similar units. Such documentation would include any
vendor quotes to include scope of supply, explanations of labor
productivity issues with supporting documentation, and other concerns
raised by commenters and addressed in more detail in other comments.
    Comment: Sargent & Lundy is both a design and engineering firm and
a system supplier, and it has provided exactly the type of detailed
scoping-level engineering study for SCR contemplated by the CCM when
selecting the most cost-effective NOX control device. EPA
acknowledges that with respect to SCR cost estimations, the CCM is no
more than a ``tool to estimate study-level costs for high-dust SCR
systems.'' CCM section 2.4, page 2-40. For systems such as SCR, ``the
control in question is either so large or so site-specific in design
that suppliers design, fabricate, and construct each control according
to the specific needs of the facility.'' Id. section <IP_ADDRESS>, page 2-
27. See also id. at section 2.3, page 2-30 (``the design is highly
site-specific.''). Importantly, the ``[a]ctual selection of the most
cost-effective option should be based on a detailed engineering study
and cost quotations from the system suppliers.'' Id. at section 2.6,
page 2-43.
    The Sargent & Lundy Evaluation provides a cost estimate not based
on the general, broad brush assumptions set forth as examples in the
CCM, but on a conceptual design of SCR at Laramie River based on site-
specific variables and Sargent & Lundy's extensive knowledge of, and
experience with, SCR installations on coal-fired utility boilers. Based
on this conceptual design, Sargent & Lundy estimated equipment costs
using example vendor quotes for similar projects, and used appropriate
commodity pricing references, rates for labor based on industry
publications and locality-specific data, and, where necessary,
allowances.
    Response: As EPA has noted in previous responses to comments, the
CCM is a good reference tool for estimating costs. With regard to
Sargent & Lundy's estimates at Laramie River Station, EPA has found
deficiencies in the cost estimates or underlying assumptions that will
be discussed in more detail in comments that are specific to units.
    Comment: One commenter asserted that the EPA's cost evaluations
overestimated the annualized capital costs of BART options by assuming
an unrealistically high interest rate, which is particularly extreme in
the cost estimates for SCR because of its relatively higher capital
costs than the other control technologies evaluated. The commenter
calculated and submitted documentation of what the commenter considers
to be the real cost of capital interest to PacifiCorp, which was 5.66
percent, and to Basin Electric, which was around 2 percent. According
to the commenter, the EPA continues to assume a much higher 7 percent
interest rate, apparently based on the EPA's mistaken belief that this
rate is supported by the CCM. The commenter stated that while the CCM
states the social interest rate ``is currently set at seven percent''
by the Office of Management and Budget (OMB), it references the
interest rate established by OMB in 1992, whereas the OMB updates
interest rates yearly and the current social interest rate is 1.7
percent for a 20-year period (citing OMB Circular A-94, App. C (revised
Dec. 2012)).\141\ The commenter concluded that even if EPA were correct
in applying the social interest rate, it should have used the current
published OMB rate in accordance with the CCM's direction.
---------------------------------------------------------------------------

    \141\ http://www.whitehouse.gov/sites/default/files/omb/assets/a94/dischist-2013.pdf.
---------------------------------------------------------------------------

    The commenter went on to contend that the CCM recommends a source-
specific interest rate for BART and reasonable progress determinations,
rather than the social interest rate applied in promulgation of
regulations. According to the commenter, the 7-percent ``social
interest rate'' is used to estimate the cost to society of taking an
action. However, the CCM states that this social interest rate ``is
probably not appropriate for industry.'' The commenter noted that the
RHR requires the EPA to make case-by-case determinations of ``the costs
of compliance'' for identified BART and reasonable progress options,
which the commenter interprets as being the actual cost to the source
of implementing the studied alternatives. The commenter indicated that
where the EPA, the state, or industry is evaluating ``the economic
impact that [air-pollution control] equipment would have upon the
source,'' a source-specific interest rate is appropriate. The commenter
concluded that the EPA erred in relying on a generic and outdated 7-
percent social interest rate that resulted in a particularly inflated
estimate of SCR costs, and asserted that in recalculating the
annualized capital costs of control technologies, the EPA must either
use the current social interest rate of 1.7 percent, or more
appropriately, source-specific rates of 5.66 percent for PacifiCorp
Units and 2 percent for Basin Electric Units.
    Response: We have retained the use of a 7-percent interest rate in
calculating the capital recovery factor. For cost analyses related to
government regulations, an appropriate ``social'' interest (discount)
rate should be used,

not the source's actual rate of borrowing. OMB Circular A-4, providing
Federal agencies guidance on developing regulatory analyses, and dated
September 17, 2003, reiterates the guidance found in the earlier
Circular A-94: ``As a default position, OMB Circular A-94 states that a
real discount rate of 7 percent should be used as a base-case for
regulatory analysis. The 7 percent rate is an estimate of the average
before-tax rate of return to private capital in the U.S. economy, based
on historical data. It is a broad measure that reflects the returns to
real estate and small business capital as well as corporate capital. It
approximates the opportunity cost of capital, and it is the appropriate
discount rate whenever the main effect of a regulation is to displace
or alter the use of capital in the private sector.'' \142\
---------------------------------------------------------------------------

    \142\ Office of Management and Budget, Circular A-4, Regulatory
Analysis, http://www.whitehouse.gov/omb/circulars-a004_a_4/.
---------------------------------------------------------------------------

    In addition, EPA calculated capital recovery factors using 3-
percent and 7-percent interest rates in determining cost-effectiveness
for the Regulatory Impact Analysis for the BART Guidelines.\143\ The 3-
percent rate is mainly used when private consumption displacement is
the main impact of a regulatory action. This cost of retrofitting power
plants for this action displaces private capital far more than private
consumption, so 3-percent is not an interest rate that is applicable
here. We consider our use of an interest rate of 7-percent to calculate
capital recovery to be a conservative approach.
---------------------------------------------------------------------------

    \143\ ``Regulatory Impact Analysis for the Final Clean Air
Visibility Rule or the Guidelines for Best Available Retrofit
Technology (BART) Determinations Under the Regional Haze
Regulations,'' EPA-0452/R-05-004 (June 2005).
---------------------------------------------------------------------------

    Finally, the interest rate cited by the commenter from Appendix C
to OMB Circular A-94, 1.7 percent, is for an altogether different
purpose than the type of regulatory analysis supporting today's rule.
According to the discount rate policy described in Circular A-94,
interest rates contained in Appendix C, which reflect Treasury
borrowing rates, are for the purpose of internal planning decisions of
the Federal Government. This is in contrast to regulatory actions, for
which as noted above, the circular prescribes use of a ``real discount
rate of 7 percent.'' \144\
---------------------------------------------------------------------------

    \144\ http://www.whitehouse.gov/omb/circulars_a094#8.
---------------------------------------------------------------------------

