established market for fly ash to be used in concrete. Four testimonial
letters from North Dakota fly ash marketers and end-users (included in
Appendix C.2 of the SIP) attest to problematic NH3
concentrations in fly ash due to SCR and SNCR control technology. The
State also noted that loss of fly ash sales would cause the undesirable
non-air quality environmental impact of additional waste destined for
landfill disposal. A summary of the State's NOX BART
analysis, and the modeling results provided by both the source and the
State, are provided in Table 31 for each unit.

                                     Table 31--Summary of Coal Creek NOX BART Analysis for Unit 1 and Unit 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts \2 3\
                                                                            Emissions                          Cost      -------------------------------
             Control option                  Control      Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)          benefit      Fewer days >
                                                                                (delta dv)     0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LTO....................................              90           0.022           4,821           58.07           12,045           1.853              64
LDSCR..................................              80           0.043           4,286           56.15           13,101           1.760              62
SNCR...................................              50           0.108           2,678           22.9             8,551           1.507              50
SOFA + LNB Option 1 \1\................              30           0.15            1,607           66.0               411           1.419              49
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The State and company also reviewed a less desirable Option 2 which was the same control technology with a lower control efficiency of 21%.
\2\ The visibility modeling that Great River Energy performed for Coal Creek Units 1 and 2 included SO2 control in addition to the noted NOX control.
  The modeling results shown above reflect the chosen SO2 BART control, scrubber modifications, in addition to the noted NOX control option. Thus, these
  values do not reflect the distinct visibility benefit from the NOX control options but do provide the incremental benefit between the options.
\3\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    North Dakota determined BART to be modified and additional SOFA
plus LNB with emission limits of 0.15 lb/MMBtu on an annual average
basis and 0.17 lb/MMBtu on a 30-day rolling average basis. North Dakota
provided that Unit 1 and Unit 2 emissions may be averaged provided the
average does not exceed the limit. The estimated cost of modified and
additional SOFA plus LNB was $411 per ton of NOX removed,
and the capital and annualized costs were estimated to be $5,260,000
and $660,000 per year, respectively.
b. EPA's Evaluation of the State's NOX BART Review for Coal
Creek Units 1 and 2
    During review of North Dakota's NOX BART analyses for
Coal Creek Station, we identified a possible discrepancy with Great
River Energy's and the State's costs associated with lost fly ash
sales. Upon our request, subsequent to submittal of the SIP, North
Dakota obtained additional supporting information from Great River
Energy for lost fly ash revenue and for the potential cost of fly ash
NH3 mitigation. The supporting information included an
updated cost analysis from Great River Energy noting that the correct
sales price for fly ash was $5 per ton instead of $36 per ton. Great
River Energy indicated the $36 per ton price was a typographical error.
The updated analysis included corrected fly ash revenue data and
NH3 mitigation costs.
    That analysis, dated June 16, 2011, indicated that the average cost
effectiveness for SNCR at Coal Creek Station Units 1 and 2 would be
$2,318 per ton of NOX emissions reductions rather than the
original estimate of $8,551 per ton. While Great River Energy
subsequently revised this value to $3,198 per ton based on concerns
regarding the technical feasibility of mitigating the NH3 in
North Dakota lignite fly ash,\35\ either of these values is
substantially less than the values North Dakota relied on to make its
NOX BART determination for Coal Creek Station Units 1 and 2.
They are also within the cost effectiveness range that North Dakota
found reasonable for BART controls at other BART sources and that we
and other states have found reasonable. Great River Energy's error

also affected the cost effectiveness values for SCR.
---------------------------------------------------------------------------

    \35\ See July 15, 2011 letter from Great River Energy to Terry
O'Clair.
---------------------------------------------------------------------------

    Because of the significant error underlying the State's cost
analysis, we are proposing to disapprove the State's NOX
BART determination for Coal Creek Station Units 1 and 2 and are
proposing a FIP to establish NOX BART limits for these
units.

E. Federal Implementation Plan To Address NOX BART for
Milton R. Young Station Units 1 and 2, and Leland Olds Station Unit 2

 1. Introduction
    As noted above, North Dakota selected SNCR + ASOFA as
NOX BART for Milton R. Young Station Units 1 and 2 and
Leland Olds Station Unit 2, but in doing so, inappropriately eliminated
SCR + ASOFA as potential BART. Thus, in our proposed FIP, we are re-
evaluating these two technologies and associated emission limits as
potential BART. Our analysis follows our BART Guidelines for both
facilities. For Milton R. Young Station 1 and 2, the BART Guidelines
are mandatory. Milton R. Young Station has a capacity of 794
megawatts.\36\ For Leland Olds Station 2, the guidelines are not
mandatory, but we are following them because they provide a reasonable
and consistent approach for determining BART.
---------------------------------------------------------------------------

    \36\ Letter from John T. Graves, Environmental Superintendent,
Minnkota Power Cooperative, Inc. to Dana Mount, Director, Division
of Environmental Engineering, North Dakota Department of Health, Re:
Permit to Operate No. F76009, Permit Revisions, November 20, 1995.
---------------------------------------------------------------------------

