temperature at Laramie River Station, it will be necessary to utilize a
more complex and costly injection system that requires injection of
urea into convective regions of the furnace using multiple-nozzle
lances in addition to the more typical wall injectors. For this reason,
EPA is accepting the capital cost developed by Sargent & Lundy for
Basin Electric of $16.9 million per unit.
    Regarding the reagent used for SCR, as the commenter points out,
EPA's initial estimates assumed that urea would be used as the feed
reagent for SCR, which results in a higher reagent cost than for
anhydrous ammonia. Because commenters have indicated that anhydrous
ammonia will be used as a reagent rather than urea, EPA's revised
estimates assume ammonia as a reagent. This will result in lower
reagent costs. EPA is also using anhydrous ammonia costs provided by
Potash Corporation instead of the value provided by the utility.\169\
The cost used by EPA represents the actual delivered cost of anhydrous
ammonia, as quoted by a major reagent supplier.
---------------------------------------------------------------------------

    \169\ Email from Potash Corporation to Andover Technology
Partners, September 27, 2013.
---------------------------------------------------------------------------

    Basin Electric provided a site-specific estimate. EPA generally
supports the use of vendor quotes and site-specific estimates but only
as used within the parameters of the overnight cost methodology and the
CCM. The BART Guidelines, are clear that ``[y]ou 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.'' \170\ When supporting
documentation to site estimates are not provided, assumptions based
upon these cannot be considered.
---------------------------------------------------------------------------

    \170\ 70 FR 39166, footnote 15.
---------------------------------------------------------------------------

    Much of the documentation owners cite to support additional costs
were not provided to us. For instance, although Basin Electric provided
a table that listed their cost line items, this spreadsheet (in pdf
format), over 600 lines in length (and including line items such as
4 gravel surfacing and chain link fence), was stripped of
all cell calculations, preventing any meaningful review.
    There was also inadequate explanation for how man-hour rates were
developed. For example, current union boilermaker rates for Lodge 101
(Denver) range from $57.62 per hour for a Journeyman to $60.12 per hour
for a Foreman, with apprentices at lower rates.\171\ The CLRC reports
similar union boilermaker rates in the Mountain-Northern Plains area at
$56.59/hr for July 2013.\172\ For non-union boilermakers, the cost is
expected to be less. Yet, for tasks that appear to be for boilermakers
(ductwork) rates of $90.79 per man-hour are used.\173\ This is a large
unexplained difference in cost. It may be that part of it is per diem
($55/day for over 70 miles and $70/day for over 120 miles per Lodge 101
information), but per diem does not explain the full difference. Per
diem, however, is also provided as a separate cost later in the
estimate, making the high labor rate more difficult to explain. Some
portion may be for overtime, but there is no explanation provided
(overtime is also added as a separate line item later in the estimate).
Without an explanation it is not possible to evaluate these costs,
which clearly deviate from publicly available costs for labor. In
addition to not providing the necessary required supporting
documentation, Basin Electric did not follow the overnight cost
methodology. Thus, Basin Electric has failed to meet the test that is
required to support deviations from the CCM.
---------------------------------------------------------------------------

    \171\ Wage & Benefit Information, Western States Field
Constructions Bargaining Agreement, Effective January 1, 2013
through September 31, 2013.
    \172\ Construction Labor Research Council Union Wages and
Supplements for the Period 07/01/2008-07/01/2013. Available from the
National Association of Construction Boilermaker Employers Web site:
www.nacbe.org.
    \173\ Appendices to Exhibit 14. Page 6 of SCR estimate (pdf page
43).

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

    Comment: The IPM methodology relied upon in the Andover Report is
inconsistent with the BART Guidelines. The Guidelines require that to
conduct a cost analysis, a state must ``[i]dentify parameters'' for
emission control and then ``[d]evelop cost estimates based upon those
design parameters.'' 70 FR 39166. The cost analysis includes
development of ``estimates of capital and annual costs,'' based on the
CCM ``where possible,'' but ``tak[ing] into account any site-specific
design or other conditions identified above that affect the cost of a
particular BART technology option.'' Id. Andover failed to adhere to
the methodology set forth in the CCM ``where possible.'' More
importantly, however, Andover neither followed the three-step process
in the BART Guidelines for estimating costs of compliance nor
appropriately considered the critical site- and project-specific
variables that affect the cost of both SCR and SNCR at Laramie River.
EPA's failure to comply with its own Guidelines results in an
inaccurate cost estimate that should not form the basis of a BART
determination.
    Response: EPA disagrees with the commenter. The three step process
was followed for all cost estimates for affected Wyoming units. The
three-step process requires that states (or EPA): (1) Identify the
emissions units being controlled; (2) Identify design parameters for
emission controls; and (3) Develop cost estimates based upon those
design parameters. The BART affected units were already identified by
the State and confirmed by EPA, which addresses step one.
    Andover clearly identified design parameters that are included in
the spreadsheets associated with the memo under the tab ``Plant Data
Summary''. This includes plant data such as fuel, capacity, capacity
factor, heat rate, baseline and controlled NOX level,
retrofit factor and firing configuration. These parameters are directly
used in the cost analysis that developed capital and annual costs.
Andover performed the cost estimates as described in the spreadsheet.
Andover considered site and project-specific parameters as described in
other responses to comments.
    Commenters may disagree with the cost methodology used by EPA, and
our response to comments regarding the cost methodology used is in
other responses; however, there is no question that EPA followed the
three-step process.
    Comment: The IPM methodology relied upon in the Andover Report is
inconsistent with the three-step process in the BART Guidelines for
estimating costs of compliance. The three-step process in the BART
Guidelines requires: (1) Identification of emission units being
controlled; (2) identification of design parameters for emission
controls; and (3) development of cost estimates based on those design
parameters. 70 FR 39166. The Andover Report did not adequately define
the emission units being controlled, failed to identify appropriate
site-specific design parameters that affect cost and performance of
these controls; and developed cost estimates that are neither
technically indefensible nor representative of the costs of SCR and
SNCR systems at Laramie River.
    Andover's reliance on the overly simplistic IPM model precluded an
appropriate BART analysis. First, because the IPM cost algorithms are
designed to provide high-level system cost, Andover used generalized
information regarding design and baseline operating conditions at the
Laramie River boilers to identify the emission units to be controlled.
Second, because the IPM model includes only four inputs, Andover's cost
analysis could not account for unit-specific operating parameters that
affect both design of the control system and the attendant costs of
installing the controls.
    As a result, the Andover Report failed to comply with the
requirement in the BART Guidelines that cost estimates account for
site-specific variables. 70 FR 39166. The site-specific design and
operational variables have an important effect on the costs of
NOX control technologies at Laramie River, particularly the
installation of SCR. Finally, because Andover used generic inputs to an
overly simplistic model, the resulting cost estimate is not technically
defensible. As Sargent & Lundy opined ``[b]ased on our evaluation of
the Andover cost estimates, it is our opinion that cost estimates
prepared by Andover are not reflective of the costs BEPC would incur to
install air pollution control systems on LRS Units 1, 2, & 3, and that
control technology costs included in the February 7, 2013 Andover
Report should not be used to determine BART for the Laramie River
generating units.''
    Response: EPA disagrees with the commenter. The three step process
requires that states (or EPA): (1) Identify the emissions units being
controlled; (2) Identify design parameters for emission controls; and
(3) Develop cost estimates based upon those design parameters.
    Commenter states that ``The Andover Report did not adequately
define the emission units being controlled, failed to identify
appropriate site-specific design parameters that affect cost and
performance of these controls; and developed cost estimates that are
neither technically indefensible nor representative of the costs of SCR
and SNCR systems at LRS.'' However, the BART affected units were
clearly identified and defined in the analysis. The units are
identified and described in the memo and the associated spreadsheets.
    EPA's contractor clearly identified design parameters that are
included in the spreadsheet associated with the memo under the tab
``Plant Data Summary''. This includes plant data such as fuel,
capacity, capacity factor, heat rate, baseline and controlled
NOX level, retrofit factor and firing configuration. These
parameters are directly used in the cost analysis that developed
capital and annual costs. This is the very same data as used by Sargent
& Lundy in their analysis, except that EPA did not correct for
elevation, which EPA is correcting in this response to comments and
calculations.
    Andover then performed the cost estimates as described in the
spreadsheet using algorithms developed by Sargent & Lundy that utilize
the same inputs as used by Sargent & Lundy in their analysis for
commenters. Other than a site visit and an adjustment for elevation,
commenters have not identified any other inputs that they used that are
different or not the direct result of the inputs utilized by EPA. With
this response to comments EPA is correcting cost estimates for
elevation and EPA has provided detailed comments regarding how site
characteristics were addressed using available satellite imagery and
why this is a valid approach for providing estimates that are
acceptable for BART analysis.
    We disagree with commenter's characterization of the cost
development methodology contained in IPM as generalized. As noted in
the documentation for IPM's cost development methodology for SCR,\174\
the cost estimate methodology is based upon two databases of actual SCR
projects. These databases include 2004 and 2006 industry cost estimates
prepared for the Midwestern Ozone Group, and a proprietary in-house
database maintained by 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
our use of satellite imagery would potentially produce a more refined
cost estimate, we disagree that our approach has produced cost
estimates that do not adequately address site-specific issues. As noted
by EPA in our responses related to satellite imagery, EPA's use of
satellite imagery enabled us to evaluate each of the major site-
specific issues raised by commenters.
---------------------------------------------------------------------------

    \174\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix52A.pdf.
---------------------------------------------------------------------------