    Comment: One commenter stated that the EPA used the IPM default
cost for auxiliary power of $0.06/kWhr for all of the control scenarios
evaluated, which is much higher than the auxiliary power cost commonly
used in cost-effectiveness analyses. The commenter asserted that the
appropriate cost of auxiliary power to use in a cost-effectiveness
analysis is the busbar cost of power to run the plant, not the cost of
power sold. According to the commenter, auxiliary power is the power
required to run the plant, or power not sold, and cost-effectiveness
analyses are based on the cost to the owner to generate electricity, or
the busbar cost, not market retail rates. The commenter indicated that
the site-specific data reported by PacifiCorp to the Federal Energy
Regulatory Commission (FERC) in 2010 indicates that the busbar power
cost for the Wyoming PacifiCorp plants is typically in the range of
$0.02/kWhr to $0.03 lb/kWhr, and for Basin Electric's Laramie River
Station, the company used a cost of $0.015/kWhr, which is consistent
with the busbar power cost.
    Response: In EPA's original analysis, we used the default values
for electricity in the IPM model, although we agree that the cost of
power used for auxiliary loads should be the cost of the owner to
generate the electricity rather than the market price it could be sold
at. EPA has reviewed FERC Form 1 for PacifiCorp \145\ and has
incorporated in our revised costs for each plant the stated cost of
electricity per net kWh. For Laramie River Station, the costs in their
July 2008 BART analysis \146\ are used, as these are more consistent
with PacifiCorp's reported cost of generation (as reported to FERC)
than the values later used by Basin Electric or by EPA in our original
cost analysis (that our proposed action was based on), which are more
reflective of retail power prices rather than the cost to generate.
---------------------------------------------------------------------------

    \145\ FERC Financial Report, FERC Form No. 1: ``Annual Report of
Major Electric Utilities, Licensees and Others and Supplemental Form
3Q: Quarterly Financial Report, PacifiCorp, Year/Period of Report
2010/Q4,'' pgs 402.2, 403, 403.2, see line 35.
    \146\ Black & Veatch, ``Basin Electric Power Cooperative Laramie
River Station Refined BART Visibility Modeling,'' July 24, 2008, pg
25 of 176.
---------------------------------------------------------------------------

    Comment: One commenter argued that the IPM model is not appropriate
for generating site-specific cost estimates to evaluate the cost-
effectiveness of BART projects because it does not account for those
site-specific requirements that significantly impact overall project
costs.
    Response: As described in our proposal, the IPM is a multi-regional
linear programming model of the U.S. electric power sector. IPM relies
upon a very large number of data inputs and provides forecasts of
least-cost capacity expansion, electricity dispatch, and emission
control strategies for meeting energy demand and environmental,
transmission, dispatch, and reliability constraints. EPA has used IPM
to evaluate the cost and emissions impacts of proposed rules, such as
the recent Mercury and Air Toxics Standard (MATS).\147\
---------------------------------------------------------------------------

    \147\ http://www.epa.gov/airmarket/progsregs/epa-ipm/docs/SuppDoc410MATS.pdf.
---------------------------------------------------------------------------

    We wish to clarify that, for our proposed action on Wyoming's
Regional Haze SIP, we did not actually run IPM. Rather, we used
information from one component of IPM, specifically, the component that
develops the costs of air pollution control technologies. Broadly
speaking, IPM relies upon numerous components and sub-components to
specify constraints and variable values that feed into the model
algorithms used during an actual IPM model run. The air pollution
control cost development component is just one of these numerous
components. We relied upon the cost information and equations contained
in this component by manually placing them into a spreadsheet that
calculated the capital, operating, and maintenance costs associated
with pollution control options. While we relied upon the results of
these spreadsheet calculations, we did not then use those results to
run IPM, as the type of information generated by an actual IPM model
run (e.g., generation dispatch decisions, capacity decisions) is not
relevant to our action.
    We documented our use of the equations from IPM's air pollution
control technology cost component by placing the raw cost calculation
spreadsheets in the docket for our proposal.\148\ These spreadsheets
contain the IPM equations, corresponding variable values, selected
notes regarding assumptions and variable ranges, as well as selected
tables from IPM Base Case v4.10 documentation. Because we did not
perform an actual IPM model run, the spreadsheet and contractor's
report in the docket for our proposal sufficiently document our use of
the cost methodologies from the IPM air pollution control cost
component.
---------------------------------------------------------------------------

    \148\ Wyoming EGU BART and Reasonable Progress Costs--10/28/
2013; Wyoming EGU BART and Reasonable Progress Costs for Jim
Bridger--10/28/2013.
---------------------------------------------------------------------------

    We disagree with commenters' characterization of the cost-
development methodology contained in IPM as generalized and inadequate
for performing site-specific cost estimates. As noted in the
documentation for IPM's cost-development methodology for SCR, the
methodology is based upon

two databases of actual SCR projects.\149\ These databases include 2004
and 2006 industry cost estimates prepared for the Midwestern Ozone
Group, and a proprietary in-house database maintained by engineering
firm Sargent & Lundy. The Midwestern Ozone Group information was cross-
referenced with actual 2009 projects, and escalated accordingly.
Sargent & Lundy then used the information in these databases to develop
the equations described in the cost component, taking into account the
pre-control NOX emission level, degree of reduction, coal
type, facility size, and numerous other unit-specific factors. While a
costly engineering evaluation that included site visits in addition to
use of satellite imagery might produce a more refined cost estimate, we
disagree that our approach does not produce site-specific estimates. As
noted by EPA in response to other comments, EPA's use of satellite
imagery enabled us to evaluate each of the major site-specific issues
raised by commenters.
---------------------------------------------------------------------------

    \149\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix52A.pdf.
---------------------------------------------------------------------------

    Specifically, we input several site-specific factors, such as fuel
type, baseline NOX level, reagent cost and type, level of
NOX reduction, site-specific power and reagent costs, etc.
into the algorithm. The algorithm also provides for adjustment of cost
to account for retrofit difficulty. The CCM at section <IP_ADDRESS> (page 2-
28 of Section 1 Chapter 2) calls for a retrofit difficulty factor to
account for the site-specific costs associated with a retrofit, such as
demolition or moving existing equipment, etc. A retrofit factor is also
used in the IPM algorithm, making it consistent with the approach used
in the CCM. Per the documentation for the IPM algorithms: ``The
formulation of the SCR cost estimating model is based upon two
databases of actual SCR projects. The comparison between the two sets
of data was refined by fitting each data set with a least squares curve
to obtain an average $/kW project cost as a function of unit size. The
data set was then collectively used to generate an average least-
squares curve fit. The least squares curve fit was based upon an
average of the SCR retrofit projects. Retrofit difficulties associated
with an SCR may result in capital cost increases of 30 to 50 percent
over the base model. The least squares curve fits were based upon the
following assumptions: Retrofit Factor =1; Gross Heat Rate = 9880;
SO2 Rate = < 3 lb/MMBtu; Type of Coal = Bituminous; Project
Execution = Multiple lump sum contracts.'' \150\
---------------------------------------------------------------------------