2. BART Analysis for Milton R. Young Station 1
    Step 1: Identify All Available Technologies.
    Our analysis only considers SNCR + ASOFA and SCR + ASOFA. Because
the State selected SNCR +ASOFA as BART, and our concern is that the
State did not properly evaluate SCR as BART, there is no need to
consider lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    We are not eliminating either SNCR or SCR as being technically
infeasible. Both technologies have been widely employed to control
NOX emissions from coal-fired power
plants.37 38 39 The State determined SNCR was technically
feasible for North Dakota EGUs. We agree with the State that SNCR is
technically feasible. The State also determined in Section 7 of the SIP
that two forms of SCR are technically feasible for use on North Dakota
EGUs burning lignite coal, stating the following:
---------------------------------------------------------------------------

    \37\ Institute of Clean Air Companies (ICAC) White Paper,
Selective Catalytic Reduction (SCR) Controls of NOX
Emissions from Fossil Fuel-Fired Electric Power Plants, May 2009,
pp. 7-8.
    \38\ Control Technologies to Reduce Conventional and Hazardous
Air Pollutants from Coal-Fired Power Plants Northeast States for
Coordinated Air Use Management (NESCAUM), March 31, 2011, p. 16.
    \39\ ICAC White Paper, Selective Non-Catalytic Reduction (SNCR)
for Controlling NOX Emissions, February 2008, pp. 6-7.

    The seven BART sources determined SCR is not technically
feasible for installation on boilers in North Dakota burning lignite
coal. The Department agrees that high dust SCR is not technically
feasible; however, LDSCR and TESCR are considered technically
---------------------------------------------------------------------------
feasible.

    The State based its conclusion on an analysis contained in Appendix
B.5 that the State submitted with its Regional Haze SIP.
    According to our BART Guidelines, a demonstration of technical
infeasibility must be documented and must show, ``based on physical,
chemical, or engineering principles, why technical difficulties would
preclude the successful use of the control option on the emissions unit
under review.'' 40 CFR part 51, appendix Y, section IV.D, Step 2. Only
then may a control technology be eliminated from further consideration
in the BART analysis. Id. The BART Guidelines go on to state that a
control technology is technically feasible if it is ``available'' and
``applicable.''
    A technology is considered available if the source owner may obtain
it through commercial channels, or it is otherwise available in the
common sense meaning of the word. Id. SCR technology has been available
through commercial channels for many years, and it could be purchased
for use at Milton R. Young Station Units 1 and 2. SCR technology is not
in the ``pilot scale testing stages of development'' for use at coal-
fired power plants, and there is no need for Minnkota ``to conduct
extended trials to learn how to apply [the] technology on a totally new
and dissimilar source type.'' Id.
    A technology is considered applicable if it can reasonably be
installed and operated on the source type under consideration. EPA must
exercise its technical judgment in making this determination. Id. The
Guidelines state that a commercially available control option will be
presumed applicable if it has been used on the same or a similar source
type. Given that SCR has been deployed at hundreds \40\ of EGUs,
burning a wide variety of coals, it is presumed that it is applicable
to the coal-fired EGUs at Milton R. Young Station.
---------------------------------------------------------------------------

    \40\ ICAC White Paper, May 2009.
---------------------------------------------------------------------------

    While Minnkota, the owner of Milton R. Young Station, and more
recently the State of North Dakota,\41\ have asserted that SCR
technology is not technically feasible, we cannot reasonably conclude
that SCR is not available or applicable to Milton R. Young Station. In
EPA's view, the concerns raised by Minnkota and the State relate only
to the specific length of catalyst life at Milton R. Young Station, not
to the commercial availability of SCR, or the ability of SCR to reduce
NOX emissions from the flue gas stream, at Milton R. Young
Station Units 1 and 2. Their primary argument is that the fuel used at
Milton R. Young Station, and in turn the flue gas stream, contain
relatively high concentrations of certain constituents (primarily
sodium and potassium) that will deactivate the catalyst relatively
rapidly and require that the catalyst be replaced too often. We
consider this to be a cost issue, not a matter of technical
feasibility. The BART Guidelines state, ``Where the resolution of
technical difficulties is merely a matter of increased cost, you should
consider the technology to be technically feasible.'' 40 CFR part 51,
appendix Y, section IV.D, step 2. As noted above, SCR has a long and
proven history of successfully reducing NOX emissions from
coal-fired electric steam generating units.
---------------------------------------------------------------------------

    \41\ In the context of a recent BACT determination for MRYS, the
State reversed its prior position and decided in that context that
SCR is technically infeasible on cyclone boilers burning North
Dakota lignite coal. On July 28, 2011, the State submitted to EPA as
part of Amendment No. 1 to the regional haze SIP the entire
administrative record for its BACT determination for MRYS. The
administrative record consists of at least 259 documents comprising
over 850 megabytes of information. EPA was unable to consider this
administrative record/SIP revision in this proposed action; the time
available under a relevant consent decree deadline did not allow EPA
to. Note that under the CAA, EPA is not required to act on a SIP
submittal until 12 months after it is determined to be or deemed
complete. EPA has individually considered some of the documents
included in the State's BACT administrative record and has included
those documents in the docket for this proposed action. We note that
under the dispute resolution provisions of a separate consent decree
between EPA, the State of North Dakota, Minnkota Power Cooperative,
Inc., and Square Butte Electric Cooperative, (Civil Action No. 1:06-
CV-034), EPA has filed a petition with the United States District
Court for the District of North Dakota disputing the State's PSD
BACT determination and its finding in that context that SCR is
technically infeasible at MRYS. Our proposed action here pertains to
BART, not BACT, is governed by CAA provisions and regulations
specific to regional haze and BART, and is not governed by such
consent decree.
---------------------------------------------------------------------------