    Comment: The Andover Report fails to consider site-specific
conditions as required by the BART Guidelines. The BART Guidelines and
the CCM emphasize the importance of taking into account site-specific
conditions in developing a cost estimate, particularly with respect to
construction of SCR. 70 FR 39166 (cost estimates should ``into account
any site-specific design or other conditions . . .''). See also CCM
section 2.4, page 2-40 (with respect to SCR, ``[a]ctual selection of
the most cost-effective option should be based on a detailed
engineering study and cost quotations from system suppliers.''); id.
section <IP_ADDRESS>, page 2-27 (``Manual deviates from its standard
approach of providing study level costs [for SCR] and, instead,
provides a detailed description of the factors'' influencing costs).
Yet as Andover acknowledges in its report, its engineers did not visit
Laramie River and had no engineering plans, process flow diagrams, or
other site-specific information regarding Laramie River when it
developed EPA's cost estimate. The only information Andover collected
regarding the site was the generating capacity of the station, annual
heat input for a baseline period, NOX emission rates for
certain years, and the type of coal burned. As a result, Andover's cost
estimation methodology fails to comply with the BART Guidelines or
follow the methodology recommended by the CCM, and the final estimate
radically underestimates the cost for SCR and SNCR at Laramie River
Station.
    Moreover, Andover's use of the IPM model compounded its failure to
review site-specific considerations relevant to costing SCR or SNCR at
Laramie River Station. Indeed, the fact that the model has only four
input parameters, and does not take into account other site-specific
parameters that are required by the BART Guidelines and recommended by
the CCM, renders any resulting cost estimate both technically and
legally deficient. As noted by Sargent & Lundy, which developed the IPM
algorithms for SCR and SNCR, ``[b]ecause of the limited number of site-
specific inputs, the IPM cost algorithms provide only order-of-
magnitude control system costs, and do not provide case-by-case
project-specific cost estimates meeting the requirements of the BART
Guidelines.''
    By relying on the IPM model, Andover deliberately skirted the issue
of site-specific conditions, other than the most generic inputs of unit
size, heat rate, coal type, and a retrofit factor. The Andover Report
describes the retrofit factor in such a way as to emphasize its site-
specific nature, and yet makes no attempt to carefully analyze the
site-specific variables inherent in the application of the retrofit
factor: ``The retrofit factor is a subjective factor used to account
for estimated difficulty of the retrofit that is unique to the
facility. Because site visits were not possible, the retrofit factor
was estimated from satellite images that provide some insight to the
configuration of the units and degree of congestion around the site and
in the vicinity of where the SCR would be installed. These factors
impact the ability to locate large cranes on the site--that impact how
the SCR is assembled (are large sections lifted into place or is the
SCR ``stick built''), how much duct work is needed, if the SCR must be
built onto a large, elevated steel structure or can be built near the
ground, and if other equipment must be relocated to accommodate the
space of the SCR.''
    The Andover Report never provides any analysis of these site-
specific factors in determining the appropriate retrofit factor for
Laramie River. Andover merely notes that the difficulties of
retrofitting an SCR unit at Units 1 and 3 is ``average,'' and applies a
retrofit factor of 1.0 to Units 1 and 3. Andover does note that
retrofit at Unit 2 will be more difficult and added an adjustment for
retrofit difficulties at Unit 2, but with no explanation of what unique
site-specific conditions contributed to the factor. Instead, the report
notes ``a modestly higher SCR retrofit difficulty factor is assumed for
Unit 2 because access will be poorer than for Units 1 or 3.'' In sum,
Andover makes no adjustments for Units 1 or 3 and accords a 20% cost
retrofit factor to Unit 2, though it had previously noted that ``when
using the IPM Capital Cost Model, retrofit difficulties associated with
an SCR may result in capital cost increases of 30% to 50% over the base
model.'' Thus, even when it accords a retrofit factor, as it did for
Unit 2, Andover inexplicably low balls that retrofit factor and the
attendant cost increase for the SCR system. When Andover's retrofit
factors are compared across units and across facilities, it appears
that Andover arbitrarily assigned the retrofit factors without
adequately accounting for site congestion and constructability issues.
Subjective retrofit factors, especially factors randomly chosen without
knowledge of site conditions, cannot account for site-specific
circumstances as provided in the BART Guidelines.
    A comparison of the broad brush approach taken by Andover with the
detailed, site specific, scoping-level study taken in the Sargent &
Lundy evaluation illustrates the inadequacies with Andover's
methodology. As an initial matter, Andover made a fundamental error by
failing to account for the effect of site elevation on the project
costs. Laramie River Station is situated at 4,750 feet above sea level,
resulting in flue gas volumes approximately 20% greater than a
similarly sized unit at sea level. These larger flue gas volumes will
require larger SCR reactors, larger duct work, and increased structural
support. None of these additional costs are accounted for in Andover's
estimate because the IPM model assumes the plant is located at sea
level. Indeed, IPM model guidance provides that ``elevation of the site
must be considered separately and factored into the MW size accordingly
due to its effects on the flue gas volume.'' Id. (citing the IPM SCR
Cost Development Document (August 2010)).
    Andover's reliance on the IPM model also resulted in failure to
account for a regional labor productivity factor. Regional productivity
must be taken into consideration in a site-specific cost estimate to
account for local workforce characteristics, labor availability,
project location, project complexity, local climate and working
conditions. This is a key factor for Laramie River Station, because
experienced, knowledgeable labor is difficult to acquire and requires
premium pay, further adding to the cost of an SCR system.
    The most substantial failing of the Andover Report, however, is its
reliance on an aerial photograph of the plant from Google
EarthTM to account for site-specific conditions at Laramie
River Station. There are numerous important elements that cannot be
discerned from an aerial photograph. Specifically, a Google
EarthTM photograph cannot identify: (1) The site constraints
posed by the location of the coal conveyor rooms; (2) the location of
the existing fan buildings and the space constraints between the
existing fan buildings and the existing electrostatic precipitators;
(3) the necessary information to determine duct work routing and SCR
tie-ins to the existing economizers and

air heaters; and (4) information regarding plant subsystems such as the
fan capacity, equipment reinforcement, auxiliary power systems,
electrical plant system capacity, and other plant subsystems that would
be affected by installation and operation of the SCR systems. Further,
the aerial photograph provides no information about where the ammonia
handling system could be located and necessary pipe routing and other
support systems for the ammonia handling system. Nor does it show the
need to penetrate the 20-story boiler wall and provide related
structural support to install duct work, to provide structural support
columns for the SCR reactors in very tight spaces, and the need for
special cranes to lift heavy equipment into place in a congested space.
    While Andover indicated that some of these site-specific issues are
addressed by the retrofit factor, the fact that Andover accorded no
retrofit factor to Laramie River Station Units 1 and 3, and low balled
the retrofit factor for Unit 2, resulted in a failure to include site-
specific costs in its estimate for the Laramie River, in direct
contravention of the requirements of the BART Guidelines and
suggestions of the CCM. Site-specific conditions are illustrated in
Section <IP_ADDRESS> of the Sargent & Lundy Critique. Finally, Andover
failed to include costs for the balance of plant systems required for
the SCR. Sargent & Lundy Critique section <IP_ADDRESS>. These items, which
require enlarging existing plant systems to provide for the additional
power and airflow and other systems necessary to operate the SCRs,
include the following: (1) Replacement of induced draft fans by larger
fans to support the SCR units; (2) Upgrading of the existing electrical
system to support the SCR units; (3) Structural stiffening of the duct
work downstream of the SCRs; and (4) Expand existing control system to
accommodate six new SCRs (two for each generating unit).
    Wyoming used actual, site-specific data regarding the BART-eligible
sources in development of its plan. In contrast, EPA did not use site-
specific data; instead, it relied on nothing more than aerial
photographs available in the public domain.
    Response: EPA disagrees with the commenter. First, as discussed
elsewhere in responses, we are no longer relying on the IPM cost
algorithms, including the application of retrofit factors, to estimate
capital costs for the Laramie River Station units. Instead, we have
evaluated the cost information provided by Basin Electric in comments
and incorporated it as appropriate. Therefore, the arguments made by
the commenter related to our use of the IPM algorithm are no longer
relevant. Nonetheless, below we discuss how our use of the IPM
algorithm in the proposed rule was based on reason and evidence and
addressed the site-specific concerns raised by the commenter.
    As noted in responses to other comments, EPA adequately addressed
site-specific issues in using the IPM SCR cost model. The SCR cost
model for IPM, being developed from actual SCR retrofit data,
incorporate all of the costs that would normally be associated with an
SCR retrofit. As such, retrofit issues that are common to all SCR
retrofits are incorporated into the cost. To the extent that there are
additional costs, as described in other comments, these can be
addressed with the retrofit difficulty factor.
    Basin Electric did not follow the BART guidelines in developing
their cost analyses, and importantly, did not provide adequate
documentation when they deviated from it. There are only very limited
situations under which an analyst can depart from the CCM methodology
under the BART Guidelines: ``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.
    This section of the BART Guidelines makes 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. Importantly, a
footnote at the bottom of the same page of the BART Guidelines makes it
clear that the analyses 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.''
    The record does not point to any ``unusual circumstance'' that
explains why Basin Electric's SCR costs are higher than costs of SCRs
at other similar facilities, other than the use of a different cost
methodology. In fact, there is nothing in the record to support claims
that the cost of SCR was in fact based on detailed site-specific vendor
bids, or is in any manner more site-specific than the costs relied upon
by EPA in our proposed rule. As an example, the BART application
submitted by Basin Electric, and relied upon by Wyoming, shows that
only the cost of catalyst is based on a vendor quote.\175\ There is no
documentation to substantiate that the remaining costs are based on
vendor quotes or any other site-specific data. The mere fact that the
cost analysis was submitted by Basin Electric is not a basis to
conclude that it is somehow highly site-specific. Indeed, even the
updated cost information recently submitted by Basin Electric during
the comment period is conceptual in nature and not based on vendor
quotes. As stated on page 21 of Exhibit 14 to their comments: ``The 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.''
---------------------------------------------------------------------------

    \175\ Wyoming Regional Haze SIP, Attachment A, ``Basin Electric
Power Cooperative Laramie River Station Refined BART Visibility
Modeling'', prepared for Basin Electric Power Cooperative by Black &
Veatch Corporation, July 24, 2008, Attachment 1, page 7 of 7.
---------------------------------------------------------------------------

    Commenter correctly notes that EPA did not account for elevation.
EPA acknowledges that it did not account for elevation in the estimate
when using the IPM algorithm and EPA's revised estimate does account
for elevation. Commenter states that the regional labor productivity
was not factored into EPA's estimate. EPA's estimate did provide an
allowance for overtime which is a line item in the estimate labeled
``Labor Adjustment.'' However, commenter did not provide sufficient
information to evaluate commenter's estimate and how productivity
factors were developed or applied in their estimate to produce their
estimate. Labor costs comprise roughly half of the total cost of Basin
Electric's estimate of what SCR would cost to install at Laramie River
Station, and the significance of this cost makes the lack of
information very important.

Moreover, if this is an important element of commenter's critique of
EPA's method, they should have provided sufficient data and supporting
justifications for EPA to evaluate commenter's estimate. Notably, this
is an important deviation from the CCM and more detailed supporting
data should have been provided. As noted in EPA's responses to other
comments, the commenter has not provided any data to explain the high
labor charge rates or claimed low productivity, as required under the
BART Guidelines.
    Commenter claims that ``a Google Earth\TM\ photograph cannot
identify: (1) The site constraints posed by the location of the coal
conveyor rooms''. On the contrary, the coal conveyors are prominent
features in the images \176\ and it is clear from the coal conveyors
where the coal conveyor rooms are located. This location for coal
conveyor rooms is not unusual. In general, coal conveyor rooms are
located either to one side of the boiler or the other, depending upon
the location of the coal pile to the boiler. Moreover, the resulting
need to route ductwork through the boiler building wall is commonly
performed in SCR retrofits. As such, this is not an unusual issue and
should not significantly impact retrofit cost versus a typical
retrofit.
---------------------------------------------------------------------------

    \176\ Review of Estimated Compliance Costs for Wyoming Electric
Generating (EGUs)--Revision of Previous Memo, memo from Jim Staudt,
Andover Technology Partners, to Doug Grano, EC/R, Inc., February 7,
2013, Figures 6a and 6b.
---------------------------------------------------------------------------

    Commenter claims that EPA did not account for ``(2) the location of
the existing FD fan buildings and the space constraints between the
existing FD fan buildings and the existing electrostatic precipitators
. . .'' It is clear from the images that there is a building located
immediately below where the SCR reactor would be located, and this is
not an unusual situation. The location of the ESP is also very clearly
shown on the images. The space between the ESP and the fan rooms is
also visible from the photo in Figure 6a of the Andover memo.
Nevertheless, having to install SCR support structure in close
proximity to existing buildings or equipment, as may be necessary at
Laramie River, is not unusual because SCRs are commonly erected in that
location and buildings or other equipment are normally in the area
below. It is also possible that SCR support structure could be built to
largely avoid the forced draft fan buildings by extending beyond them
with a common support structure for all three, or at least more than
one, SCR reactor. The space between the ESP and the fan buildings is
only significant with regard to location of a crane for erection of
Unit 2, and this is why a higher retrofit difficulty is assumed for
Unit 2. Middle unit crane access issues are not unusual either and have
been addressed numerous ways, including assembling a temporary crane
above the boiler building, as was performed at the Brayton Point plant
for their Unit 3.
    Commenter claims that EPA did not adequately account for ``(3) the
necessary information to determine duct work routing and SCR tie-ins to
the existing economizers and air heaters . . .'' EPA disagrees with the
commenter. The general routing can be estimated from the images, and
there was nothing in the images to suggest any problems with routing
ductwork. It was apparent that a penetration was necessary in the
boiler building, which is routinely necessary because boilers are
typically housed in boiler buildings and the SCRs are not, making
penetration of a boiler building wall necessary in any SCR retrofits
where the boiler is in a boiler building. This is the case with most
SCR retrofits. In fact, Figures 2 and 3 of Exhibit 16 to Basin
Electric's comments demonstrate that the ductwork tie in to the boiler
and associated modifications are similar to what is done routinely and
ductwork length is reasonable. For an SCR cost estimate, the most
critical cost issues that require closer examination than possible with
a satellite photo is if it is necessary to move major pieces of
equipment, such as an air preheater, in order to accommodate the
ductwork. Had it been determined that relocating the air preheater was
necessary, this would entail some significant additional cost over what
would be considered a ``typical'' retrofit. Basin Electric did not
indicate any such need and therefore their costs for ductwork are
expected to be within the normal cost for a retrofit.
    Commenter claims that EPA did not properly account for ``(4)
information regarding plant subsystems such as the FD fan capacity,
equipment reinforcement, auxiliary power systems, electrical plant
system capacity, and other plant subsystems that would be affected by
installation and operation of the SCR systems. Sargent & Lundy Critique
section <IP_ADDRESS>.-<IP_ADDRESS>.'' The IPM algorithm explicitly assumes that
it will be necessary to replace the forced draft (FD) fan \177\ and
make modifications to auxiliary electrical systems and associated
boiler structure and has a line item cost for this. As such this was
addressed in the cost.
---------------------------------------------------------------------------