    \150\ Sargent & Lundy, ``IPM Model--Revisions to Cost and
Performance for APC Technologies--SCR Cost Development Methodology,
FINAL'', August 2010.
---------------------------------------------------------------------------

    Therefore, the IPM algorithm is based upon actual retrofit
projects. As such, the average or typical retrofit found for the
retrofit projects evaluated is assumed to use a retrofit factor of 1.0,
and for more difficult than average retrofits, a retrofit factor
greater than 1.0 would apply. On page 1 of the documentation of the IPM
model for SCR, it states that ``Retrofit difficulties associated with
an SCR may result in capital cost increases of 30 to 50% over the base
model.'' Therefore, EPA expects that retrofit difficulty factors may
apply up to around 1.50 at the maximum. In effect, project elements
that are typically included in an SCR retrofit are accounted for in the
cost estimated by the algorithm, and deviations from those typical
costs can be addressed by a retrofit factor. In fact, the algorithm
expressly calls for a retrofit factor that can be varied (see Table 1
of reference, variable ``B''), which makes it consistent with the
retrofit difficulty factor method called for in the CCM. And, because
the IPM algorithm is based upon actual projects, it already
incorporates contingency. Finally, the IPM algorithm can be modified
for other effects, such as elevation, and EPA has since examined this
and modified its estimates in this final action to correct for the
effects of altitude.
    Comment: One commenter alleged that site elevation was not
reasonably accounted for in EPA's cost estimates, particularly for
PacifiCorp's Naughton Units 1 and 2 and Dave Johnston Unit 3. The
commenter explained that algorithms in the IPM model were developed for
a generic coal-fired power plant located at or near sea level. However,
site elevation can have a significant impact on control system sizing
and design. Thus, elevation of the site must be considered separately
and factored into the unit capacity (i.e. megawatts) accordingly due to
its effects on the flue gas volume. The commenter pointed out that
PacifiCorp's Wyoming BART units are located at elevations ranging from
approximately 5,000 to 7,000 feet above mean sea level. At this
elevation, flue gas flows will be 20-30 percent higher than similarly
sized units at mean sea level. The higher flue gas flow requires larger
ductwork, larger reactors, and more robust support structures, and
these items have a profound influence on the overall project cost.
While Wyoming had this information available in its SIP, EPA failed to
account for site elevation in its FIP.
    Response: EPA agrees with commenter that higher altitudes will
increase the volume of flue gas, making it necessary to increase the
cross-sectional area of associated ductwork and the SCR reactor.
Increased flue gas volume also impacts the fan design. Consequently,
EPA has revised its cost calculations for SCR in this final action to
address issues associated with plant altitude. While altitude has a
significant impact on the cost of SCR, it does not make a significant
difference in the cost of SNCR because altitude does not affect the
urea flow rate or the associated urea storage system, urea circulation
system, or metering/mixing/pumping systems. There may be a slight
increase in the number of injectors due to increased furnace cross-
section, but this is expected to be a small part of the total cost of
an SNCR system.
    Comment: The same commenter argued that site configurations were
not reasonably accounted for in EPA's cost estimates, particularly for
the Naughton Units 1 and 2 and Dave Johnston Unit 3. The IPM model
applies a retrofit factor to account for the difficulty of fitting new
BART equipment into the existing site configuration. The Andover Report
states that site visits were not possible. Thus, retrofit factors for
Naughton Units 1 and 2, and Dave Johnston Unit 3 were determined based
on a review of Google EarthTM images of the station.
Accordingly, the Andover Report applied retrofit factors for the units
that are highly subjective based on minimal site information. The
commenter argued that, when preparing site-specific cost estimates,
site visits must be conducted to evaluate the true complexity
associated with the retrofit and to assess specific modifications to
the plant that would be required to overcome issues associated with
congestion, as well as difficulties associated with construction.
Neither Andover nor EPA sought permission from PacifiCorp to visit the
sites of the BART units, nor did Andover explain why it ``wasn't
possible'' to do so. Both Sargent & Lundy and Babcock and Wilcox have
extensive experience with PacifiCorp's Naughton and Dave Johnston
facilities. Just since 2005, Sargent & Lundy has been contracted by
PacifiCorp to perform 14 projects at Dave Johnston station and over 25
projects at Naughton station. These projects range from site
evaluations, studies, detailed engineering, or functioning as
PacifiCorp's Owner's Engineer for major environmental retrofit
engineer, procure, and construct projects. From having conducted many
site visits at these stations, Sargent &

Lundy is very aware of site-specific congestion and construction
challenges that would affect SCR installations at Naughton Units 1 and
2 and Dave Johnston Unit 3. Similar to Sargent & Lundy's site-specific
experience, Babcock and Wilcox has recently completed major
environmental retrofit projects on Naughton Units 1 and 2 (wet scrubber
additions) and Dave Johnston Unit 3 (dry scrubber and baghouse
addition), making Babcock and Wilcox uniquely positioned to offer
budgetary cost estimates for further retrofits to those facilities with
significant first-hand knowledge. While Wyoming had much of this
information available in its SIP, EPA failed to account for this site-
specific information in its FIP.
    Response: EPA disagrees with the commenter. EPA did account for
site-specific factors when performing its cost estimates. Because SCRs
are built on or next to the boiler structure, they are often elevated,
and there is usually equipment in one direction (the boiler) or the
other (other air pollution control equipment, like an electrostatic
precipitator (ESP), scrubber, or chimney) that limits access. This
issue is complicated further with boilers that are located adjacent to
one another--a common configuration. Due to the height of the SCR,
large cranes play a vital role in their construction. The location of
cranes next to where the SCR is going to be built can be difficult.
    As noted in a paper by Babcock & Wilcox,\151\ key issues for SCR
constructability are site access and ability to locate a crane and the
resulting erection sequence. The erection sequence is impacted by the
crane that is available and whether it can fit on site because the
crane and its location will limit the size of material that can be
lifted into place. A larger crane allows for the lifting of larger
pieces of ductwork, resulting in fewer lifts and less fabrication in
the air. Without adequate access for a crane and proximity to a lay-
down area for material, erection must be done with smaller pieces,
which will require more labor and expense.
---------------------------------------------------------------------------

    \151\ Hines, J.A., Kokkinos, A., Fedock, D., ``Benefits of SCR
Design for Constructability'', Power Gen, International 2001,
December 11-13, 2001, Las Vegas
---------------------------------------------------------------------------

    Access around and between the boilers will determine crane location
and location of material receiving areas. In some cases, it may be
necessary to demolish equipment or buildings in order to gain adequate
access. In other cases, it may be necessary or preferable to erect
cranes on the top of the boiler structure (as was performed for the SCR
installed at Dominion's Brayton Point Unit 3).\152\
---------------------------------------------------------------------------