    We also note that in the BACT context, the State gives great weight
to the fact that two catalyst vendors queried by Minnkota indicated an
unwillingness to provide typical catalyst life guarantees without first
performing catalyst deactivation field

tests on the coal Minnkota burns at Milton R. Young Station. However,
as noted in our BART Guidelines, ``lack of a vendor guarantee by itself
does not present sufficient justification that a control option or an
emissions limit is technically infeasible.'' 40 CFR part 51, appendix
Y, section IV.D, step 2. Here, the vendor guarantee for a specific
catalyst life, or lack thereof, is not relevant to the availability of
SCR, or its ability to remove NOX from the gas stream at
Milton R. Young Station, but only to the willingness of two catalyst
companies to provide a specific catalyst life guarantee without more
information. Neither vendor contacted by Minnkota indicated it would
not provide SCR catalyst absent any prior field testing. One of the two
catalyst vendors contacted by Minnkota is willing to provide full
performance guarantees on critical operating parameters such as
NOX reduction, NH3 slip, SO2 to sulfur
trioxide (SO3) conversion, and pressure drop. This is strong
evidence that at least one of the two catalyst vendors contacted by
Minnkota believes NOX can be successfully controlled with
SCR at Milton R. Young Station and that SCR is commercially available.
In addition, both catalyst vendors contacted by Minnkota have stated
they believe a catalyst life guarantee can be offered once the field
testing data is collected. The fact that some catalyst vendors have not
yet offered a catalyst life guarantee without field testing of
deactivation rates is not evidence that SCR is not available or is
technically infeasible at Milton R. Young Station. Given the record
before us, the lack of a vendor guarantee for a specific catalyst life
is not sufficient to overcome the presumption that this commercially
available technology is applicable to coal-fired power plants,
including Milton R. Young Station.
    Additional support for our finding that SCR is not technically
infeasible is contained in Appendix B.5 of the State's SIP. There, the
State concluded that low-dust and tail-end SCR were technically
feasible. A LDSCR would be located after the electrostatic precipitator
(ESP), which removes particulates. Alternatively, a TESCR would be
located after both the ESP and SO2 scrubber. Testing has
shown that these control devices would remove a high percentage of the
ash and catalyst poisons before they would reach the SCR, thereby
negating the higher concentrations of catalyst poisons in North Dakota
lignite coal compared to other applications of high-dust SCR at coal-
fired utility boilers.
    North Dakota reviewed PM stack tests at Milton R. Young Station
Unit 2 (August 2007 and May 2008) that indicated an average sodium and
potassium removal efficiency of greater than 99% by the ESP and wet
scrubber, with resulting emission rates at 0.78 milligrams sodium
sulfate and 0.20 milligrams potassium sulfate per normal cubic meter.
See Appendix B.5 to the SIP submittal. The State found that these
loadings of sodium and potassium aerosols, which would enter a LDSCR or
TESCR at Milton R. Young Station, were significantly lower than the
concentrations present in the gas streams of boilers burning peat and
wood that were the subject of experimental and pilot scale testing of
SCR catalyst life. The State carefully evaluated the results of such
testing and concluded that a reasonable catalyst life could be achieved
at Milton R. Young Station.\42\ Id. Appendix B.5 also indicates that
North Dakota independently consulted three vendors who opined to the
State that SCR would be technically feasible at Milton R. Young
Station.\43\ Finally, the State found that existing biomass boilers,
with flue gas characteristics that approximate those from North Dakota
lignite, have used TESCR successfully. Id.
---------------------------------------------------------------------------

    \42\ The State concluded that an SCR system would require a
catalyst life of at least 10,000 hours to be considered an
applicable technology and technically feasible. We do not agree with
this arbitrarily-selected bright-line threshold. Catalyst life
relates to how often the catalyst needs to be replaced to maintain
the ability of the SCR to successfully reduce NOX
emissions. Thus, catalyst life is a component of the cost analysis
for SCR.
    \43\ ``The Department [North Dakota] contacted three of the
vendors, Ceram Environmental, Haldor Topsoe and Babcock Power. The
companies generally confirmed the information in the emails to Mr.
Hartenstein. Babcock Power indicated that they had no worries about
getting 10,000 hours of catalyst life at the M.R. Young Station.
However, they recommended `coupon' testing prior to design of the
SCR. Ceram was convinced it was technically feasible; however, their
representative did acknowledge that if the sodium and potassium
aerosols are making it through the ESP and wet scrubber, catalyst
deactivation could be a problem. Haldor Topsoe indicated that the
catalyst deactivation at M.R. Young would be manageable if the
catalyst is kept dry during outages.'' SIP Appendix B.5.
---------------------------------------------------------------------------