    \177\ Sargent & Lundy, ``IPM Model--Revisions to Cost and
Performance for APC Technologies--SCR Cost Development Methodology,
FINAL'', August 2010.
---------------------------------------------------------------------------

    Commenter claims that ``Further, the aerial photograph provides no
information about where the ammonia handling system could be located,
and necessary pipe routing and other support systems for the ammonia
handling system. Nor does it show the need to penetrate the 20-story
boiler wall and provide related structural support to install duct
work, to provide structural support columns for the SCR reactors in
very tight spaces, and the need for special cranes to lift heavy
equipment into place in a congested space.'' EPA disagrees. It is
apparent from the image, and the open spaces on the images that have no
structures, that there are any of a number of places at the Laramie
River site that the ammonia storage system could be located. Selecting
the ideal location does require closer examination of the site than
possible with an aerial photograph. However, the impact on total
capital cost is relatively small. With regard to modifications to the
boiler building, this has already been discussed along with the
installation of structural support columns for the SCR and need for
cranes. These modifications are routinely necessary for SCR retrofits
and would be factored into the historical SCR projects that the IPM
algorithms are based upon.
    Expansion of the controls is another cost identified by commenters
as not adequately addressed by EPA. EPA disagrees with commenter. Every
SCR retrofit requires expansion of controls. So, this is incorporated
into the IPM model. There may be specific issues that may be associated
with tailoring the controls to the existing site that make this portion
of the cost slightly more or slightly less expensive than normal. But,
controls are generally a small contributor to total SCR cost and these
differences would have a minor effect.
    Comment: When all of the site-specific and balance of plant
conditions are included, Sargent & Lundy estimated that the capital
cost of installing SCR at Laramie River Station is $746,906,000. This
is twice as much as Andover's flawed cost estimate of $330,000,000. The
discrepancy in the cost estimates is not surprising in light of
Andover's failure to comply with the BART Guidelines and to follow the
CCM where appropriate. For example, the site congestion and balance-of-
plant upgrades alone total approximately $290 million--costs which
accurately reflect site-specific constraints to installing SCR, but
which were not accounted for in the Andover Report. While the costs
estimated in the Sargent

& Lundy Evaluation are significantly greater than those set forth in
the Andover Report, they are a far more accurate and representative
assessment of the costs of installing SCR and SNCR at Laramie River
Station.
    Response: EPA disagrees with the commenter, having found the
following discrepancies in the commenter's estimates for cost of SCR
and SNCR at Laramie River Station:
1. Apparently Double-Counts General Facilities
    The itemized cost estimate in the Appendices to Exhibit 14 includes
items that are normally incorporated into the General Facilities cost,
while Sargent & Lundy took an additional provision for General
Facilities (Exhibit 14 at page 31). General Facilities are costs that
are not directly associated with the process equipment, and include
such things as access roads, access platforms, safety equipment (such
as eye-wash stations), etc. On the other hand, ductwork, piping,
structural steel to support process equipment are direct capital cost
and do not fall into the category of General Facilities. The itemized
cost estimate by Sargent & Lundy in the Appendices to Exhibit 14,
however, includes the cost of many items that would normally fall under
the category of General Facilities. This includes the cost of roads and
a parking area ($930,226 at page 2 of SCR estimate), eye wash stations
(page 3), a pre-engineered building for the construction warehouse
($780,000 page 8), fire protection systems (page 16), gratings,
handrails, ladders (page 22). As a result, Sargent & Lundy double
counts for General Facilities by having these costs accounted for in
the itemized direct capital cost as well as in its Indirect Capital
costs.
2. Labor Rates in Sargent & Lundy's Itemized Capital Cost in the
Appendices to Exhibit 14 Appear To Already Have a Significant
Contingency Built in and Additional Costs for Overtime and Per Diem--
Already Incorporating Contingency in Apparent Double-Counting of
Contingency
    According to Basin Electric's comments, their labor rates were
taken from the publication RS Means.\178\ However, examples of how the
labor rates from RS Means were used to develop what was ultimately used
in their estimate were not provided. RS Means is a subscription service
that can cost up to $1,100, depending upon the package.
---------------------------------------------------------------------------

    \178\ Exhibit 14, page 25.
---------------------------------------------------------------------------

    However, there are publicly available labor rates for the major
construction trades from the CLRC that are available for download at
the National Association of Construction Boilermaker Employers' Web
site.\179\ The Laramie River Station estimate assumes boilermaker labor
tasks with a labor rate of $90.79/hr while according to the CLRC
boilermaker rates in the Mountain and Northwest Plains as of July 2013
were $56.79/hour, which is close to the values for Lodge 101 of the
boilermakers union, ranging from $57.62 for a Journeyman to $60.12 for
a Foreman, and lower rates for apprentices.
---------------------------------------------------------------------------

    \179\ Construction Labor Research Council Union Wages and
Supplements, available from the National Construction Boilermaker
Employers Web site, www.nacbe.com.
---------------------------------------------------------------------------

    The Laramie River estimate assumes pipefitter labor tasks with a
labor rate of $81.72/hour, while according to the CLRC pipefitter rates
in the Mountain and Northwest Plains as of July 2013 were $43.57/hour.
Plumber rates are only slightly higher are $47.47/hour. In fact, there
are several areas where the Laramie River itemized estimated rates in
the Appendices far exceed Mountain-Northern Plains reported rates for
union craft labor for July 2013. The ratio of assumed rate versus
reported is as high as 187%. It is only for the installation of an
architectural door that the reported rate for carpenters is even close
to the assumed rate for Laramie River Station. Carpenters also build
concrete forms.\180\ For carpenters doing concrete forms, the paid rate
($65.02--see page 2 of estimate) is more than double the union rate.
For most of these crafts, these rates cannot be explained by per diem.
For example, if all of the boilermakers lived 120 miles from the
location and were eligible for $70/day per diem and also drove 120
miles each way every day of an eight-hour shift receiving $0.565/mile,
that would only increase the hourly rate by $25.70, which does not
explain the $34+ difference.
---------------------------------------------------------------------------

    \180\ Bureau of Labor Statistics, 47-2031 Carpenters,
www.bls.gov/oes/current/oes472031.htm.
---------------------------------------------------------------------------

    It may be that Sargent & Lundy applied an escalation to the labor
charges for future expected rates. If so, this is inconsistent with the
CCM, which does not allow for this. In light of the fact that labor
comprises the single largest expense and is nearly half of the total
direct cost of the project--per Basin Electric's estimate in the
Appendices to Exhibit 14--the high labor rates assumed by Sargent &
Lundy are critical cost items that require much more complete
explanation than was provided.
3. Additional Labor Costs
    In addition to the high labor rates incorporated into Sargent &
Lundy's itemized estimate, roughly $47 million in additional labor
costs are included for five ten-hour days and six ten-hour days and per
diem.\181\ This schedule (which results in overtime) is stated to be
necessary to attract necessary labor.\182\ No further explanation is
provided for these costs. It is unclear why it is necessary to offer
these in light of the fact that power plant construction labor demand
is well off of its peak and is especially low in the Western States. As
a key power plant construction trade, boilermaker man-hours are a good
indication of general power plant construction activity. Boilermaker
man-hours demonstrate that labor demand is well off of past peaks, and
for the first two quarters of 2013, boilermaker employment in the
Western States is 18.6% below 2012 levels for the same period.
Boilermaker man-hours in 2012 nationally totaled 27 million, well off
the years of 2006 through 2009 that were all above 30 million, and
peaked in 2008 at over 40 million. 2012 levels were still below 2010's
rate of 28 million.\183\
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    \181\ Appendices to Exhibit 14 of Basin Electric comments, page
4 of SCR estimate.
    \182\ Exhibit 14, page 25.
    \183\ http://nacbe.com/manhour-reports/. Also see: Staudt, J.E.,
``Engineering and Economic Factors Affecting the Installation of
Control Technologies--An update'', Developed for U.S. EPA Clean Air
Markets Division, December 15, 2011, figure 2-2 on page 12.
---------------------------------------------------------------------------

    It is also unclear why such high expenses are needed for overtime
and per diem, particularly in light of the high assumed wage rates
discussed earlier. Moreover, the need for overtime needs to be
incorporated into a discussion of schedule, which was not provided. The
time available for installing the SCRs may allow for spreading of
activities over longer periods of time than in past retrofit efforts
that may have allowed less time than the RHR, which allows for five
years. However, there is no discussion of the need for overtime in the
context of schedule.
4. Quantity and Cost of Materials and Impact on Labor Hours
    Throughout the spreadsheets provided as Attachments to Exhibit 14
to Basin Electric's comments, no information was provided on how the
quantities of materials were estimated, such as tons of steel for
ductwork, etc. This makes it impossible to evaluate if Sargent & Lundy
estimated the correct quantities of materials, associated material
costs, or the associated hours

associated with erecting the materials. The spreadsheet was provided as
a pdf document, and therefore any underlying equations could not be
examined. As noted in our comments to other questions, it is necessary
to include documentation for any additional information used for the
cost calculations that differs from the CCM. Since the quantities of
materials also relate to the labor needed to install the materials,
this also impacts the labor costs estimated by Sargent & Lundy.
5. AFUDC
    Sargent and Lundy includes AFUDC in its SCR cost. This cost of
about $22-$23 million cost per unit, for a total of $68 million, is not
permissible under the CCM as discussed in response to other comments.
6. Process Contingency
    Although the CCM shows an allowable process contingency of 5% for
SCR, 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 NETL: \184\ ``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 this document, for
commercially available technologies process contingency could range
from 0-10%. 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,\185\ at the end of 2001, there was only about 13,000 MW of
coal SCR capacity in the U.S., with nearly all installed in the prior
two years, meaning that there was very limited long-term experience
with SCR on U.S. coals. SCR usage on coal-fired boilers has since
increased about ten times to about 130,000 MW of coal capacity (over
40% of all coal capacity) and is therefore a very well proven and well
understood technology on a wide range of U.S. coals. 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--5%. EPA believes that for SCR applications on utility boilers
burning Powder River Basin coals, which are very well understood SCR
applications, there should not be a need for process contingency.
---------------------------------------------------------------------------

    \184\ 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.
    \185\ 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.
---------------------------------------------------------------------------

7. Sulfur Trioxide (SO3) Mitigation Measures Are Not Needed
    Sargent & Lundy assumed that a SO3 mitigation system is
necessary for the Laramie River SCR. We disagree as this adds
unnecessary capital and operating cost. An SO3 mitigation
system is unnecessary because of the relatively low sulfur content of
the coal and the fact that the coal fly ash is high in free calcium
oxide. The available free lime will neutralize the SO3
making SO3 mitigation unnecessary. In fact, in the model
they developed for the IPM, Sargent & Lundy assumed that SO3
mitigation was unnecessary for boilers using coals with SO2
levels below 3 lb/MMBtu, making it unnecessary for Laramie River, which
fires a much lower sulfur coal from the Dry Fork Mine, with an
uncontrolled SO2 rate of roughly 0.50 to 1.0 lb/
MMBtu.186 187 188 In fact, Sargent & Lundy uses the same
rationale for arguing (correctly) that air preheater modifications are
not necessary to address potential ammonium bisulfate formation from an
SNCR system.\189\ Moreover, even if SO3 formation were a
legitimate concern, low oxidation SCR catalysts are available and any
additional cost impact would be very small. SO3 mitigation
is not a large capital cost compared to the other costs that contribute
to the SCR, but it is illustrative of the manner in which Sargent &
Lundy has taken efforts to overdesign the system while adding
unnecessary costs.
---------------------------------------------------------------------------

    \186\ Sargent & Lundy, ``IPM Model--Revisions to Cost and
Performance for APC Technologies--SCR Cost Development Methodology,
FINAL'', August 2010, page 5.
    \187\ http://www.westernfuels.org/member-services/mining-operations
    \188\ BNSF Mine Guide, at www.bnsf.com/customers/pdf/mineguide.pdf. SO2 calculated by multiplying sulfur
content (expressed as a decimal) times 2 million and dividing by the
heating value in Btu/lb.
    \189\ Exhibit 14, page 17.
---------------------------------------------------------------------------