    \152\ Wright, B., Erickson, C., Phillipo, M., ``Keys to Success:
SCR Installations at Dominions Brayton Point Units 1 and 3'',
Electric Power, May 2008.
---------------------------------------------------------------------------

    Because of its easy availability and it usefulness in providing a
``bird's eye'' view of the site congestion (how close equipment is
located to each other, room for a crane, etc.), site access, local
transportation options, availability of a lay-down area to locate
material on site, and other limitations around the site, satellite
imagery has become a very important tool in evaluating these site-
specific factors. In fact, the major air pollution control original
equipment manufacturers use satellite imagery to assist them in
estimating site congestion issues, determining location of construction
equipment and other limitations on and around the site in this way.
Site visits are also useful, but are normally performed in addition to
rather than in lieu of careful examination of satellite images. For
example, in their comments to EPA in 2010, the Utility Air Regulatory
Group used satellite photographs to demonstrate the relative difficulty
of different SCR installations.\153\
---------------------------------------------------------------------------

    \153\ Cichanowicz, E., ``Current Capital Cost and Cost-
Effectiveness of Power Plant Emissions Control Technologies'',
Prepared for Utility Air Regulatory Group, January 2010.
---------------------------------------------------------------------------

    While a site visit can be useful and provide additional
information, assessing satellite imagery provides adequate information
to determine access to the site, access around the boilers,
availability of space for locating construction equipment and
materials, and whether buildings or equipment must be demolished to
make room for the equipment. Notably, the budgetary price provided to
PacifiCorp from Babcock & Wilcox was not developed from a site visit.
Per the cover page of the budgetary proposal, ``[g]iven the budgetary
nature of this request, we have not made site visits to consider layout
options: instead, we have used available drawings and made necessary
assumptions to enable us to establish a basis to derive quantities of
material and associated costs.''
    For SCR installations, site visits and more detailed boiler
drawings provide additional information regarding air preheater
location and whether it must be relocated to make room for the SCR, or
if ductwork limitations require demolition of other large pieces of
equipment such as ESPs. Such costs will significantly increase the cost
of retrofitting an SCR. However, relocation of the air preheater or ESP
was not identified as a concern by any of the commenters. Instead, most
commenters raised retrofit issues that are commonly encountered in SCR
retrofits, including location of SCR support steel and possible
interferences with other equipment on site; penetration of boiler
building by SCR ductwork; location of cranes for units that are side-
by-side; the need for increased fan capacity and associated electrical
modifications; and stiffening of ductwork due to increased pressure
drop from SCR. As a result, the retrofit costs in the IPM algorithms
that were developed from actual SCR projects should capture these more
common retrofit issues and to the extent that some situations seem more
difficult, can be addressed with retrofit factors.
    In its cost estimates, PacifiCorp provided a long comparative table
(over 100 rows with 25 columns of data) for Dave Johnston 3 and
Naughton 1 and 2 showing different cost estimating methods. The table
showed vendor budgetary pricing for Direct Capital Costs based upon a
proposal from Babcock & Wilcox. While EPA accepts the proposal from
Babcock & Wilcox as part of our final action, we have a few general
comments. The proposal, while providing a detailed total scope of
supply, provides a total cost for the project without line items. In
addition, the items included under the Owner's scope by Black and
Veatch are limited to: Boiler modifications; air-preheater
modifications; medium voltage power source; asbestos, lead, and
polychlorinated biphenyls (PCB) remediation; commercial licenses and
permits; and spare parts. Some of these costs, such as air-preheater
modifications, will not be required, while others will have a small to
modest impact on the overall cost. Notably, the cost estimate includes
items like potable water systems, fire protection, service water, other
assorted auxiliaries, as well as roads, fences, etc. Therefore, the
proposal is close to being ``turnkey'' and includes nearly all costs
for the project. It also includes some items that would fall into the
category of General Facilities. The proposal assumes that other
modifications to the Naughton plant will result in abandonment of
existing chimneys and ESPs on Units 1 and 2. Currently, these chimneys
are in service. Babcock & Wilcox also determined that the existing fans
are likely to be sufficient for the additional draft loss from the SCR.
As was noted in the Andover Report, we think that there may be some
substantial conservatism built into the Babcock and Wilcox estimate.
For example, the proposal states that the offset of Naughton Units 1
and 2 is just enough

to make it impractical to make a common structure for both SCR
reactors. However, examination of the drawings in the proposal shows
that Babcock & Wilcox has sized the ductwork to compensate for the
offset so that the SCR reactors should be able to be supported with a
common structure. Also, the proposal assumes that the abandoned stacks
at both sites will be dismantled, although this does not appear to be
necessary for Naughton Unit 2 and may not be necessary for Dave
Johnston Unit 3 if shorter horizontal duct runs are used. Finally,
comparison of the cost estimate provided by PacifiCorp for Naughton
Unit 1 and 2, and Naughton 1 especially, to historical costs shows that
the costs are well in excess of what other SCRs have cost. This is
particularly perplexing because additional fan capacity is not needed,
and it is not necessary to move the air preheater.
    In light of the proposal and its fairly comprehensive scope of
supply, PacifiCorp's capital cost estimate included a number of items
that EPA is not including in our cost estimate, as noted below:
    1. Process Contingency: Although the CCM permits a process
contingency of 5%, in EPA's opinion this is not necessary today for SCR
on coal-fired boilers firing the coals used in Wyoming. According to
the Department of Energy's National Energy Technology Laboratory,\154\
``Process contingency is intended to compensate for uncertainty in cost
estimates caused by performance uncertainties associated with the
development status of a technology. Process contingencies are applied
to each plant section based on its current technology status.''
According to the document, for commercially available technologies,
process contingency could range from 0-10%.
---------------------------------------------------------------------------

    \154\ U.S. Department of Energy, National Energy Technology
Laboratory, ``Cost Estimating Methodology for NETL Assessments of
Power Plant Performance'', DOE/NETL-2011/1455, April 2011, pg 4.
---------------------------------------------------------------------------

    When the CCM was issued in January 2002, SCR was commercially
available but was only emerging in application on coal-fired utility
boilers in the U.S. According to a study by Cichanowicz,\155\ there was
only about 13,000 MW of coal-fired capacity using SCR in the U.S. at
the end of 2001, with nearly all SCRs installed in the prior two years,
meaning that there was very limited long-term experience with SCR on
coal-fired units. SCR usage on coal-fired boilers has since increased
about ten-fold to about 130,000 MW of coal capacity (over 40% of all
U.S. coal capacity), and is therefore a very well proven and well
understood technology on a wide range of U.S. coals, including Powder
River Basin coal. As a result, the process contingency for SCR on coal-
fired utility boilers should be much lower today than what it was when
the CCM was issued in January 2002, which was 5%. EPA believes that for
SCR applications on utility boilers burning Powder River Basin coals
(the Wyoming utility boilers), which are very well understood SCR
applications, there should not be any need for process contingency.
---------------------------------------------------------------------------