    Also, Microbeam Technologies, Inc. (Microbeam) performed PM
emissions testing for Milton R. Young Station Unit 2 in March of 2009.
The Microbeam results demonstrate the high removal efficiency of PM and
the primary catalyst poisons of interest (sodium and potassium) by the
ESP and scrubber at Milton R. Young Station. The results reflected a PM
removal efficiency of 99.76%, and that the amount of sodium oxide plus
potassium oxide was approximately 50-90 times greater entering the ESP
than exiting the ESP. The results were similar for sodium oxide plus
potassium oxide entering the ESP versus exiting the wet scrubber. This
means the loading of sodium oxide plus potassium oxide on a high-dust
SCR at Milton R. Young Station would be approximately 50-90 times
higher than on a LDSCR or TESCR. Put another way, the Microbeam results
showed that the ESP removes at least 98% of the catalyst poisons, which
would be before the flue gas reaches a LDSCR or TESCR. Thus, any
differences in fuel quality (especially concentrations of catalyst
poisons in the ash) of North Dakota lignite compared to other types of
coal in the United States would be offset at the control percentages
described because Milton R. Young Station would employ a LDSCR or
TESCR, whereas the vast majority of SCR installations in the United
States are configured as high-dust SCRs.
    Step 3: Evaluate Control Effectiveness of Remaining Control
Technology.
    For the purposes of our SNCR + ASOFA cost analysis, we used a
control efficiency of 58% and an emission rate of 0.355 lb/MMBtu, the
same control efficiency that North Dakota used. For our TESCR + ASOFA
cost analysis we used the control efficiency of 93.8% that Minnkota
used in its BART analysis and an emission rate of 0.05 lb/MMBtu,
instead of North Dakota's 90% control efficiency and 0.085 lb/MMBtu
emission rate. We find that SCR technology, by itself, can achieve 90%
control efficiency and that the overall NOX reduction would
be even greater (93.8%) with the use of combustion controls in
combination with SCR. A summary of emissions projections for the two
control options is provided in Table 32.

    Table 32--Summary of EPA NOX BART Analysis Control Technologies for Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                Emissions
             Control option                    Control        Emission rate   Emissions  (tons/ reduction (tons/
                                           efficiency (%)      (lb/MMBtu)            yr)               yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA...........................              93.8             0.053               627             9,410
SNCR + ASOFA............................                58             0.355             3,784             5,248
No Controls (Baseline)..................                 0             0.849        \1\ 10,037  ................
----------------------------------------------------------------------------------------------------------------
\1\ North Dakota used a baseline of 9,032 tons/yr. We changed this to reflect maximum heat input and the
  utilization rate reported by Minnkota.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SNCR + ASOFA.
    We are not relying on North Dakota's costs for SNCR. Though the
North Dakota costs derived by Burns & McDonnell are generally
consistent with the Control Cost Manual, at least one cost, related to
lost revenue due to outage, is not. The North Dakota costs are also
based on lower reagent costs which we acknowledge do fluctuate. To
ensure a fair comparison between the two competing technologies, we
have re-worked the costs for SNCR. We relied on Minnkota's Burns &
McDonnell estimate for total capital equipment costs for SNCR. However,
we have then generally used factors and assumptions provided by the
Control Cost Manual for the remainder of the SNCR analysis. In the
absence of a Control Cost Manual method for combustion controls, we
have used all the costs provided by North Dakota for ASOFA. This
approach is similar to the one we used to analyze the costs for SCR at
Milton R. Young Station Unit 1, which enables us to compare the costs
of the two technologies on a consistent basis. This was not an
exhaustive effort, but it did result in a downward adjustment in the
cost estimate for SNCR. We deem the analysis adequate for comparing the
cost effectiveness values of the two top control options--SCR and SNCR.
    Regarding specific elements in our cost analysis, we used $475 per
ton to estimate urea costs and did not allow for lost revenue due to
outage (consistent with Control Cost Manual). To estimate the average
cost effectiveness (dollars per ton of emissions reductions), we
divided the total annual cost by the estimated NOX emissions
reductions. We summarize our costs from our SNCR cost analysis in
Tables 33, 34, and 35.

   Table 33--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
             Description                 Cost factor        Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A.........  ................         4,277,000
Capital Investment SNCR, B..........  ................         4,007,000
Total Capital Investment, TCI                    A + B         8,284,000
 (2009$)............................
------------------------------------------------------------------------

 Table 34--Summary of EPA NOX BART Annual Analysis for SNCR on Milton R.
                       Young Station Unit 1 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........            60,108
Reagent..........................  ...................           949,747
Electricity......................  ...................            21,529
Water............................  ...................               958
Increased Coal...................  ...................            36,845
Increased Ash....................  ...................             2,639
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              1,071,827
     (TDAC).                        Items Listed Above.
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           378,253
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         1,450,081
                                  --------------------------------------
    Total Annual Cost ASOFA        North Dakota                2,520,719
     (TACA).                        Appendix B.4.
                                  --------------------------------------
    Total Annual Cost SNCR+ASOFA.  TACS + TACA........         3,970,799
------------------------------------------------------------------------
\1\ Capital Recovery Factor (CRF) is 0.0944 and is based on a 7%
  interest rate and 20 year equipment life. Office of Management and
  Budget, Circular A-4, Regulatory Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.

            Table 35--Summary of EPA NOX BART Costs for SNCR on Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                             Total installed                      Emissions       Average cost
               Control option                  capital cost     Total annual      reductions    effectiveness ($/
                                                  (MM$)          cost (MM$)       (tons/yr)           ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA...............................           8.284            3.971            5,777               687
----------------------------------------------------------------------------------------------------------------