8. Labor Productivity Factor Apparently Not Site-Specific
    Basin Electric has commented that local labor productivity is a
major factor that impacts cost. However, it appears that the labor
productivity factor being selected at the site may have been broadly
applied by Sargent & Lundy at multiple sites in an inconsistent manner.
According to Basin Electric, ``Labor productivity accounts for things
such as labor availability, site access and working conditions,
climate, season changes, and project size and complexity'' and it is a
common practice on large construction projects to apply a productivity
factor to account for local worker productivity and construction site
conditions. A labor productivity factor of 1.15 was selected to account
for labor productivity in the southeastern Wyoming region as compared
to the benchmark of 1.00 for Texas, cited in Basin Electric's comments.
Although the comments refer to the Compass International Global
Construction Cost and Reference Yearbook, the value in that document
for the southeastern Wyoming region is not expressly stated, and it is
unclear if 1.15 is, in fact, the value in that document as we were not
able to confirm the number in the document referenced.\190\
---------------------------------------------------------------------------

    \190\ Exhibit 14, page 25.
---------------------------------------------------------------------------

    In another Sargent & Lundy BART analysis, performed for Oklahoma
Gas & Electric Sooner Units 1 & 2 and Muskogee Units 4 & 5, Sargent &
Lundy also used a Labor Productivity factor of 1.15.\191\ Since the
Oklahoma Gas & Electric units are in a climate far more similar to
Texas (only about 150 miles from Texas) than Wyoming, and the Oklahoma
plant likely draws from similar construction labor pools as Texas, it
seems that they should have a similar productivity factor as Texas. It
is also unusual that Sargent & Lundy would select the exact same
productivity factor for the Oklahoma BART analysis as Laramie River
Station's BART analysis, although these facilities are roughly six
hundred to seven hundred miles away, with very different climates and
draw on different labor pools. In this case, it appears that Sargent &
Lundy has used the same productivity factor for Laramie River Station
as for other BART analyses. In summary, there is no evidence that the
labor productivity factors suggested by the commenter are site-
specific.
---------------------------------------------------------------------------

    \191\ Oklahoma Gas & Electric, ``Sooner Units 1 & 2, Muskogee
Units 4 & 5 Dry FGD BART Analysis Follow-Up Report'', December 28,
2009, see pdf pages 28 and 43.
---------------------------------------------------------------------------

9. Contractor's Fees and Profit Are Excessive
    Commenter's estimate for contractor's fees Expense and Profit total
nearly $51 million, or 14% of the estimated total Labor, Material,
Subcontract, and Process Equipment.\192\ By contrast, Sargent & Lundy
estimated for the IPM algorithm total contractor fees and profits of
10% of the estimated Labor,

Material, Subcontract, and Process Equipment cost. When this higher
percentage is combined with a high direct cost, the contractor's fees
become excessive. The high contractor fees and profits assumed in the
Laramie River Station estimate also seem inconsistent with a weak power
plant construction market, as demonstrated by the boilermaker man-hour
data discussed earlier.
---------------------------------------------------------------------------

    \192\ Attachments to Exhibit 14 to Basin Electric Comments, page
4 of SCR estimate.
---------------------------------------------------------------------------

10. Labor, Material, Subcontract, and Process Equipment Costs in Excess
of Historical Norms, With Substantial Additional and Unnecessary Costs
Added
    It is not unusual for owners to report excessive costs because
owners are most interested in a cost estimate that has a very low risk
of an overrun rather than a 30% cost estimate, which has a
higher risk of overrun (about 50%), but is likely to be a better
estimate of actual project cost. Commenter's estimate for total Labor,
Material, Subcontract, and Process Equipment is $361 million. Adding
Sargent & Lundy's estimated cost of scaffolding, freight, and
consumables that is in the Appendices to Basin Electric's Exhibit 14 to
their estimated Labor and Material, Subcontract, and Process Equipment
raises the cost to $383 million (Sargent & Lundy provides no supporting
documentation for this $22 million in additional cost). This is 27%
above the expected cost of $301 million (with elevation accounted for)
developed from the IPM SCR model, which is developed from actual
project data. This suggests that Sargent & Lundy made a fairly
conservative estimate of these costs for Basin Electric. But, in
addition to the cost of Labor, Material, Subcontract, and Process
Equipment, scaffolding, consumables and freight, in their estimate for
Basin Electric, Sargent & Lundy added very high costs for overtime, per
diem (that were not explained as required) and high costs for
contractor's fees and profits, and then added additional project and
process contingencies, unnecessary costs such as SO3
mitigation and un-allowed costs such as AFUDC that increased total
project cost to nearly $750 million--about double what they had
estimated in 2008.\193\ The combined effect of the conservative cost
estimates with additional contingencies or unnecessary cost adders,
results in what appears to be an unrealistically high cost.
---------------------------------------------------------------------------

    \193\ Attachments to Exhibit 14 to Basin Electric Comments, page
4 of SCR estimate and Exhibit 14 page 31.
---------------------------------------------------------------------------

11. Project Contingency of 15% Is Too High in Light of the Method Used
and Very Conservative Underlying Assumptions
    Because the cost estimates developed for Basin Electric 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, Section 1.1 Chapter 1, page 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 (AACE) (CCM Section 1, Chapter
2, p 2-5). AACE 16R-90 \194\ 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
NETL,\195\ ``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 BEC, EPC fees and process contingency.'' AACE 18R-97 \196\
defines different classes of estimates, from 5 (least detailed) to 1
(most detailed). The methodology used in the CCM falls into a Class 4
or Class 5, while the methodology used by Basin Electric in their
comments, with hundreds of line items and thousands of input
parameters, is clearly a far more detailed estimate that does not leave
out any aspect of the project.
---------------------------------------------------------------------------

    \194\ AACE Recommended Practice, AACE 16R-90; www.aacei.org/non/rps/18R-90.pdf.
    \195\ 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.
    \196\ AACE Recommended Practice, AACE 16R-87; www.aacei.org/non/rps/18R-97.pdf.
---------------------------------------------------------------------------

    The 15% project contingency factor in the CCM for SCR shown in
Table 2.5 on page 2-44 of Section 4.2 Chapter 2 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: (1) 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 (2) 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
at page 2-30 of Chapter 2--Cost Estimation: Concepts and Methodology:
``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 Basin Electric 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 for their estimate.
12. The Cost Information in Exhibit 14 Does Not Appear To Be Consistent
With the Cost Information in the Appendices to Exhibit 14
    The table on page 4 of the SCR cost estimate for Units 1-3 shows a
total cost of $481 million. This is inconsistent with the Total Direct
Capital Costs shown on page 31 of Exhibit 14, which total $465 million.
It is unclear what the cause of the $16 million difference is. In
either case, EPA believes that the cost is not adequately explained.

13. Laramie River Station Does Not Require an SNCR System With Four
Injection Zones
    The Laramie River Station is a base loaded unit, with capacity
factors well above 80%. This means that the boiler rarely operates at
part load. Sargent & Lundy designed the SNCR system with four injection
zones to accommodate the ``entire load and temperature range within the
boiler''.\197\ Because the unit will rarely operate at part load and
the emission rate is a 30-day average, there is likely no need for four
injection levels. Four injection levels are only required on load-
following units that spend a significant amount of time at low or
middle loads or units that must comply with emission limits of much
shorter averaging times, such as 24 hour averages or less. In practice,
this system would be designed with two, or, at most, three injection
zones. The additional injection zone adds cost in the form of
additional injectors and furnace penetrations, and associated labor. On
the other hand, EPA has accepted Basin Electric's estimate of the cost
of the SNCR system. Although we believe that there would likely be
fewer injection levels, based upon the furnace exit temperature
reported by the company, we expect that at least one of the injection
levels will require a convective zone injection system using multi-
nozzle lances, which will increase the cost. Therefore, these effects
offset one another and we are accepting the cost provided by Basin
Electric.
---------------------------------------------------------------------------

    \197\ Exhibit 14, page 17.
---------------------------------------------------------------------------

14. Similar Labor Rate Issues for SNCR as for SCR Estimate
    Examination of the labor rates for the Sargent & Lundy cost
estimate revealed that Sargent & Lundy assumed the same high labor
rates for crafts as they did for SCR without the rates explained
sufficiently. They also assumed an additional $2.7 million in
additional overtime and per diem rates that are not explained.\198\
---------------------------------------------------------------------------

    \198\ Appendices to Exhibit 14 of Basin Electric comments, page
4 of SNCR estimate.
---------------------------------------------------------------------------

    For these reasons, the Sargent & Lundy capital cost estimates for
SCR and SNCR are deficient, for the reasons as described above.
However, because EPA expects that the SNCR injection system necessary
for Laramie River Station may require more costly multiple-nozzle
lances in at least one injection zone, this should offset the cost
impact of the deficiencies we have identified, and we are accepting the
capital cost of the SNCR system provided by Basin Electric equal to
$16.9 million per unit.
    For the SCR capital cost at Laramie River, EPA is accepting some
costs and not others, as described in more detail in supporting
information with these comments.\199\
---------------------------------------------------------------------------

    \199\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013; Wyoming EGU BART and
Reasonable Progress Costs--10/28/2013.
---------------------------------------------------------------------------

    Comment: We are very concerned to see that EPA has introduced a
retrofit factor greater than ``1'' (the default) for 13 of the 15 EGUs
evaluated. The IPM model used by EPA to estimate control costs in
Wyoming already includes retrofit costs in its costing algorithms. It
is generally accepted that retrofit projects will incur costs over and
above those for a ``greenfield'' site, and most of those retrofit costs
are already included in the database used to generate the IPM
algorithms. So, unless a particular situation is so extreme as to
warrant an additional retrofit factor, applying a retrofit factor to an
algorithm that already includes retrofit costs is double counting those
costs. Not only is the application of a retrofit factor not mentioned
in the Federal Register Notice, its only supporting documentation
appears in docket item EPA-R08-OAR-2012-0026-0086[1], ``Review of
Estimated Compliance Costs for Wyoming Electricity Generating Units
(EGUs)--revision of previous memo'': ``Selective Catalytic
NOX Reduction (SCR) capital cost is estimated using the IPM
algorithms with retrofit factors adjusted on a unit by unit basis.''
The retrofit factor is a subjective factor used to account for the
estimated difficulty of the retrofit that is unique to the facility.
Because site visits were not possible, the retrofit factor was
estimated from satellite images that provide some insight to the
configuration of the units and degree of congestion around the site and
in the vicinity of where the SCR would be installed. These factors
impact the ability to locate large cranes on the site--that impact how
the SCR is assembled (are large sections lifted into place or is the
SCR ``stick built''), how much ductwork is needed, if the SCR must be
built onto a large, elevated steel structure or can be built near the
ground, and if other equipment must be relocated to accommodate the
space of the SCR. When using the IPM capital cost model, retrofit
difficulties associated with an SCR may result in capital cost
increases of 30 to 50% over the base model.\200\
---------------------------------------------------------------------------

    \200\ Sargent & Lundy, ``IPM Model--Revisions to Cost and
Performance for APC Technologies SCR Cost Development Methodology
FINAL'', August 2010, Project 12301-007, Perrin Quarles Associates,
Inc. p 1.
---------------------------------------------------------------------------

    A proper estimation of retrofit factors involves more than an
inspection of satellite images. For example, EPA Region 8 visited the
four-unit Colstrip power plant in Montana before concluding that a
retrofit factor of ``1'' was appropriate. Once such a site visit is
conducted, retrofit factors should be developed for each element of the
cost analysis--not the ``blanket'' approach used by EPA here.
    Another example is provided by Sargent & Lundy's ``Constructability
Review'' for addition of SCR at Navajo Generating Station. Navajo
Generating Station consists of three EGUs, with the middle unit
constrained by a coal conveyor passing through. Even so, Sargent &
Lundy estimated that construction effort would be only 25% greater for
Unit 2 than for the other two units. EPA needs to clarify why they
chose to add a retrofit factor greater than 1 (average retrofit factor
of 1.33 for 13 of 15 units reviewed) to the costs when retrofit costs
are already contained within data used to generate the IPM and when
neither Wyoming, Basin Electric, or PacifiCorp included a comparable
retrofit factor. By adding the retrofit factor, EPA has overestimated
the costs of SCR: in the case of Dave Johnston Units 1, 2, and 4 and
Wyodak Unit 1, this has led EPA to propose less-efficient controls than
SCR.
    Chapter 2, ``Cost Estimation: Concepts and Methodology'' of the CCM
provides a lengthy discussion of retrofit factors. The CCM addresses
SCR retrofits specifically ``A correction factor for a new installation
versus a retrofit installation is included to adjust the capital
costs'' (Section 4, NOX Controls, Section 4.2,
NOX Post- Combustion, Chapter 2, SCR). The CCM retrofit
factor is $728/MMBtu/hr and, for medium-size boilers like Dave Johnston
Unit 4 or Wyodak, this represents a 23%-24% increase in the direct
capital cost.
    EPA inconsistently and without explanation applied ``retrofit
factors'' that improperly increase the reported capital costs of SCR
installation. Such retrofit factors are intended to account for the
increased costs of unusually difficult retrofits, i.e., those that
present more challenges than assumed for the ``typical'' SCR retrofit,
for which costs are described by the IPM SCR cost module. The EPA
unjustifiably determined that only two of the fifteen Wyoming EGUs
(Laramie River Station Units 1 and 3) would be of average difficulty,
while applying increases of between 20 and 50 percent to the remaining
units. The EPA applied such retrofit factors even for units for which
the source owners did not claim above-average installation challenges.
The