    \155\ From data in Cichanowicz, J., Muzio, L., Hein, M., ``The
First 100 GW of SCR in the U.S.,--What Have We Learned?''--2006 Mega
Symposium.
---------------------------------------------------------------------------

    2. Project Contingency: Because the cost estimates developed for
PacifiCorp are already very conservative and based upon detailed
estimates of the labor and materials to build the SCR, a 15% project
contingency is excessive. According to the CCM at Section 1.1, Chapter
1, pages 1-4: ``The accuracy of the information in the Manual works at
two distinct levels. From a regulatory standpoint, the Manual
estimating procedure rests on the notion of the ``study'' (or rough
order of magnitude--ROM) estimate, nominally accurate to within  30%. This type of estimate is well suited to estimating control
system costs intended for use in regulatory development because they do
not require detailed site-specific information necessary for industry
level analyses.''
    The methods and cost elements of the CCM were adapted from the
American Association of Cost Engineers, or AACE (CCM Section 1, Chapter
2, pages 2-5). AACE 16R-90 \156\ states that, ``Project Contingency is
included to cover the costs that would result if a detailed-type
costing was followed as in a definitive-type study.'' According to
National Energy Technology Laboratory (NETL), ``AACE 16R-90 states that
project contingency for a `budget-type' estimate (AACE Class 4 or 5)
should be 15% to 30% of the sum of [bare erected cost], [engineering,
procurement, and construction] fees and process contingency.'' \157\
AACE 18R-97 defines different classes of estimates, from Class 5 (least
detailed) to Class 1 (most detailed).\158\ The methodology used in the
CCM falls into a Class 4 or Class 5, while the methodology used by
PacifiCorp's contractor, Babcock and Wilcox, is clearly a far more
detailed estimate that does not leave out any aspect of the project.
Therefore, the project contingency factor is not applicable. The 15%
project contingency factor in the CCM for SCR is based upon use of the
cost-estimating method described in the CCM to develop the Total Direct
Capital Costs. It is not intended to apply to a detailed estimate that:
---------------------------------------------------------------------------

    \156\ AACE Recommended Practice, AACE 16R-90; www.aacei.org/non/rps/18R-90.pdf.
    \157\ U.S. Department of Energy, National Energy Technology
Laboratory, ``Cost Estimating Methodology for NETL Assessments of
Power Plant Performance'', DOE/NETL-2011/1455, April 2011, pg 5.
    \158\ AACE Recommended Practice, AACE 16R-87; www.aacei.org/non/rps/18R-97.pdf.
---------------------------------------------------------------------------

     Includes many cost items not explicitly included in the
estimating method described in the CCM to develop the Total Direct
Capital Costs and meant to be included in the 15% project contingency;
and
     Already has substantial contingency built into it through
conservative assumptions.
    In fact, the CCM discusses the importance of not double-counting
contingency in multiple places, such as retrofit factor and
contingency: ``Due to the uncertain nature of many estimates, analysts
may want to add an additional contingency (i.e., uncertainty) factor to
their estimate. However, the retrofit factor is a kind of contingency
factor and the cost analyst must be careful to not impose a double
penalty on the system for the same unforeseen conditions. Retrofit
factors should be reserved for those items directly related to the
demolition, fabrication, and installation of the control system. A
contingency factor should be reserved (and applied to) only those items
that could incur a reasonable but unanticipated increase but are not
directly related to the demolition, fabrication, and installation of
the system. For example, a hundred year flood may postpone delivery of
materials, but their arrival at the job site is not a problem unique to
a retrofit situation.'' (emphasis added). The CCM, therefore,
explicitly anticipates that some analysts may, incorrectly, apply
multiple contingencies for the same areas of uncertainty even when
using the methods described in the CCM for estimating Total Direct
Capital Costs.
    Because the cost estimates developed for PacifiCorp are already
very conservative and based upon detailed estimates of the labor and
materials to build the SCR, rather than study-level estimates, they
have double-counted both the costs that are intended by the CCM to be
included in the project contingency when using the CCM method, plus
they have added additional contingency in the form of conservative
assumptions to address uncertainties in their estimate. For this
reason, a 15% project contingency is

excessive, and we have not revised our cost estimates to include one.
    3. General Facilities: The cost estimate from Babcock & Wilcox,
submitted by PacifiCorp, includes several items that would fall into
the category of General Facilities, and in order to avoid double-
counting, EPA has not included an additional line item for General
Facilities.
    Comment: The same commenter suggested that the project-specific
scopes were not reasonably accounted for in EPA's cost estimates,
particularly for Naughton Units 1 and 2 and Dave Johnston Unit 3.
Additional project-specific scope concerns (related to the addition of
SCR on-site) include limited capacity of the existing induced-draft
fans and auxiliary power system, as well as National Fire Protection
Association-related equipment reinforcement requirements. Larger, more
powerful, induced-draft fans may overload existing electrical systems,
and the electrical systems may require significant modifications.
Structural stiffening of the duct work, and equipment downstream of the
boiler and upstream of the new fans may also be required by National
Fire Protection Association regulations to operate at more negative
pressures due to the installation of the SCR. These types of costs are
not generally reflected in the base case IPM cost algorithms, but they
must be taken into consideration in the development of a project-
specific cost estimate. Wyoming had this information available in the
Wyoming SIP, but EPA failed to account for this important cost
information in its FIP.
    Response: All SCR systems experience a pressure drop across the
SCR, and therefore some consideration must be made to fan capacity for
every SCR system. The algorithm used by EPA explicitly includes a
``balance of plant'' cost line item such as an allowance for additional
fans and auxiliary electrical work.\159\ As for the duct stiffening,
this is frequently necessary when new fans are installed. However, as
noted in the proposal by Babcock & Wilcox, additional fan capacity is
not expected to be necessary at Naughton Units 1 and 2 or Dave Johnston
Unit 3.
---------------------------------------------------------------------------

    \159\ Sargent & Lundy, ``IPM Model--Revisions to Cost and
Performance for APC Technologies--SCR Cost Development Methodology,
FINAL'', August 2010, Table 1, pg. 5.
---------------------------------------------------------------------------