    SCR + ASOFA.
    Our contractor, ERG, prepared a cost analysis for SCR for Milton R.
Young Station Units 1 and 2. As explained below, ERG started with some
of the cost information in the Burns & McDonnell (Minnkota's
contractor) BACT cost analyses provided in the NOX BACT
Analysis Study, Supplemental Reports, for Units 1 and 2 dated February
2010 and November 2009, respectively. See SIP Appendix C.4.
    ERG used Burns & McDonnell's original SCR equipment costs and other
costs that were not independently verified by EPA (auxiliaries/balance
of plant, construction costs, natural gas pipeline, reagent costs,
natural gas costs), but then calculated total capital costs and annual
costs for SCR using the applicable Control Cost Manual methodology and
factors and certain information supplied by EPA. While EPA could not
independently verify many of the Burns & McDonnell-estimated costs, and
believes they may overestimate actual costs, the result is a cost
estimate that should represent the upper end of likely costs for these
items. EPA provided ERG with information regarding catalyst volume,
catalyst cost, catalyst replacement frequency, and estimated additional
outage time for replacing spent catalyst. EPA provided a reasonable
value for catalyst cost of $6,000 per cubic meter based on vendor data.
This cost could be significantly reduced if regenerated catalyst were
used. Contingencies were calculated using the Control Cost Manual
assumptions. The maintenance costs were adjusted using the cost factor
in the Control Cost Manual, and annual costs were not ``levelized.''
\44\
---------------------------------------------------------------------------

    \44\ As discussed in section V.D., above, the Control Cost
Manual does not provide for ``levelization'' of annual costs.
---------------------------------------------------------------------------

    To be conservative, ERG calculated four different catalyst
replacement scenarios. Scenarios 1 through 3 assume catalyst
replacement of one layer per year, one layer every two years, and one
layer every three years. ERG's Scenarios 1 through 3 do not include
additional outage time that Minnkota claimed would be necessary for
boiler maintenance for solidified slag removal specifically
attributable to the installation of ASOFA. For Scenario 3, which we
find most reasonable for reasons further described below, there would
be no additional unit outage time (and associated electricity costs)
for catalyst replacement, because all of this work could be completed
during a regularly scheduled major unit outage event. Despite our
disagreement about the extent of additional outage time due to ASOFA,
we had ERG run Scenario 4 as a ``worst-case'' scenario that assumes the
accuracy of Burns & McDonnell's estimate of additional outage time
needed for solidified slag removal due to the installation of
ASOFA.\45\ For all scenarios, ERG modified the amount of time required
for each catalyst layer replacement from Burns & McDonnell's
assumptions, recalculated the unit availability using the revised
downtime, and recalculated electricity costs and corresponding
NOX emissions using the new availability.
---------------------------------------------------------------------------

    \45\ Minnkota asserts there is a potential reduction in
reliability and availability of a lignite-fired cyclone boiler as a
result of installing and operating a separated overfire air system
due to challenges in maintaining adequate slag layer development and
flow within the cyclone barrels or furnace bottom compared with non
air-staged combustion. Minnkota claims the need for forced or
extended scheduled outages to remove the solidified slag. EPA does
not agree that these additional outage times for ASOFA are
legitimate. For further detail regarding this issue, please refer to
our Technical Support Document.
---------------------------------------------------------------------------

    We find that Scenario 3 is the most reasonable based on the
following considerations regarding catalyst life:
     An SCR catalyst must be changed out periodically. The
catalyst lifetime is a function of catalyst activity and NH3
slip. As catalyst activity decreases over time, NH3 slip
increases until it reaches the design limit, at which point new
catalyst is added. One of the two catalyst vendors queried by Minnkota
prepared a budgetary proposal that estimated a catalyst exchange cycle
for Milton R. Young Station based on the catalyst design presented in
the proposal. This catalyst design was developed by the catalyst vendor
based on the detailed boiler and fuel specifications supplied by
Minnkota. The catalyst design was also intended to reflect the three
year planned outage schedule at Milton R. Young Station specified by
Minnkota. In the budgetary proposal, the catalyst design includes an
initial fill of two catalyst layers with one empty spare layer. The
catalyst vendor estimated the two initial catalyst layers would operate
for 24,000 hours, at which time a third layer of catalyst (in the spare
layer) would be added. The vendor estimated that the first layer of
catalyst would need replacement at about 88,000 hours, or over 10 years
of SCR operation. The second catalyst layer replacement would not be
needed until approximately 125,000 hours or approximately 15 years of
SCR operation. Thus, EPA's assumption of replacing a layer of catalyst
every three years is conservative and a reasonable assumption. Based on
the catalyst vendor's expected catalyst exchange cycles, the three year
replacement assumption would overestimate annual costs once the third
layer of catalyst is added after the third year of operation. At that
point, the catalyst vendor estimates less frequent need for catalyst
replacement. While the other catalyst vendor queried by Minnkota
estimates an approximately two year catalyst replacement cycle, there
is no reason to give more deference to that proposal.
     SCR catalyst is typically specified to last 16,000 to
24,000 hours for hot-side (or high dust) SCRs (after the boiler), the
worst-case location for catalyst life. In the tail-end position, after
ash and catalyst poisons have been significantly reduced by pollution
control devices, SCR catalyst typically lasts 50,000 to over 100,000
hours.\46\
---------------------------------------------------------------------------

    \46\ See, for example, vendor e-mails in Appendix D of the North
Dakota Report: Selective Catalytic Reduction (SCR) Technical
Feasibility for M.R. Young Station; McIlvaine, Next Generation SCR
Choices--High-Dust, Low-Dust and Tail-End, FGD & DeNOx Newsletter,
no. 369, January 2009; Hans Hartenstein, Steag's Long-Term SCR
Catalyst Operating Experience and Cost, EPRI SCR Workshop, 2005.
---------------------------------------------------------------------------