EPA's exclusive evidence of potential retrofit challenges--satellite
images--does not support the EPA's application of retrofit factors.
(The commenter submitted a TSD that elaborated on some of these
points.)
    The descriptions given of the EPA's view of the retrofit difficulty
at each plant based on satellite images make it clear that many guesses
were made and/or that the EPA erred on the side of high retrofit
difficulty to be conservative. Being conservative in cost estimates may
be acceptable if such conservatism is applied equally to all units and
if the EPA provides a reasoned basis for its assumptions, but the EPA
did not do so. The EPA assumed that the two units in the middle at Jim
Bridger ``will be somewhat more difficult to achieve access for
equipment'' and applied the highest retrofit factor of 1.5 to these
units, while for Laramie River Unit 2, the EPA assumed more retrofit
difficulty due to its location in the middle but only applied a
retrofit factor of 1.2. The EPA essentially made guesses that the
middle units may have more retrofit difficulty, and did not
consistently apply the same retrofit factors to the middle units of
these two plants. We found it telling that PacifiCorp's capital cost
estimates for installation of SCR systems at all four Jim Bridger units
(which are of equal size to each other) were identical for each unit,
and the same is true of Basin Electric's capital cost estimates for
installation of SCR systems at all three Laramie River units (which are
also equal in size). Given these facts, the EPA has no basis for its
application of a higher SCR retrofit factor for the units in the middle
(i.e., Jim Bridger Units 2 and 3 and Laramie River Unit 2).
    To summarize, the EPA has not adequately justified the application
of any retrofit factor to the costs of SCR at any of the EGUs in
Wyoming, and the EPA should not apply retrofit factors to increase the
capital costs of SCR without adequate justification for those retrofit
factors. Further, the EPA must remember that the IPM cost module for
SCR is based on actual cost data for SCR retrofits, and that virtually
all SCR retrofits would have some space constraints due to most power
plants being built without ever planning for SCR installation. The EPA
should only apply a retrofit factor if it can justify that the cost of
SCR installation would noticeably deviate from a typical installation.
    Response: As noted by commenter, the IPM cost model is based upon
actual retrofits and incorporates all of the costs normally associated
with retrofit of an SCR. This means that many of the retrofit issues
commenters have raised are incorporated into the base cost, which can
then be adjusted with a retrofit difficulty factor based upon the
perceived difficulty of the retrofit relative to typical retrofits. EPA
disagrees with the commenter in its assertion that the EPA
inconsistently and without explanation applied ``retrofit factors''
that improperly increase the reported capital costs of SCR
installation.
    EPA applied retrofit factors while carefully considering site
conditions. Where there was uncertainty, EPA did lean toward making
more conservative estimates, which would explain the average retrofit
factor exceeding 1.0. Section <IP_ADDRESS> of the CCM discusses retrofit
cost considerations as ``Probably the most subjective part of a cost
estimate.'' The CCM states that, ``Since each retrofit installation is
unique, no general factors can be developed. A general rule of thumb as
a starting point for developing an appropriate retrofit factor is: The
larger the system, the more complex (more auxiliary equipment needed),
and the lower the cost level (e.g. study level, rather than detailed),
the greater the magnitude of the retrofit factor.'' Thus, retrofit
difficulty factor may factor in some uncertainty and be higher to
account for that.
    In the cost estimates EPA developed, retrofit factors were
determined from satellite images using the following considerations:
(1) Available access to and from the site for transportation of
equipment and available space for laying down construction materials;
(2) Location of equipment relative to each other and whether there is a
substantial amount of demolition necessary in order to make room for
SCR equipment; and (3) Access for a crane. At a highly congested site,
crane access can be difficult and may entail a more costly approach.
Access for a crane is a particular concern for internal units when
units are located side-by-side.
    There are no strict guidelines used for determining the actual
value of retrofit factors. They are a matter of judgment. Per the CCM
at <IP_ADDRESS> (page 2-28, Chapter 2 Cost Estimation: Concepts and
Methodology), ``[t]he 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.'' What
follows is the explanation for each of the retrofit factors used at
each of the sites. As will be shown, the retrofit factors were the
result of a thoughtful process, and were not arbitrary.
    With regard to the Dave Johnson site, this is one of the more
congested sites in Wyoming. Per the Andover report on estimated costs
of NOX controls: ``Based upon the close proximity of the
boilers and associated equipment to one another, decommissioned
chimneys that will limit access and ability to move a crane, the coal
pile and coal conveyors that also limits access to the area of the
units where construction would occur, the office building that is
adjacent to Unit 1 and limits access, and the Unit 4 scrubber, retrofit
of an SCR on Units 1-4 would likely entail a significantly higher than
average retrofit cost. Unit 4 probably has the best access of all of
the units because there may be some space between the boiler and the
scrubber, but it is difficult to say for sure from the image and
therefore a conservatively high retrofit difficulty was used for unit 4
that is consistent with the other units.'' \201\ As noted, the site is
fairly congested for all units, justifying a high retrofit factor of
1.5 for all units, not just the middle units.
---------------------------------------------------------------------------

    \201\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013, p. 30; Wyoming EGU
BART and Reasonable Progress Costs--10/28/2013.
---------------------------------------------------------------------------

    Jim Bridger is also limited on space, but not so much so as Dave
Johnston: ``Based upon the satellite photo, the SCR reactors would
likely be installed above the ESPs and ductwork routed to the boiler.
The boilers do not appear to be unusually constrained from the
perspective of installing SCR ductwork; however, access for
construction equipment will be much more difficult to achieve for the
two middle units. The scrubbers and associated piping will limit access
somewhat. Unit 4 access will be limited somewhat by the coal conveyor
and because it's scrubber takes up more room than the other scrubbers.
For this reason a retrofit difficulty factor of 1.5 is assumed for the
middle units and 1.25 for units 1 and 4.'' \202\
---------------------------------------------------------------------------

    \202\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013, p. 35; Wyoming EGU
BART and Reasonable Progress Costs--10/28/2013.
---------------------------------------------------------------------------

    On the other hand, as is apparent from the satellite image, Laramie
River is a more open site than Dave Johnson. Satellite images ``show a
less constrained site than Dave Johnston, with good access to both
units 1 and 3. The coal conveyor is clearly visible and will be an
obstruction for the unit 2 SCR. As a result, retrofit difficulty of
installing SCR is expected to be average, except possibly for unit 2
which is located between units 1 and 3. Access of a crane will be
somewhat more challenging for Unit 2 and an SCR retrofit difficulty of
1.2 is assumed for estimating SCR capital cost. In all cases

the SCR reactor is likely to be installed above the ESP ductwork.''
\203\
---------------------------------------------------------------------------

    \203\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013, p. 39; Wyoming EGU
BART and Reasonable Progress Costs--10/28/2013.
---------------------------------------------------------------------------

    Naughton is much more congested than Laramie River, although access
appears slightly better than for Dave Johnson. Per the Andover report:

    Babcock & Wilcox provided cost estimates for the Naughton unit 1
& 2 SCRs. Babcock & Wilcox's estimate assumed that it would be
necessary to demolish stacks that will be abandoned after a planned
scrubber installation and they also determined that additional fan
capacity was not necessary. Babcock & Wilcox also assumed a complex
support structure would be needed, which adds cost. Babcock and
Wilcox also stated that units 1 and 2 are slightly offset which
makes it impractical to build a common support structure for the SCR
reactors; however, . . . Babcock & Wilcox has used a longer
horizontal duct run on the unit 1 SCR which places the unit 1 and
unit 2 SCR reactors side-by-side so that a common support structure
is likely to be possible, offering some potential savings from what
they have estimated. Alternatively, a shorter horizontal duct run on
unit 1 may make it possible to avoid demolition of the unit 1
chimney that will be abandoned. When using the IPM algorithm a
retrofit difficulty factor of 1.3 is assumed. This was based upon
the fact that it appeared to be a less congested site than Dave
Johnston, but there were potential challenges, such as the chimneys,
that could result in longer duct runs or additional demolition.
    For unit 3 it is also unclear if there is enough space to
install the SCR reactor on the same side of the chimney as the
boiler, which, means that demolition of that chimney may be needed.
There appears to be access for construction equipment, such as a
crane, in the area east of the plant (the upper part of the photo)
and to the north of unit 3. In estimating the cost of the SCR for
unit 3, retrofit difficulty is above average because more lengthy
duct runs or demolition of the chimney are likely needed, and an
assumed retrofit difficulty factor of 1.3 is assumed for unit 3.

    Hence, Naughton is assumed to be an above average retrofit
difficulty because of the potential for some significant interference
from some equipment and the possible need for longer than average duct
runs.
    For Wyodak, access to the site appears good, but there are some
possible issues that might come up if the existing (but decommissioned)
ESP needs to be demolished, which was the reason for the above average
retrofit factor of 1.3. Per the Andover report:

    In the event SCR were installed at the site, the SCR reactor
would likely be located above the existing (but decommissioned) ESP
shown between the boiler building and the chimney . . . There is
ample room on the site for lay down of material. Location of a crane
near the construction site appears to be possible; however, in every
direction from the boiler there is a potential interference that
might complicate crane location relative to the lay-down area.
Therefore, the difficulty of this retrofit is probably average to
perhaps above average. A conservative estimate of retrofit
difficulty of 1.3 is assumed, although a closer examination of the
site may show that a lower retrofit difficulty may be possible.\204\

    \204\ Andover Technology Partners, ``Cost of NOX
Controls on Wyoming EGUs'', October 28, 2013, p. 52; Wyoming EGU
BART and Reasonable Progress Costs--10/28/2013.
---------------------------------------------------------------------------