    Comment: The same commenter alleged that Owner's costs were not
reasonably accounted for in EPA's cost estimates, particularly for
Naughton Units 1 and 2 and Dave Johnston Unit 3. Owner's Costs include
a variety of non-financial costs incurred by the owner to support
implementation of the air pollution control project. Owner's Costs are
project-specific, but generally include costs incurred by the owner to
manage the project, hire and retain staff to support the project, and
costs associated with third party assistance associated with project
development and financing. Owner's Costs are real costs that the owner
will incur during the project and are typically included in cost
estimates prepared for large air pollution control retrofit projects.
In fact, EPA's Coal Quality Environmental Cost (CUECost) model includes
Owner's Costs (or ``Home Office'' costs) in its air pollution control
system cost estimating workbook and interrelated set of spreadsheets.
See CUECost Workbook User's Manual Version 1.0, prepared by Raytheon
Engineers & Contractors, Inc. and Eastern Research Group, Inc., EPA
Contract No. 68-D7-0001, Appendix B, pages B-3 and B-6. Wyoming had
this information available in its SIP, but EPA failed to account for
this important cost information in its FIP.
    Response: Home office fees are Owner's costs, and these are
accounted for in the CCM in the 10% allowance for Engineering and
Owner's Costs. See CCM at Section 4.2, Chapter 2, page 2-44). As
described in Table 2.5 of the CCM, engineering and home office fees
represent 10% of purchased equipment costs. In this respect, we agree
with the commenter's assertions that the CCM does discuss some of the
items that roll up into these line items. For example, the CCM does
provide for ``Engineering and Home Office Fees'' that includes the home
office and plant support costs described in the comments. We have
included the portion of Owner's Costs/Surcharge in the total cost, up
to the value specified for ``Engineering and Home Office Fees''
indicated by the CCM, which is 10%.
    The cost factors used in the CCM include home office fees in the
10% that is applied to engineering fees; however, the line item for
Owner's Cost in the IPM estimate was made zero. The reason Owners Cost
was removed is that the CCM includes owner's cost with the 10% for
engineering and home office fees. A 10% engineering charge was already
applied and therefore an additional allowance for home office fees
would be greater than the cost allowed under the CCM. Even if that cost
were added at a 5% rate, it would increase capital cost by 5%. This
difference would not change the determination.
    Comment: The same commenter argued that regional labor concerns
were not reasonably accounted for in EPA's cost estimates, particularly
for Naughton Units 1 and 2 and Dave Johnston Unit 3. Regional labor
concerns are not accounted for in the IPM model. Regional labor
characteristics must be taken into consideration in a site-specific
cost estimate to account for factors including labor availability,
project complexity, local climate, and working conditions. Because the
Naughton and Dave Johnston facilities are in relatively remote
locations, higher labor rates must be paid to attract the kind of
skilled workers required to construct an SCR project. In addition, the
locations are subject to extreme cold and wind that can result in
significant productivity and construction challenges and delays, adding
to the overall project cost. Wyoming had this information available in
its SIP, but EPA failed to account for this important cost information
in its FIP.
    EPA's flawed analyses of incomplete ``new'' cost information
directly resulted in EPA's proposed requirements for PacifiCorp to
install SCR on Naughton Units 1 and 2 and Dave Johnston Unit 3. In
contrast, to be responsive to EPA's request for additional information,
PacifiCorp has solicited budgetary project-specific cost information
from Babcock and Wilcox, an active and uniquely positioned competitive
market participant for SCR technology, for these same units. In
conjunction with Sargent & Lundy's expertise, PacifiCorp has
incorporated the site-specific budgetary cost information from Babcock
and Wilcox into updated EPA CCM side-by-side comparisons with the
Andover Report results to further demonstrate the inaccuracies in the
new cost information developed by EPA. (The following included tables
to summarize the results of these comparisons.) It is important to note
that PacifiCorp has utilized a 20-year remaining equipment life and has
excluded AFUDC from the results in the tables for comparison purposes.
    As demonstrated by the results in the tables, EPA significantly
understated costs per ton of pollutant removed. As such, EPA based its
cost-effectiveness conclusions on significantly inaccurate information.
Before taking any final action on the proposed FIP, EPA must consider
in its final BART analyses the additional cost information being
provided by PacifiCorp.
    Response: EPA disagrees with this comment. The commenter claims
that remote locations require offering higher wage rates and that
conditions at the site, including inclement weather, reduce worker
productivity. Because the commenter claims that these are important
factors that impact cost, the

commenter should have provided data to support its assertions. The
commenter did not provide any data to demonstrate that wage rates in
the area near its facilities are higher than in more populated areas.
The commenter also did not provide any specific productivity factors or
other evidence to show how the commenter arrived at its man-hour
estimates or explain how those estimates differ from a normal
productivity. Without such information, EPA cannot review and validate
the commenter's claims that labor productivity is low or that labor
cost is high.
    On the other hand, labor rates for union construction labor are
available from the Construction Labor Research Council (CLRC),\160\ and
these rates are consistently well below what appears to have been
assumed in the itemized estimate provided with Basin Electric's
comments. The difference is too large to be explained by per diem.
Because both Basin Electric and PacifiCorp used Sargent & Lundy to
prepare their cost estimates, it is reasonable to assume that both
companies have made similar assumptions. Moreover, in addition to the
high labor rates assumed, there are additional line item costs for
overtime and per diem. As a result, the estimates provided by
commenters appears to incorporate additional costs or provisions well
beyond the normal costs both in the labor rates and in the line item
for additional labor costs.
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    \160\ Construction Labor Research Council Union Wages and
Supplements, available from the National Construction Boilermaker
Employers Web site, www.nacbe.com.
---------------------------------------------------------------------------