     We have assumed the SCR at Milton R. Young Station 1 would
be located at the tail end, after the ESP and new wet scrubber. As
noted, these control devices remove the majority of the ash and
catalyst poisons. Flue gas composition data collected at Milton R.
Young Station 2, which has an inefficient, older wet scrubber, proves
that the amount of submicron alkali aerosols is so small that catalyst
deactivation would not occur rapidly.\47\ Further, any remaining
soluble alkaline substances would not poison the catalyst at TESCR
operating temperatures. Significant deactivation only occurs if
condensed moisture is present at the catalyst surface, i.e., when the
catalyst is being cooled down to below the water dew point. Unit
startups and shutdowns do not occur frequently at Milton R. Young
Station 1. Furthermore, condensation on the catalyst can be prevented
by bypassing or buttoning up the SCR reactor during forced outages of a
few days.\48\

Regardless, catalyst vendors have ample experience preventing moisture
condensation in SCR catalysts.\49\ In other words, available evidence
suggests that catalyst life would be relatively long, consistent with
that experienced at plants burning other types of coal and fuel.
---------------------------------------------------------------------------

    \47\ 1/8/10 EPA Comments, enclosure 2, pp. 24-25 (``As discussed
extensively in the Minnkota BACT comments, the actual flue gas
composition analysis data measured downstream of the wet FGD at MRYS
[Milton R. Young Station] proves that the amount of submicron
alkalie aerosols is so small that catalyst deactivation does not
occur rapidly and a relatively long catalyst life can reasonably
expected (sic) compared to most HDSCR [high dust SCR]
installations.'')
    \48\ 5/6/08 Cochran (CERAM) E-mail, p. 2 (As to high dust SCR:,
a worst case: ``Due to the high sodium and iron concentrations it is
recommended that a full SCR bypass system be installed. During lay-
up periods the catalyst would need to remain warm and dry (above
condensing conditions), for instance with an air drying or
dehumidification system. This may necessitate the use of a
dehumidifier and air lock system to access the reactor.''), in 5/8/
08 Milton R. Young Additional Information.
    \49\ Minnkota Power Cooperative, Inc. and Square Butte Electric
Cooperative, Additional Information and Discussion of Vendor
Responses on SCR Technical Feasibility, North Dakota's NOx BACT
Determination for Milton R. Young Station Units 1 & 2, Appendix A,
Vendor Emails, Email from John Cochran, CERAM Environmental, Inc.,
to Robert Blakley, Re: Request for Lignite SCR Feasibility
Commercial and Technical Information, May 6, 2008 (``Sodium is a
catalyst poison. Concerns reported by Dr. Benson regarding high
sodium content and fine fume are duly noted, but inadequate evidence
is presented that this could be a fatal flaw to application of SCR
considering the flawed pitch and resultant pluggage of the catalyst
used during the Coyote Station testing [North Dakota lignite].
Sodium is not a poison to catalyst at SCR operating temperatures.
Significant deactivation can occur if condensed moisture transports
sodium residing at the surface into the catalyst pore structure
during outage or layup. CERAM has experience with high sodium
applications to substantiate this effect. Important to avoid
deactivation from sodium is the need to protect the catalyst from
going through a condensation event.'')
---------------------------------------------------------------------------

    ERG derived the annual cost of $2,161,000 (2009 dollars) for
installation, operation, and maintenance of ASOFA for Unit 1 from
tables 4-6-SF of Minnkota's February 2010 Supplemental BACT Analysis
for Milton R. Young Station. As we noted above relative to the ASOFA
slag issue and associated costs due to additional unit outage time
assumed by Minnkota in calculating annual operating costs, EPA does not
concur that this cost is entirely representative, but the ERG analysis
relied on this cost due to time constraints. As with the annual costs
for SCR, ERG did not ``levelize'' these annual costs for SNCR. ERG
added the annual costs for ASOFA to the annual costs for SCR to arrive
at a total cost for the combined controls.
    To estimate the average cost effectiveness (dollars per ton of
emissions reductions), ERG divided the total annual cost by the
estimated NOX emissions reductions.
    We summarize our costs from the ERG cost analysis in Tables 36, 37
and 38. See our Technical Support Document for the full analyses, in
particular, our letter to Mr. Terry O'Clair, North Dakota Department of
Health, dated May 10, 2010, and attached spreadsheet.

  Table 36--Summary of EPA NOX BART Capital Cost Analysis for TESCR on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
                                   Control cost manual
           Description                  factor or          Cost (MM$)
                                       calculation
------------------------------------------------------------------------
Total Direct Capital Costs, A....  ...................             86.32
Indirect Installation Costs
    General Facilities...........  0.05 x A...........              4.32
    Engineering and Home Office    0.10 x A...........              8.63
     Fees.
    Process Contingencies........  0.05 x A...........              4.32
Total Indirect Installation        0.20 x A...........             17.26
 Costs, B.
    Project Contingency, C.......  0.15 x (A + B).....             15.54
Total Plant Cost, D..............  A + B + C..........            119.12
    Preproduction Cost, G........  0.02 x D...........              2.41
    Inventory Capital (Reagent),   ...................             0.087
     H.
    Natural Gas Pipeline.........  ...................              1.50
                                  --------------------------------------
    Total Capital Investment, TCI  ...................            123.13
     = D + G + H.
------------------------------------------------------------------------

Table 37--Summary of EPA NOX BART Annual Costs for TESCR Scenario 3 1 on
                  Milton R. Young Station Unit 1 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost (MM$) 2
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........             1.809
Reagent..........................  ...................             2.716
Catalyst.........................  ...................             0.250
Electricity......................  ...................             2.711
Natural Gas for Flue Gas           ...................             3.756
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various                 11.281
     (TDAC).                        Items Listed Above.
    Indirect Annual Cost 3 (IDAC)  CRF x TCI..........            10.735
    Annual ASOFA Cost (AAC)......  ...................             2.161
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC + AAC..            24.176
------------------------------------------------------------------------
\1\ See Table 38 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.0872 and is based on a 6%
  interest rate and 20 year equipment life. From Minnkota NOX BACT
  Analysis Study, Milton R. Young Station Unit 1, Table C.1-1, p. C1-4,
  October 2006 (provided in BART Determination Study for Milton R. Young
  Station Unit 1 and 2, October 2006, SIP Appendix C.4).