    As a result, the retrofit factors used were not arbitrary but the
result of a thoughtful process of examining the site for issues that
would affect the difficulty of the retrofit.
    Comment: EPA's application of the maximum retrofit factor (1.5) to
Dave Johnston Units 1 and 2 is unsupported and leads to a significant
$1.5 million/year and $800/ton overestimation of average costs. Neither
PacifiCorp nor Wyoming proposed a retrofit factor for these units. It
is especially surprising that EPA has applied the maximum retrofit
factor to all four units at Dave Johnston, and that even an ``end''
unit like Unit 1 is considered to have the highest degree of retrofit
difficulty. It has been our experience that end units are typically the
easiest to retrofit, while the more difficult retrofits are associated
with ``middle'' units. Once the SCR costs are corrected to address the
issue discussed above, the incremental costs become $5,700-$5,800/ton
(versus $7,050/ton at Bridger Unit 2).
    The EPA applied a retrofit factor of 1.5 to Dave Johnston Units 1-
3, citing close proximity of boilers, decommissioned chimneys and the
coal pile. It is not clear that these issues warrant a 50 percent
increase in SCR costs due to retrofit difficulty at Units 1-3.
    Response: EPA's estimate of retrofit factor is based upon a
thoughtful consideration of the various factors described in the
previous response. With regard to the Dave Johnston site, this appears
to be one of the more difficult sites in Wyoming from the perspective
of retrofit.
    Comment: EPA's application of the maximum retrofit factor (1.5) to
SCR on Dave Johnston Unit 4 is unsupported and leads to a significant
$3.8 million/year and $900/ton overestimation of average costs. Neither
PacifiCorp nor Wyoming proposed a retrofit factor for this unit. We
disagree with EPA's decision to apply the maximum retrofit factor to
all four units at Dave Johnston, and that even an ``end'' unit like
Unit 4 is considered to have the highest degree of retrofit difficulty.
It has been our experience that end units are typically the easiest to
retrofit, while the more difficult retrofits are associated with
``middle'' units.
    The CCM retrofit factor is $728/MMBtu/hr and, for medium-size
boilers like Dave Johnston Unit 4 or Wyodak. This represents a 23%-24%
increase in the direct capital cost. For Dave Johnston Unit 4, the EPA
applied a retrofit factor of 1.5 to the costs of SCR because ``[t]here
may be more space available near unit 4 for a retrofit of SCR, but this
is unclear from the photograph.'' This is a very questionable basis to
justify increasing the costs of SCR by 50 percent.
    Response: Because of the congestion of the overall site at Dave
Johnson plant, a large reduction of retrofit factor to well below 1.5
was not justified even though Unit 4 is an end unit. There appears to
be other equipment in the vicinity of Unit 4 that would obstruct access
and maintaining a retrofit factor of 1.5 seems reasonable.
    Comment: The EPA assigned a 1.3 retrofit factor to the SCR cost
estimate for the single unit Wyodak plant. It appears the main reason
for applying this factor is because the SCR would likely have to be
placed on top of the decommissioned ESP, and that space constraints
were not an issue. Although the EPA summarized that ``. . . the
difficulty of this retrofit is probably average to above average since
it is common to have some relocation of equipment,'' the EPA applied a
30 percent increase to the SCR costs for Wyodak.
    Response: As noted by the commenter, EPA determined that a retrofit
factor of 1.3 is conservative at Wyodak. But, because of the possible
items that are apparent (as described above) from the satellite
photograph and that could get in the way, it was not regarded as below
average difficulty, but perhaps something slightly above average. EPA
therefore does not believe that the retrofit factor should be lower
than 1.0 and it may be as high as 1.3. EPA is basing its cost analysis
on the more conservative estimate.
    Comment: In Montana, EPA used the IPM algorithms for some sources
and not for others, asserting only that use of IPM ``was intended to
ensure that the direct capital costs reflect the most recent cost
levels seen in the marketplace'' and thus did not over-estimate costs.
77 FR 57888. EPA also used IPM for the Arizona FIP but failed to
address how its use was consistent with either the BART Guidelines or
the CCM. 77 FR 72512 (Dec. 5, 2012). In Colorado, EPA said the State's
cost

estimates for Craig Unit 1 deviated from the CCM but accepted them
anyway because EPA was pleased with a State law that required emission
reductions from certain other EGUs. 77 FR 76875. EPA sometimes
supplements the CCM with a rule that installed SCR retrofit costs must
fall between $79/kW and $316/kW, unless the state justifies a deviation
from this range. North Dakota SIP, 77 FR 20929; Montana FIP, 77 FR
57889; New Mexico FIP, 76 FR 52388, 52392. EPA has proposed to apply
this rule to the Wyoming SIP and FIP, 78 FR 34738. This cost range is
derived from ``industry studies'' and does not appear anywhere in the
CCM. Supplementing the CCM with this new requirement is inconsistent
from the terms of the CCM and BART Guidelines.
    Response: We agree that we have used the IPM control cost
algorithms in various regional haze rulemakings as noted by the
commenter. And as noted by the commenter, our intent in using the IPM
cost algorithms was to ensure that our capital cost estimates for SCR
reflect those currently found in the marketplace. Elsewhere in these
responses to comments, we have documented in some detail how our use of
the IPM algorithms is consistent with the BART Guidelines and CCM. We
disagree that we have supplemented the CCM with a rule that retrofit
costs must fall between $79/kW and $316/kW--2010 dollars ($81/kW to
$324/kW when escalated to 2013 dollars), which was the range of actual
installed capital costs found in recent industry studies as cited in
our final rule for North Dakota. In the North Dakota rulemaking, we
used this information to assess whether costs supplied to EPA by states
or sources were consistent with those observed in the industry for
numerous other retrofits spanning a wide range of retrofit
difficulties. As such, this in no way represents a requirement imposed
by EPA; rather, it represents a very practical means by which EPA has
gauged the validity of costs. We acknowledge that, given exceptionally
difficult retrofit circumstances or other factors, it is possible for a
particular retrofit to fall outside of this range. In fact, we note
that our revised costs supporting this final rule are in some cases in
excess of the cited range. Our revised SCR costs for BART EGUs, when
represented on a dollar per kilowatt basis, range from $222/kW to $467/
kW, with a median cost of $322/kW (2013 dollars).\205\ From this, it is
clear that we have not established a requirement that SCR capital costs
fall within the cited range as suggested by the commenter. For our
Colorado final action, we are currently in litigation over our approval
of the State's BART determination for Craig.
---------------------------------------------------------------------------

    \205\ 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: EPA inappropriately claimed that ``Wyoming's SCR capital
costs on a $/kW basis often exceeded real-world industry costs'' (78 FR
34748) and then refers to industry studies conducted between 2002 and
2007 that report installed unit capital costs actually incurred by
owners broadly ranging ``from $79/kW to $316/kW (2010 dollars).'' Id.
EPA also noted ``instances'' in its proposed FIP ``in which Wyoming's
source-based cost analyses did not follow the methods set forth in the
EPA CCM.'' EPA is simply incorrect in stating that Wyoming's analyses
were flawed and did not reflect real-world industry costs for the units
being analyzed. The commenter states that they are presenting
information on the ``real-world'' costs for the upcoming Jim Bridger
Units 3 and 4 SCR projects, which recently were competitively bid for
engineering, procurement, and construction contracts to be installed in
accordance with the requirements in the Wyoming SIP. These real-world
costs, in turn, can easily be compared to the costs assessed by Wyoming
and by EPA in their BART determinations.
    Even when including AFUDC, the Wyoming SIP cost basis aligns
closely with the EPA's cost basis, with each agency again understating
real world costs for these projects. By extension, this real-world cost
information for Jim Bridger Units 3 and 4 validates the methodology
used by Wyoming to determine cost information for each of PacifiCorp's
BART Units. This information clearly disputes EPA's claims in its FIP
that Wyoming ``did not properly or reasonably take into consideration
the costs of compliance'' and that its SCR cost analyses exceeded real
world industry costs and were flawed. Id.
    Response: We disagree that it was incorrect for EPA to state
Wyoming's cost analyses for SCR were flawed. As discussed in our
proposed rule, EPA found several deficiencies with Wyoming's cost
analyses, including: Inclusion of AFUDC, inclusion of some
inappropriate owner's costs, insufficient documentation to support
vendor estimates or bids, and use of incorrect baseline emission rates.
78 FR 34749. These deficiencies represented a departure from the
procedures outlined in the CCM and BART Guidelines and, particularly
when taken collectively, had a material impact on the cost estimates.
We have addressed why each of these items are inconsistent with the CCM
and BART Guidelines in other response to comments here.
    Moreover, since the time of the State's analyses, EPA has been made
aware of additional pertinent information by commenters, much of which
has been incorporated into the revised costs presented in this final
rulemaking. Examples include: Inclusion of certain costs submitted by
the facility owner's where appropriately documented, shorter useful
life for one facility, correction for elevation, use of ammonia instead
of urea as SCR reagent, revised SNCR reagent consumption for some
facilities, and use of busbar costs for auxiliary power in place of
market prices.
    Regarding whether Wyoming's costs exceeded real world industry
costs, see EPA's response to comment immediately above.
    Comment: Wyoming did not overestimate the costs of SCR. The EPA
claimed to have identified a number of flaws in Wyoming's cost analyses
for SCR (78 FR 34748), but only identified one flaw--that ``Wyoming's
SCR capital costs on a $/kW basis often exceeded real-world industry
costs.'' The EPA's use of the word ``often'' indicates that Wyoming's
costs did not always exceed real-world costs, but the EPA did not
explain which costs exceeded real-world costs and which did not.
    The EPA specifically alleged only that the cost estimates for Dave
Johnston Units 3 and 4, Naughton Units 1, 2, and 3, and Wyodak ``are in
excess of the range of capital costs documented by various studies for
actual installations,'' and that the EPA based this conclusion of five
industry studies conducted between 2002 and 2007. The EPA did not
explain why the State was wrong to rely on vendor submitted,
engineered, site-specific cost estimates instead of reports of
installations at other facilities as long as a decade ago. The State's
costs of compliance are based on site-specific capital costs, operating
costs, and maintenance costs provided by the companies in their
applications for a state BART permit, and over 50 percent of the costs
of compliance is driven by the capital cost to engineer and physically
install a SCR system. Such costs must be evaluated on a case-by-case
basis in accordance with Appendix Y. Variable costs, including reagent
usage (ammonia), account only for 2 to 7 percent of SCR costs.
    The BART Guidelines not only allow, but encourage states to take
into account

site-specific conditions that impact the cost of installing emission
controls. Until the EPA explains why it was unreasonable for Wyoming to
prefer site-specific, real-world costs over speculative extrapolation
of costs incurred at other facilities many years past, the EPA cannot
lawfully displace the State's judgment simply because EPA prefers one
approach over the other.
    Response: We disagree that EPA only identified one material flaw in
Wyoming's costs estimates for SCR. See EPA's response to comment
immediately above where we identify several flaws. Because Wyoming's
approach to estimating SCR costs was not consistent with the BART
Guidelines and CCM, it was appropriate for EPA to revise these costs in
our proposed rule.
    We agree that the BART Guidelines encourage states to take into
account site-specific conditions that impact the cost of installing
emission controls. However, we disagree with the commenter's
characterization of the State's costs of compliance for SCR as site-
specific in nature on the mere basis that they were submitted by the
sources. There is nothing in the record to support claims that these
costs were in fact based on detailed site-specific vendor bids, or are
in any manner more site-specific than those costs relied upon by EPA in
our proposed rule. As an example, the BART application submitted by
PacifiCorp for Dave Johnston Unit 3, and relied upon by Wyoming, states
that: ``Costs and schedules for the LNBs and OFA, SNCR, and SCR were
furnished to CH2M HILL by PacifiCorp, developed using Sargent and
Lundy's internal proprietary database, and supplemented (as needed) by
vendor-obtained price quotes. The relative accuracy of these cost
estimates is stated by S&L to be in the range of plus or minus 20
percent.'' \206\
---------------------------------------------------------------------------

    \206\ Wyoming Regional Haze SIP, Attachment A, ``BART Analysis
for Dave Johnston Unit 3,'' prepared for PacifiCorp by CH2MHILL,
December 2007, page 3-7.
---------------------------------------------------------------------------

    From this, it is clear that PacifiCorp, and thereby also the State,
based SCR costs on ``S&Ls internal database'' and not a unique
quotation specific to Dave Johnston Unit 3 supplied by an SCR vendor.
Moreover, while the BART application refers to ``vendor-obtained
quotes,'' it does not make clear for which items these quotes were
obtained, if any, nor are any quotes for SCR included in the BART
application. Instead, the total installed capital cost of SCR (with
combustion controls) is shown in PacifiCorp's economic analysis as a
single line item with a value of $83,301,164, but without any detail or
supporting documentation.\207\ In an update to its initial BART
application, PacifiCorp subsequently increased the capital cost to
$129,700,000, but again without any detail or supporting
documentation.\208\
---------------------------------------------------------------------------

    \207\ Wyoming Regional Haze SIP, Attachment A, ``BART Analysis
for Dave Johnston Unit 3,'' prepared for PacifiCorp by CH2MHILL,
December 2008, Attachment 1.
    \208\ Wyoming Regional Haze SIP, Attachment A, ``Addendum to
Dave Johnston Unit 3 BART Report,'' prepared for PacifiCorp by
CH2MHILL, March 26, 2008, Attachment 1.
---------------------------------------------------------------------------