    While EPA welcomes the use of SCR vendor estimates, such as those
used by PacifiCorp, or engineering estimates, such as those provided by
Basin Electric, specific details supporting the estimates must be
provided in order for them to be useful. Without details on the scope
of supply, the estimates cannot be used as a reliable source of
information because vendor scope could potentially be in error or could
be duplicative of other costs included in the estimate elsewhere.
    With regard to adjustment for regional labor concerns, neither
PacifiCorp nor Basin Electric's submittals were satisfactory.
Deficiencies in Basin Electric's submittal with regard to regional
labor concerns are addressed elsewhere in these responses to comments.
The proposal from Babcock & Wilcox, while showing a total lump sum
price, did not demonstrate how they factored in regional labor
concerns.
    Comment: The IPM methodology relied upon in the Andover Report is
inconsistent with the assumptions set forth in the CCM. While EPA
states that its revised cost analyses ``followed the structure of the
EPA CCM,'' EPA acknowledges that ``we have largely used the Integrated
Planning Model cost calculations to estimate direct capital costs and
operating and maintenance costs.'' 78 FR 34749. See also Andover Update
(``In estimating the costs of controls, the following were considered:
IPM Cost Models, US EPA Air Pollution CCM.''). The IPM model is a
regulatory model that uses cost algorithms developed by Sargent & Lundy
to estimate system-wide costs of air pollution technology for adoption
of national regulations. The inputs in the IPM model do not conform to
the methodology set forth in the CCM, and neither Andover nor EPA
offers any explanation for the discrepancies. This failure epitomizes
the arbitrary and capricious nature of EPA's decision making.
    A careful reading of the Andover Report evidences that Andover only
followed the CCM on a limited basis, and in doing so, read into the CCM
requirements that are non-existent, while ignoring wholesale many of
the CCM's recommendations. The following language from the report
illustrates the concern: ``The BART Guidelines recommend use of the EPA
Air Pollution CCM, and the methodology used here for estimating costs
is consistent with the recommendations in the manual, such as inclusion
of taxes, insurance and administrative costs, and the use of overnight
cost for capital cost.''
    As an initial matter, the CCM does not anywhere recommend the use
of ``overnight cost'' for estimating capital costs. See Section XI.B.3.
The overnight approach assumes construction of a project ``overnight,''
which means a party would not incur any interest charges, including
AFUDC, or experience any cost escalations. While a ``constant dollar
approach'' may be read to exclude escalation, the CCM does not
recommend that users assume that the interest costs related to
constructing a capital-intensive, multi-year project will cost the same
as an off-the-shelf control technology that can be installed in a day.
Furthermore, based on the acknowledgment in its report, Andover appears
only to have followed the methodology set forth in the CCM in these
three limited respects. In all other respects, Andover relied on the
IPM cost algorithms for its SCR estimate, without regard to the CCM.
For SNCR capital costs, Andover relied on an assumed $20/kW cost rather
than using the IPM algorithms or the methodology set forth in the CCM.
    The high-level cost algorithms in the IPM model and the assumed
$20/kW capital cost for SNCR resulted in a substantial underestimate of
the costs of designing and constructing both the SCR and SNCR systems.
For example, the only inputs to the IPM cost modules are unit size,
heat input, fuel type, and NOX removal efficiency. The CCM
uses these inputs, but also provides for using SCR design parameters,
such as flue gas flow rate, actual stoichiometric ratio (the amount of
reagent needed to achieve target NOX emissions), space
velocity and area velocity (a measure of flue gas resident time in the
SCR reactor), catalyst volume, SCR reactor dimensions, and reagent
consumption. The CCM methodology includes similar design parameters
specific to SNCR, which the IPM model does not include and which
Andover did not consider in its cost estimate.
    Andover also used the IPM model to calculate indirect capital costs
in the SCR cost estimate. The IPM model includes in its indirect
capital cost algorithm factors for Engineering and Construction
Management, Labor, and Contractor Profit/Fees. Andover removed from the
IPM capital cost calculation both Owner's Costs and AFUDC. Moreover,
the IPM Model does not include a number of other inputs that are
included in the CCM, including preproduction costs, inventory capital,
and initial catalyst costs, and Andover did not adjust the model to
incorporate these additional costs. Andover's selection of certain IPM
model inputs and exclusion of inputs in the CCM resulted in the
substantial underestimation of the indirect capital costs necessary to
design and install an SCR system.
    For SNCR, Andover arbitrarily assigned a capital cost of $20/kW,
without using the IPM algorithms or performing an analysis of direct
and indirect costs consistent with the CCM. Andover relied on the IPM
model to calculate operating and maintenance costs except for urea
reagent costs for SNCR, which uses factors that differ from those
recommended in the CCM and costs utilized by Sargent & Lundy. The
model's simplistic treatment of catalyst costs, for example, is
inconsistent with the recommendations in the CCM and underestimates
annual catalyst replacement costs for SCR and for SNCR. For SNCR,
Andover adjusted the urea utilization rate from the IPM model without
explanation, which cut in half estimated annual urea costs. Andover
also assumed urea would be used as the reagent for SCR, which

increased reagent costs above those calculated by Sargent & Lundy based
on the use of anhydrous ammonia.
    Neither Andover nor EPA explains why the cost estimate uses only
limited portions of the CCM, or why Andover believes use of the IPM
cost methodology is somehow more representative of the costs of control
that would be incurred by Basin Electric for installation of SCR and
SNCR systems. It is inherently contradictory, and therefore arbitrary
and capricious, for EPA to base its proposed disapproval of Laramie
River BART on the alleged failures of Wyoming to follow the CCM, while
at the same time relying on a consultant's report that does not comply
with those same standards.
    Response: EPA disagrees with the commenter. The methodology used by
EPA is consistent with the CCM for the following reasons: (1) EPA used
the overnight cost method, which excludes certain cost elements such as
AFUDC; (2) The comparative nature of BART costs makes use of the IPM
algorithms a reasonable approach; and (3) as demonstrated in the
Exhibit 14 of Basin Electric's comments, use of the cost equations in
the CCM would have actually resulted in lower costs than predicted by
the IPM algorithms.
    Moreover, both the IPM algorithms and Sargent & Lundy's estimates
for Basin Electric are empirically based from data collected at other
projects. According to page 21 of Exhibit 14 to Basin Electric's
comments: ``. . . Cost estimates prepared for LRS are based on
equipment costs and budgetary quotes available from similar projects
and Sargent & Lundy's experience with the design and installation of
retrofit SNCR and SCR control systems. The LRS cost estimates are
conceptual in nature; thus, Sargent & Lundy did not procure equipment
quotes specifically for the LRS control systems. Rather, equipment
costs for the LRS projects are based on conceptual designs developed
for the control systems, preliminary equipment sizing developed for the
major pieces of equipment, and recent pricing for similar equipment . .
.'' As a result, the estimates provided by Basin Electric are not more
valid than those developed by EPA.
    Commenter claims that AFUDC should be included in the cost
analysis. As described in our responses to other comments, the CCM
explicitly excludes AFUDC from control costs, and EPA's estimates were
correct in excluding AFUDC. This is central to the overnight cost
methodology.
    Commenter is critical of EPA's method for estimating SNCR capital
cost. With regard to SNCR cost methodology, the cost of SNCR is driven
primarily by the operating cost. Capital cost has a small effect on
total cost of SNCR. Therefore, a simplifying assumption that yields a
reasonable estimate of capital cost will result in an annualized cost
accurate to within  30%. Based upon input from technology
vendors on cost for other units \161\ and based upon the fact that
EPA's contractor Andover has over 25 years of direct experience
designing, specifying and optimizing SNCR systems, $20/kW was a very
reasonable estimate. EPA's contractor also reviewed the SNCR algorithms
developed by Sargent & Lundy for EPA and is of the opinion that in most
cases $20/kW provides a better estimate than the IPM algorithm because
the IPM algorithm assumes greater economies of scale than generally
exist in SNCR applications.
---------------------------------------------------------------------------

    \161\ Email from Alex Dainoff, Fuel Tech, to James Staudt,
Andover Technology Partners, Wednesday, June 27, 2012.
---------------------------------------------------------------------------