  Table 38--Summary of EPA NOX BART Costs for Various TESCR Scenarios on Milton R. Young Station Unit 1 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                  Emissions                        Average cost
              Scenario                      Description          reductions 1     Total annual    effectiveness
                                                                 (tons/year)       cost ($MM)        ($/ton)
----------------------------------------------------------------------------------------------------------------
1...................................  1 layer replaced every             9,418            25.53            2,711
                                       year.
2...................................  1 layer replaced every             9,414            24.73            2,627
                                       2 years.
3...................................  1 layer replaced every             9,410            24.18            2,569
                                       3 years.
4...................................  ASOFA downtime allowed.            9,424            26.23            2,783
----------------------------------------------------------------------------------------------------------------
\1\ Reductions vary based on impacts to boiler availability in each scenario (i.e., lower boiler operating hours
  equate to lower emission reductions).

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and
operation of the evaluated controls are not significant enough to
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Milton R. Young Station Unit 1 is at
least 20 years. Thus, this factor does not impact our BART
determination.
    Factor 5: Evaluate visibility impacts.
    Minnkota modeled the visibility benefits for SNCR + ASOFA using
natural background per the BART Guidelines. North Dakota then performed
additional modeling for the SCR + ASOFA control option. Minnkota and
North Dakota both provided single-source modeling results using natural
background conditions, complying with the BART Guidelines. The SCR +
ASOFA option, when combined with wet scrubbing for SO2,
would result in a significant improvement in visibility at Theodore
Roosevelt, estimated to be 3.476 deciviews and 114 fewer days above 0.5
deciviews. This represents an incremental visibility improvement of
1.400 deciviews and 43 fewer days above 0.5 deciviews beyond that
achieved by wet scrubbing alone. Moreover, when compared to SNCR +
ASOFA, it would result in an incremental visibility improvement of
0.553 deciviews and 18 fewer days above 0.5 deciviews. North Dakota
conducted supplemental cumulative modeling for SCR at Milton R. Young
Station 1 that is discussed in more detail in section V.D.1.e. For the
reasons described there, we are disregarding North Dakota's alternative
modeling in our analysis.
    More information on our interpretation of the State's and source's
modeling information is included in the Technical Support Document.
    Step 5: Select BART.
    We propose to find that BART is SCR + ASOFA at Milton R. Young
Station 1 with an emission limit of 0.07 lb/MMBtu (30-day rolling
average). Of the five BART factors, cost and visibility improvement
were the critical ones in our analysis of controls for this source. We
agree with the State that the other three factors are not relevant to
this BART determination.
    In our BART analysis for NOX at Milton R. Young Station
1, we considered SNCR + ASOFA and SCR + ASOFA. The comparison between
our SNCR analysis and our TESCR Scenario 3 analysis is provided in
Table 39.

                Table 39--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2 4
                                                           Total                                           Incremental   -------------------------------
                                                         installed      Total annual      Average cost         cost         Visibility
                   Control option                      capital cost      cost (MM$)      effectiveness    effectiveness     improvement    Fewer days >
                                                           (MM$)                            ($/ton)          ($/ton)          (delta          0.5 dv
                                                                                deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)..........................      \3\ 123.13             24.18            2,569            4,855           3.476             114
SNCR + ASOFA........................................            8.28              3.97              687  ...............           2.923              96
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Minnkota's and the State's modeling for both SNCR and SCR was based on lower emissions reductions (fewer tons removed) than we anticipate; thus, we
  anticipate slightly greater visibility benefits (delta deciview) than reflected in these values. The visibility benefit shown is for the most impacted
  Class I area, Theodore Roosevelt.
\2\ Minnkota and the State modeled combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of wet scrubbing along
  with the noted NOX control option.
\3\ This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of ASOFA.
\4\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    We have concluded that SNCR + ASOFA and SCR + ASOFA are both cost
effective control technologies and that both would provide substantial
visibility benefits. SNCR + ASOFA has a cost effectiveness value of
$687 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it
has a cost effectiveness value of $2,569 per ton of NOX
emissions reduced. This is well within the range of values we have
considered reasonable for BART and that states other than North Dakota
have considered reasonable for BART. Even with more frequent catalyst
replacement, SCR would still be cost effective even at the high end of
the range ($2,783 per ton) allowing for the most frequent catalyst
replacement of one layer per year and allowing for the questionable
costs of lost power generation revenue in TESCR Scenario 4. We also
analyzed the SCR costs assuming the same baseline emissions