    We note that the capital cost estimates for SCR presented by EPA in
our proposed rule were also based on the Sargent & Lundy databases as
these in turn underlie the IPM cost algorithms. As such, the commenter
is mistaken when characterizing Wyoming's capital costs as superior to
those from EPA. However, the costs presented by EPA went on to correct
the deficiencies that we have identified elsewhere (e.g., improper
calculation of baseline emissions). Therefore, the capital costs
provided from each agency were ultimately generated in a similar
manner, but only the overall costs generated by EPA were in keeping
with the BART Guidelines and CCM.
    It is notable that, in order to address our concerns regarding lack
of site-specific costs and associated documentation, the Wyoming
sources have submitted additional cost information during the comment
period for the proposed rule. The PacifiCorp comments include capital
costs based on a vendor budgetary quote from Babcock and Wilcox, as
opposed to capital costs based on the Sargent & Lundy databases.
Similarly, Basin Electric has submitted a consultant's report that,
while conceptual in nature and without vendor-based equipment costs,
provides a more detailed analysis of SCR costs for Laramie River than
before. These submittals contain more recent and more detailed cost
information than relied upon by Wyoming in their cost analyses. The
submission of these updated costs from the sources, intended to supply
more site-specific costs to EPA, belies claims by the commenter that
the costs originally used by the State were ``vendor submitted,
engineered, site-specific cost estimates.''
    Comment: We would like to point out that while the EPA makes a
point of saying in their proposed rule that they have followed their
own guidelines in the CCM, that manual has not been updated since 2002.
Representative Lummis of Wyoming has authored language to require the
EPA to update its cost manual for the first time in over a decade. The
old data in the old handbook no longer reflects the true costs of
designing, engineering and installing controls. Before rejecting state
data on the cost of compliance, the EPA must engage states and
regulating entities to acquire real-world cost data and use that data
to update its manual.
    Response: We consider the use of the broader costing methodology
used by the CCM, the overnight method, as crucial to our ability to
assess the reasonableness of the costs of compliance. Evaluation of the
cost of compliance factor requires an evaluation of the cost-
effectiveness associated with the various control options considered
for the facility. A proper evaluation of cost-effectiveness allows for
a reasoned comparison not only of different control options for a given
facility, but also of the relative costs of controls for similar
facilities. If the cost-effectiveness of a control technology for a
particular facility is outside the range for other similar facilities,
the control technology may be rejected as not cost-effective. In order
for this type of comparison to be meaningful, the cost estimates for
these facilities must be performed in a consistent manner. Without an
``apples-to-apples'' comparison of costs, it is impossible to draw
rational conclusions about the reasonableness of the costs of
compliance for particular control options. Use of the CCM methodology
is intended to allow a fair comparison of pollution control costs
between similar applications for regulatory purposes.
    Just as importantly, while we have followed the broad methodology
of the CCM as required by the BART Guidelines, we have also accounted
for the cost of controls currently observed in the marketplace. In
particular, our use of the cost calculations taken from the IPM,
released in 2010, is designed to reflect modern day costs. Moreover,
operation and maintenance costs for items such as labor, reagent, and
catalyst, reflect current market values. In short, we have adhered to
the broad overnight cost methodology specified in the CCM, while
updating both capital and operation and maintenance costs to reflect
current market conditions. Therefore, the commenter is mistaken in
asserting that our costs are based on outdated information.
    Comment: EPA's regional haze FIP also is improper because it
assumes BART NOX controls over $5,000 per ton are ``cost
effective.'' (See e.g., 77 FR 33053.) Appendix Y, on the other hand,
states that BART NOX control costs per ton above $1,500 are
not ``cost

effective.'' In the preamble to the BART Guidelines, EPA suggests that
75% of the EGUs would have BART NOX removal costs between
$100 and $1,000 per ton, and almost all of the remaining EGUs could
install sufficient BART NOX control technology for less than
$1,500 per ton. EPA also recognized in the preamble that SCR was
generally not cost effective for EGUs, except for EGUs with cyclone
boilers (where the cost per ton was less than $1,500 per ton, with an
average of $900 per ton). Based upon EPA's Preamble, BART
NOX control technology that costs more than $1,500 per ton
should not be considered ``cost effective.'' Here, EPA found BART
NOX controls with a ``cost effectiveness'' number much more
than $1,500 per ton to be ``cost effective.'' Therefore, EPA should
withdraw its regional haze FIP.
    Response: We disagree with this comment. For each source subject-
to-BART, the RHR, at 40 CFR 51.308(e)(1)(ii)(A), requires that states
identify the level of control representing BART after considering the
factors set out in CAA section 169A(g), as follows: ``States must
identify the best system of continuous emission control technology for
each source subject to BART taking into account the technology
available, the costs of compliance, the energy and non-air quality
environmental impacts of compliance, any pollution control equipment in
use at the source, the remaining useful life of the source, and the
degree of visibility improvement that may be expected from available
control technology.'' 70 FR 39158. Because the preamble generally
discusses costs, this does not obviate the need for states (or EPA in
the case of a FIP) to identify the best system of continuous emission
control technology on a case-by-case basis considering the five
factors. While EPA described various dollar-per-ton costs as ``cost-
effective'' in various preambles (e.g., 70 FR 39135-39136), EPA did not
establish an upper cost effectiveness threshold for BART
determinations.
    Comment: Far from stating that the CCM must be the exclusive source
of cost information, the BART Guidelines state that ``[t]he basis for
equipment cost estimates also should be documented, either with data
supplied by all equipment vendor (i.e., budget estimates or bids) or by
a referenced source (such as the EPA CCM]).'' Although the BART
Guidelines then say that cost estimates should he based on the CCM, it
also says that the CCM should only he used ``where possible.'' The
Guidelines go on to say that the CCM ``addresses most control
technologies in sufficient detail for a BART analysis.''
    The CCM does not say that it addresses `all' control technologies,
just ``most'', implying that the CCM does not supply all of the
necessary information. Further, the Guidelines state that the cost
analysis should ``take into account any site-specific design or other
conditions identified above that affect the cost of a particular BART
technology option.'' Again, the CCM acknowledges that there are
conditions, design scenarios, etc. that are not addressed in the CCM
but that exist in the real world that must be addressed.
    Response: We acknowledge that our BART guidelines state, ``In order
to maintain and improve consistency, cost estimates should be based on
the [CCM], where possible'' and that ``[w]e 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 Control CCM or there
are additional cost methods that could be used, we believe that these
could serve as useful supplemental information.'' The CCM contains two
types of information: (1) Study level cost estimates of capital and
operation and maintenance costs for certain specific types of pollution
control equipment, such as SCR, and (2) a broader costing methodology,
known as the overnight method. We agree that the language of the BART
Guidelines does not require strict adherence to the study level
equations and cost methods used to estimate capital and operating and
maintenance costs.
    We consider the use of the broader costing methodology used by the
CCM, the overnight method, as crucial to our ability to assess the
reasonableness of the costs of compliance. Evaluation of the cost of
compliance factor requires an evaluation of the cost-effectiveness
associated with the various control options considered for the
facility. A proper evaluation of cost-effectiveness allows for a
reasoned comparison not only of different control options for a given
facility, but also of the relative costs of controls for similar
facilities. If the cost-effectiveness of a control technology for a
particular facility is outside the range for other similar facilities,
the control technology may be rejected as not cost-effective. In order
for this type of comparison to be meaningful, the cost estimates for
these facilities must be performed in a consistent manner. Without an
``apples-to-apples'' comparison of costs, it is impossible to draw
rational conclusions about the reasonableness of the costs of
compliance for particular control options. Use of the CCM methodology
is intended to allow a fair comparison of pollution control costs
between similar applications for regulatory purposes. This is why the
BART guidelines specify the use of the CCM where possible and why it is
reasonable for us to insist that the CCM methodology be observed in the
cost estimate process. The overnight method has been used for decades
for regulatory control technology cost analyses, and its use ensures
equitable BART determinations across states and across sources.
    Comment: Although EPA contends that States must conform in all
respects to the Agency's CCM, its own consultant ignores the Manual
when calculating capital costs and operating and maintenance costs, and
instead uses an entirely different methodology called the IPM. 78 FR
34749. EPA tries to finesse this problem by asserting that the
consultant followed ``the structure of'' the CCM and BART Guidelines,
id., but that simply is not true. The IPM is a fundamentally different
tool and uses a fundamentally different methodology than the CCM--it
does not follow the CCM. Therefore, to rely on the consultant's cost
report to disapprove Wyoming's cost analysis and BART analysis would be
arbitrary and capricious, and not in accordance with law.
    Response: We disagree. As noted elsewhere in these responses to
comments, in our revised cost estimates, we have followed the broad
methodology of the CCM, referred to as the overnight method, while
updating capital and operating and maintenance costs to reflect current
real-world costs. In doing so, we directed our consultant (Andover) to
reconcile anything in the IPM cost algorithms that would be
inconsistent with the CCM's overnight method. For example, the IPM cost
algorithms include AFUDC, which as we have established elsewhere in
these response to comments, is not part of the overnight costs.
Accordingly, our consultant eliminated this cost when utilizing costs
derived IPM cost algorithms. In effect, we have ``squared'' the IPM-
based costs with the methodology required by the CCM.
    Comment: EPA's average cost effectiveness for combustion controls
and SCR for the Laramie River units is higher than Wyoming's average
cost effectiveness. Compare, e.g., 78 FR 34773, Table 36 (Wyoming's SCR
average cost effectiveness of $3,372/ton for Unit 1) with 78 FR 34775,
Table 39 (EPA's SCR average cost effectiveness of $3.718/ton for Unit
1). The higher the cost effectiveness of a given technology, the
stronger the case for rejecting it. If the State was justified in
rejecting SCR based on its lower predicted cost of SCR, it would be
even more justified in

rejecting SCR if it had used EPA's higher cost. The outcome would not
have changed, and so any error alleged by EPA is not material.
    EPA's incremental cost effectiveness for combustion controls plus
SCR, compared with the cost effectiveness of combustion controls plus
SNCR, is lower than Wyoming's incremental cost effectiveness. However,
in considering cost effectiveness for purposes of both its SIP
disapproval and its FIP proposal, EPA cites and relies primarily on the
average cost effectiveness for SCR, not the incremental cost. 78 FR
34776 (``[T]he cost-effectiveness for new LNBs with OFA and SCR ranges
from approximately $3600/ton to $3900/ton with significant visibility
improvement at the most impacted Class I area. . . . When considering
the cost effectiveness and visibility improvement of new LNBs plus OFA
and SCR, it is within the range of what EPA has found reasonable for
BART in other SIP and FIP actions.'') EPA refers to incremental cost
only incidentally--not as an affirmative reason for disapproving
Wyoming's BART. Id. (``We also propose to find that the incremental
cost-effectiveness does not preclude the selection of new LNBs with OFA
and SCR.'').
    Response: We disagree. The commenter fails to note that the
visibility improvement presented by EPA in our proposed rule is higher
than that found by the State. The tables cited by the commenter show a
visibility improvement from SCR of 0.44 deciviews resulting from the
State's analysis, while EPA's analysis showed a visibility improvement
of 0.79 deciviews. We found that, when balancing all of the BART
factors, this level of visibility improvement was significant enough to
justify the costs associated with SCR. In our revised visibility
modeling analysis for this final rule, we have presented a lower
visibility improvement for Laramie River Unit 1 of 0.57 deciviews. We
continue to find that this level of visibility improvement, and
consideration of the other BART factors, warrants installation of SCR.
The same can be said for the other two Laramie River units.
    Additionally, the SCR costs and visibility improvement for the
Laramie River units provided by the State and EPA are not directly
comparable. In the BART application submitted by Basin Electric, and
relied upon by the State, and unlike in the case of SNCR, no additional
combustion controls are assumed in the SCR control scenario. Since the
time that Basin Electric submitted the BART application to the State,
additional combustion controls have been installed on the Laramie River
units. We have taken account of these additional controls in our
analyses. When assessing the emission reductions from SCR (or SNCR),
and the associated costs and visibility improvement, we incorporated
the actual emission rates currently being achieved with the additional
combustion controls. We have presented the costs of compliance and
visibility for the additional combustion controls plus SCR, much in the
same way that the State presented the same factors for the PacifiCorp
units.
    Comment: The costs of SCR plus combustion controls are cost
effective at all of the Wyoming EGUs regardless of whether the costs
are based on EPA's cost analyses or the commenter's 2012 cost analyses
conducted for the original Wyoming SIP. SCR costs for each EGU in
Wyoming, show that SCR plus combustion controls is very cost effective
for all BART-subject EGUs and also Dave Johnston Units 1 and 2.
Further, even EPA's June 2013 cost estimates for SCR plus combustion
controls show that these controls are cost effective at all Wyoming
EGUs, despite what the commenter believes are deficiencies in EPA's
cost effectiveness analyses that overestimate the costs of SCR plus
combustion controls. These costs are within the range that has been
required or proposed of other similar sources to meet BART as follows:
     Final NOX BART determination for San Juan Units
1-4 requires installation of SCR at all four units to meet a
NOX emission limit of 0.05 lb/MMBtu, found that the costs
ranged from $1,987/ton to $2,651/ton of NOX removed, in 2010
dollars.
     EPA Region 9 has proposed SCR as BART for Four Corners
Units 1-5 to meet a NOX limit of 0.11 lb/MMBtu at a cost
effectiveness of $2,515/ton to $3,163/ton in 2008 dollars. That
converts to $2,407/ton to $3,028/ton in 2010 dollars.
     In its FIP for Montana, EPA found that the cost
effectiveness of SCR controls for Colstrip Units 1 and 2 of
approximately $3,200/ton per unit (in 2010 dollars) was reasonable.
     In its FIP for Arizona regional haze, EPA is requiring SCR
along with combustion controls to meet BART at the BART-subject coal-
fired units at Apache, Cholla, and Coronado power plants at cost
effectiveness values ranging from $2,275/ton to $3,472/ton.
    Response: We agree that the costs for SCR plus combustion controls
presented in our proposed rule, taken without consideration of the
remaining BART factors, may generally be considered cost effective.
However, the CAA and RHR require a consideration of all five BART
factors. For example, a control that is considered cost effective may
not be warranted if the visibility improvement is minor. Also, there
may be occasions that, while the average cost effectiveness of a
control is reasonable, the incremental cost effectiveness may not be.
In short, EPA must weigh more than just the cost effectiveness when
considering BART.
    Also note that, as described elsewhere in these responses to
comments, we have revised the SCR cost estimates that we presented in
our proposed rule. In today's final rule, we have again balanced the
costs along with the remaining BART factors when considering the
selection of BART controls.
    Comment: EPA's proposed FIP is arbitrary, capricious, and contrary
to law for a number of reasons, including that the EPA's BART analyses
ignored relevant data. Wyoming based its BART analyses on site-
specific, engineered, vendor submitted bids for installing emission
controls (citing the SIP Attachment A materials related to Laramie
River Station), and Basin Electric has submitted to EPA comments
extensively explaining the bases for these cost estimates, including
the substantial technical difficulty of installing SNCR and SCR at
Laramie River Station due to the design of the three units. The EPA has
disregarded the site-specific cost estimates submitted for Laramie
River Station and the other BART sources in Wyoming, and the EPA has
alleged without any specificity that Wyoming did not properly or
reasonably take into consideration the costs of compliance. The EPA
relied on the IPM Model with retrofit factors adjusted on a source-by-
source basis, instead of relying on the site-specific costs.
    EPA's October 23, 2012 revised cost memo states that ``[t]he
retrofit factor is a subjective factor used to account for the
estimated difficulty of the retrofit that is unique to the facility''
and noted that these retrofit factors were determined without site
visits, but based on satellite images of the facilities. At EPA's
public hearing in Casper, Wyoming, on July 26, 2013, Basin Electric's
consultant, Kenneth Snell, explained to EPA in detail how the satellite
images fail to reveal multiple conditions specific to Laramie River
Station that make installing SCR far more expensive than EPA's
consultant assumed. EPA's failure to rebut those positions is arbitrary
and, moreover, that the EPA's methodology--