    On the other hand, as will be described later in this response, the
high reported furnace temperature at Basin Electric's Laramie River
Station means that SNCR will require a more complex injection system
and will have a higher urea injection rate than what is typical for
most SNCR systems. For this reason EPA has accepted the capital cost of
SNCR estimate provided by Basin Electric. In any event, SNCR capital
cost generally has a small effect on cost compared to operating cost.
    Commenter is critical of EPA's use of the IPM algorithm as not
utilizing the same input design parameters. As described in other
responses to comments, the IPM algorithm for SCR incorporates either
directly or by inference all of the inputs the commenter has raised.
But, commenter is incorrect about some of the claimed inputs.
Stoichiometric ratio, space velocity, area velocity, catalyst volume,
SCR reactor volume, and reagent consumption are not inputs to an SCR
design, but are all direct results of design calculations using the
inputs of initial NOX level, final NOX level (and
by inference percent reduction), unit size, heat rate, and fuel
characteristics--all inputs to the IPM model. Gas flow rate is also
normally calculated based upon fuel type, unit size and heat rate--
again, IPM inputs. The IPM model therefore directly develops SCR
reactor cost based upon all of the same inputs, but using algorithms
based upon a database of the cost of actually constructed units. Other
costs, such as preproduction costs and initial inventory of ammonia are
incorporated into the capital costs. In any event, these are very small
portions of total cost. Initial catalyst cost is incorporated into the
direct capital costs of the project in the IPM estimate, and in any
event, initial catalyst cost is typically a very small portion of total
capital cost.
    Commenter is critical of EPA's treatment of the associated costs
for replacement catalyst. Regarding treatment of catalyst cost, EPA's
approach is reasonable, factoring in the NOX reduction,
coal, facility size, capacity factor, and catalyst cost--all of the
same factors that impact catalyst replacement cost. PacifiCorp, on the
other hand, uses excessive catalyst replacement costs. PacifiCorp's use
of $290/ft\3\ for replacement catalyst cost equates to $10,422/m\3\.
This is nearly double the current cost of new catalyst. The difference
cannot be accounted for in the labor to install catalyst, which is a
very small fraction of the catalyst cost.\162\ Moreover, replacement
catalyst is frequently regenerated catalyst which costs roughly half
the cost of new catalyst. EPA conservatively assumed new catalyst at
roughly $5,500/m\3\,\163\ when in fact most catalyst replenishments
will likely be at a much lower cost due to the extensive availability
of regenerated catalyst. As a result, EPA's catalyst costs are much
more reasonable and are in fact, conservative in light of the
availability of regenerated catalyst.
---------------------------------------------------------------------------

    \162\ From data in Cichanowicz, J., Muzio, L., Hein, M., ``The
First 100 GW of SCR in the U.S.,--What Have We Learned?''--2006 Mega
Symposium, page 4.
    \163\ Cichanowicz, J.E., ``Current Capital Cost and Cost-
Effectiveness of Power Plant Emissions Control Technologies''
Prepared for, Utility Air Regulatory Group, January 2010.
---------------------------------------------------------------------------

    Commenters are critical of EPA's estimates of SNCR reagent
consumption. Because of the importance of reagent consumption on SNCR
system capital and operating cost, chemical utilization is an important
factor. Utilization is a measure of how efficiently the SNCR reagent
reduces NOX. With SNCR, NOX reduction does not
occur on a one-for-one basis as reagent is added because a portion of
the chemical introduced does not contribute to NOX
reduction. The utilization of reagent (normally urea) declines as
temperature (or carbon monoxide concentration) increases because more
of the urea becomes oxidized (forming NOX), which reduces
the amount of reagent available for the NOX reduction
reaction. The net difference between the amount of NOX
reduced and the amount of NOX formed equals the overall
reduction in NOX, and at a sufficiently high temperature,
NOX can actually increase as urea is injected. Hence,
furnace temperature is

a critical parameter in determining utilization.
    Chemical utilization is equal to the percent NOX
reduction divided by the treatment rate, expressed in terms of
Normalized Stoichiometric Ratio. The IPM model assumes a default
chemical utilization rate of 15%. Commenter states that Andover
adjusted the urea utilization rate in the IPM model without
explanation. On the contrary, on page 3 of its memo, Andover provided
actual utility data and explained why 25% was a more common utilization
rate for utility boilers. Chemical utilization is a strong function of
furnace temperature, and because chemical consumption is the single
largest expense associated with SNCR, using an incorrect chemical
utilization will lead to large discrepancies in cost.
    Commenter states that the furnace exit gas temperature is
2710[emsp14][deg]F. While EPA suspects that this may be in error
(high), it is the data provided by the company. If this temperature is
correct, SNCR may only be marginally effective. Sargent & Lundy
estimated a chemical utilization of 12%, which is possibly optimistic.
Information from Fuel Tech, the leading supplier of SNCR technology,
stated that at the unusually high furnace exit temperature of
2500[emsp14][deg]F, well below 2710[emsp14][deg]F assumed by Sargent &
Lundy, a 25% reduction was possible at a particular facility from a
similar NOX baseline with a Normalized Stoichiometric Ratio
of 1.75 (utilization of 14.3%). Hence, EPA will accept the 12%
utilization and 20% NOX reduction assumed by Sargent & Lundy
for Laramie River Station.\164\
---------------------------------------------------------------------------

    \164\ Email from Alexander Dainoff to Jim Staudt, June 27, 2012.
---------------------------------------------------------------------------

    The model in the IPM, which was developed by Sargent & Lundy,
assumes a utilization rate of 15%, which Andover's data, as well as
Fuel Tech's input, demonstrates is too low for most facilities. It is
therefore a very conservative estimate of chemical utilization. In
fact, Andover reviewed Sargent & Lundy's model when it was developed
for EPA and Sargent & Lundy did not provide any supporting data
regarding the assumed utilization rate at that time. However, in light
of the high assumed furnace temperature at Laramie River Station, EPA
is assuming a 12% chemical utilization at a 20% NOX removal
rate for those units.\165\
---------------------------------------------------------------------------

    \165\ Exhibit 16 to Basin Electric comment, page 25.
---------------------------------------------------------------------------

    On the other hand, in the October 28, 2013 memo by Andover for EPA,
test data for utility boilers was provided showing that 25% is a more
reasonable utilization rate for most units. Moreover, Andover's
principal has conducted numerous electric utility SNCR optimization
programs, among them are programs described in referenced papers, which
makes him qualified to make this determination.166 167 168
So, in applications where more typical furnace temperatures are
expected, a chemical utilization rate closer to 25% can be reasonably
assumed.
---------------------------------------------------------------------------

    \166\ Staudt, J., Casill, R., Tsai, T., Ariagno, L.,
``Commercial Application of Urea SNCR for NOX RACT
Compliance on a 112 MWe Pulverized Coal Boiler'', 1995 EPRI/EPA
Joint Symposium on Stationary Combustion NOX Control,
Kansas City, May 16-19, 1995.
    \167\ Staudt, J, Hoover, B., Trautner, P., McCool, S., Frey, J.,
``Optimization of Constellation Energy's SNCR System at Crane Units
1 and 2 Using Continuous Ammonia Measurement'', The MEGA Symposium,
Baltimore, MD, August 31-September 2, 2010.
    \168\ Staudt, J.E., Kehrer, K., Poczynec, J., Cote, R., Pierce,
R., Afonso, R., and Sload, A., ``Optimizing Selective Non-Catalytic
Reduction Systems for Cost-Effective Operation on Coal-Fired
Electric Utility Boilers'', presented at ICAC Forum '98, Durham,
March 1998.
---------------------------------------------------------------------------

    It is also likely that, in light of the higher furnace exit