relying on a subjective interpretation of satellite images--is itself
arbitrary and capricious because it strains credulity to claim that one
can assess retrofit costs by simply looking at hazy satellite pictures
of a power plant.
    Response: EPA disagrees. First, Wyoming's BART analysis \209\ was
based upon a 2008 cost estimate by Basin Electric, which, when adjusted
for the fact that they were performed prior to addition of combustion
controls, resulted in similar capital costs for SCR and similar cost
effectiveness. Moreover, and as noted in previous responses, the costs
submitted by Wyoming should not be considered site-specific estimates,
and therefore superior to EPA's costs, on the mere basis that they were
submitted by a source. In any case, with their comments on EPA's
reproposal, Basin Electric has roughly doubled their claimed cost of
SCR, but these were not part of the Wyoming BART analysis. These new
costs submitted by Basin Electric are presumably intended to be more
site-specific in nature than those originally submitted to the State.
---------------------------------------------------------------------------

    \209\ Wyoming Department of Environmental Quality Air Quality
Division BART Application Analysis AP-6047 May 28, 2009.
---------------------------------------------------------------------------

    Second, the new costs offered by Basin Electric were found to be
deficient in a number of respects that are discussed more specifically
in other responses to comments. The new costs estimates included
numerous costs that were inadequately explained or without any
supporting documentation. The new cost estimates also did not include
vendor quotes. Per Basin Electric's Exhibit 14, page 21: ``The LRS
[Laramie River Station] cost estimates are conceptual in nature; thus,
S&L did not procure equipment quotes specifically for the LRS control
systems.''
    EPA also disagrees with the commenter regarding the use of
satellite images for assessing retrofit difficulty. As noted in
responses to other comments, because they provide a unique ``bird's
eye'' view, satellite images are routinely used to evaluate conditions
at a site: Available space for a crane, access to and from the site,
interferences that may exist at the site boundary, interferences
between major pieces of equipment, available space for laying down
material. With regard to SCR installation, satellite images cannot
reveal whether or not the air preheater must be relocated to
accommodate SCR ductwork; however, none of the commenters indicated
that any affected Wyoming BART sources found it necessary to relocate
their air preheater. Satellite images cannot reveal the ``ideal
location'' for reagent storage equipment, although this is not a large
impact on cost. When possible and resources allow, site visits may also
provide useful data in addition to satellite images, but these are
generally performed in addition to rather than in lieu of analysis of
satellite images.
    Mr. Snell's comments are largely addressed in other comments and
broadly fall into three areas: (1) Criticism of EPA's use of the IPM
algorithm for estimating SCR cost; (2) Assertions that EPA failed to
take into account site-specific factors affecting cost; (3) Assertions
that EPA failed to take into account balance of plant systems that
would need to be upgraded. Each of these items raised by Mr. Snell as
well as the specific issues within each item has been addressed
elsewhere in other responses to comments.
    Comment: It has been our experience that the effectiveness of SNCR
is highly dependent upon the characteristics of each boiler. EPA states
that SNCR typically reduces NOX an additional 20 to 30%
above combustion controls without excessive NH3 slip.
NOX reduction with SNCR is known to be greater at higher
NOX emission rates than lower rates. Accordingly, EPA has
estimated that the NOX reduction from SNCR as 30% for
initial NOX greater than 0.25 lb/MMBtu, 25% for
NOX from 0.20 to 0.25 lb/MMBtu and 20% for NOX
less than 0.20 lb/MMBtu.
    To support this statement, EPA cites a memo from Jim Staudt,
Andover Technology Partners (``Review of Estimated Compliance Costs for
Wyoming Electric Generating (EGUs)--Revision of Previous Memo'', memo
from Jim Staudt, Andover Technology Partners, to Doug Grano, EC/R,
Inc., February 7, 2013, p 7), but this memo provides no evidence or
documentation to support the assumptions that these control levels can
be achieved. Such assumptions, whether or not supported, can
significantly affect the outcome of a BART determination, as EPA
explained regarding Laramie River: ``Therefore, EPA predicts that the
reduction that can be achieved with SNCR at the Laramie River units is
20%, which is much lower than the 48% assumed by Wyoming. This
significantly reduces the tons reduced by SNCR which is in turn used in
the calculation of cost effectiveness. It also affects the incremental
cost effectiveness between SNCR and SCR (both in combination with
additional combustion controls).'' The use of incremental costs in this
manner is extremely sensitive to bias due to the interjection of
control strategies based upon invalid assumptions of control
efficiency.
    Another commenter stated that the EPA is wrong to claim that
Wyoming overestimated the ability of SNCR to reduce NOX. The
commenter made the following points in support of this claim:
     The CCM claims that ``[r]eductions of up to 65% have been
reported for some field applications of SNCR in tandem with combustion
control equipment such as low NOX burners (LNB).''
     Wyoming's estimates are entirely consistent with
demonstrated SNCR effectiveness. One study clearly concluded that
``SNCR has the capability of NOX reductions in the range of
30-60%, depending on the specific retrofit application.'' See EPRI,
Cardinal 1 Selective Non-Catalytic Reduction (SNCR) Demonstration Test
Program, at 1-2 (2000). That study showed, for example, that a 600 MW
unit equipped with LNB could reduce NOX by an amount greater
than EPA's ``typical'' results.
     The EPA's AP 42, Fifth Edition, Volume I, Chapter 1:
External Combustion Sources recognizes that ``[t]he effectiveness of
SNCR depends on the temperature where reagents are injected; mixing of
the reagent in the flue gas; residence time of the reagent within the
required temperature window; ratio of reagent to NOX and the
sulfur content of the fuel that may create sulfur compounds that
deposit in downstream equipment.''
    The commenter concluded that EPA's own literature, as well as other
studies, recognize that SNCR effectiveness is highly contextual and
that it can achieve reductions far in excess of Wyoming's estimates.
    The commenter asserted that the EPA, without explanation,
disregarded its own position on the contextual nature of SNCR
effectiveness, and in turn disregarded Wyoming's well-reasoned analysis
by relying instead on ``typical'' NOX reductions. The
commenter believes that the EPA has practiced arbitrary decision making
because the EPA did not explain in its proposal why it now prefers a
generic approach to SNCR effectiveness in reducing NOX over
its previously expressed recognition that effectiveness depends on a
host of facility-specific factors.
    Response: EPA agrees with the commenter that the effectiveness of
SNCR is highly dependent upon the characteristics of each boiler, and
those characteristics include furnace temperature, furnace CO
concentration, NOX level and other factors, but furnace
temperature, CO concentration, and

NOX level are most important. The tendency of NOX
reduction to decrease as the NOX concentration is reduced is
a well-established phenomenon. Utility boiler upper furnace
temperatures are typically in the range of 2000-2300 [deg]F, but can
sometimes be lower or higher. As described in Section 1.2.3, SNCR
Performance Parameters in the Control CCM, and also by Sun, Hofmann and
Pachaly in 1990, and by Muzio, Montgomery, Quartucy and Texeira in
1993,210 211 the percentage reduction in NOX is
strongly impacted by the residence time, furnace temperature and the
starting, or baseline, NOX. Because most utility boiler
furnace temperatures and residence times fall into an expected range,
the possible NOX reduction is generally related to baseline
NOX and Figure 1.5 of the CCM demonstrates the effect of
baseline NOX and temperature on NOX reduction. Of
course, there are some units that may fall outside the typical range of
furnace temperatures or CO levels, and can achieve higher or lower
levels of NOX reduction. As noted in our response to other
comments, the furnace temperatures at Laramie River Station as reported
by Basin Electric in their recently submitted comments are much higher
than typical, and this will limit the possible NOX
reduction.
---------------------------------------------------------------------------

    \210\ Sun, W., Hofmann, J., and Pachaly, R., ``Post-Combustion
NOX Reduction With Urea--Theory and Practice'', Seventh
Annual International Pittsburgh Coal Conference, September 10-14,
1990.
    \211\ Muzio, L., Montgomery, T., Quartucy, G., Texeira, D.,
``The Effect of Residence Time On SNCR Processes'', EPRI/EPA 1992
Joint Symposium on Stationary Combustion NOX Control, Bal
Harbor, FL, May 24-27, 1993.
---------------------------------------------------------------------------

    On the other hand, EPA disagrees that EPA ``disregarded its own
position on the contextual nature of SNCR effectiveness, and in turn
disregarded Wyoming's well-reasoned analysis''. On the contrary, EPA
carefully considered the contextual situation at Laramie River Station
and the State's analysis in reaching its opinion. Experience has shown
that for utility boilers NOX reductions of 48% using SNCR
alone have only been possible from much higher NOX baselines
than exist at Laramie River Station. In practice, facility owners have
generally found that, when using SNCR, the lowest cost approach is to
first reduce NOX as far as possible with combustion controls
and then use SNCR for additional reductions beyond what combustion
controls can provide. As a result, SNCR is rarely used alone to provide
48% NOX reduction on electric utility boilers because the
baseline levels in practice are typically too low to achieve such high
NOX reduction through SNCR.
    The Cardinal Station citation raised by the commenter is from a
test on a 600 MW unit that had a NOX baseline of around 450-
500 ppm of NOX \212\--in the range of about 0.6 to 0.7 lb/
MMBtu, well above the emission rate of the Laramie River Station units,