of 9,032 tons per year used by North Dakota and determined that the
high-end cost effectiveness value, assuming the most frequent catalyst
replacement frequency, would be about $3,115 per ton of NOX
reduced. All of these cost effectiveness values are well within the
range of values that North Dakota considered reasonable in several of
its NOX BART determinations, where predicted visibility
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at
Milton R. Young Station 1, as modeled by Minnkota and the State. Both
sets of controls would have a positive impact on visibility. As
compared to SNCR + ASOFA, SCR + ASOFA would provide an additional
visibility benefit 0.553 deciviews and 18 fewer days above 0.5
deciviews at Theodore Roosevelt. We consider these impacts to be
substantial, especially in light of the fact that neither of these
Class I areas is projected to meet the uniform rate of progress. We
also note that the 0.553 deciview improvement at Theodore Roosevelt is
greater than the improvement in visibility that North Dakota found
reasonable to support other NOX BART determinations in the
SIP despite higher cost effectiveness values for the sources involved
in these other BART determinations. Given the incremental visibility
improvement associated with SCR + ASOFA, the relatively low incremental
cost effectiveness between the two control options ($4,855 per ton),
and the reasonable average cost effectiveness values for SCR + ASOFA,
we propose that the NOX BART emission limit for Milton R.
Young Station 1 should be based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted
the annual design rate of 0.05 lb/MMBtu upwards to allow for a
sufficient margin of compliance for a 30-day rolling average limit that
would apply at all times, including startup, shutdown, and
malfunction.\50\ We are also proposing monitoring, recordkeeping, and
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \50\ As discussed in the BART Guidelines, section V (70 FR
39172, July 6, 2005), and Section 302(k) of the CAA, emissions
limits such as BART are required to be met on a continuous basis.
---------------------------------------------------------------------------

    As we have noted previously, under section 51.308(e)(1)(iv), ``each
source subject to BART [is] required to install and operate BART as
expeditiously as practicable, but in no event later than 5 years after
approval of the implementation plan revision.'' Based on the retrofit
of other SCR installations we have reviewed, we propose a compliance
deadline of five (5) years from the date our final FIP becomes
effective.
3. BART analysis for Milton R. Young Station 2
    Step 1: Identify All Available Technologies.
    Our analysis only considers SNCR + ASOFA and SCR + ASOFA. Because
the State selected SNCR + ASOFA as BART, and our concern is that the
State did not properly evaluate SCR as BART, there is no need to
consider lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    For the reasons described in our BART analysis and determination
for Milton R. Young Station Unit 1, we are not eliminating either SNCR
or SCR as being technically infeasible.
    Step 3: Evaluate Control Effectiveness of Remaining Control
Technology.
    For the purposes of our SNCR + ASOFA cost analysis, we used a
control efficiency of 58% and an emission rate of 0.355 lb/MMBtu, the
same control efficiency that North Dakota used. For our TESCR + ASOFA
cost analysis we used the control efficiency of 93.8% that Minnkota
used in its BART analysis and an emission rate of 0.05 lb/MMBtu,
instead of North Dakota's 90% control efficiency and 0.085 lb/MMBtu
emission rate. We find that SCR technology, by itself, can achieve 90%
control efficiency and that the overall NOX reduction would
be even greater (93.8%) with the use of combustion controls in
combination with SCR. A summary of emissions projections for the two
control options is provided in Table 40.

    Table 40--Summary of EPA NOX BART Analysis Control Technologies for Milton R. Young Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                Emissions
               Control option                     Control       Emission rate   Emissions (tons/ reduction (tons/
                                              efficiency (%)      (lb/MMBtu)          yr)              yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA..............................              93.8            0.049              984           14,807
SNCR + ASOFA...............................              58              0.330            6,630            9,162
No Controls (Baseline).....................               0              0.786       \1\ 15,792  ...............
----------------------------------------------------------------------------------------------------------------
\1\ North Dakota used a baseline of 15,507 tons/yr. We adjusted this to reflect maximum heat input and the
  utilization rate reported by Minnkota.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SNCR + ASOFA.
    For the reasons described in our BART analysis and determination
for Milton R. Young Station Unit 1, we are not relying on North
Dakota's costs for SNCR. We have adjusted North Dakota's costs using
the same methodology we describe in our BART analysis and determination
for Milton R. Young Station Unit 1.
    We summarize our costs from our SNCR cost analysis in Tables 41,
42, and 43.

   Table 41--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                  Milton R. Young Station Unit 2 Boiler
------------------------------------------------------------------------
             Description                 Cost factor        Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A.........  ................        10,008,000
Capital Investment SNCR, B..........  ................         7,437,806
                                     -----------------------------------
    Total Capital Investment, TCI                A + B        17,445,806
     (2009$)........................
------------------------------------------------------------------------

 Table 42--Summary of EPA NOX BART Annual Analysis for SNCR on Milton R.
                       Young Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........           111,567
Reagent..........................  ...................         1,768,029
Electricity......................  ...................            37,963
Water............................  ...................             1,784
Increased Coal...................  ...................            68,590
Increased Ash....................  ...................             4,913
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              1,992,847
     (TDAC).                        Items Listed Above.
                                  --------------------------------------
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           702,076
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         2,694,923
                                  --------------------------------------
    Total Annual Cost ASOFA        North Dakota                3,749,684
     (TACA).                        Appendix B.4.
                                  --------------------------------------
    Total Annual Cost SNCR +       TACS + TACA........         6,444,608
     ASOFA.
------------------------------------------------------------------------
\1\ Capital Recovery Factor (CRF) is 0.0944 and is based on a 7%
  interest rate and 20 year equipment life. Office of Management and
  Budget, Circular A-4, Regulatory Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.

            Table 43--Summary of EPA NOX BART Costs for SNCR on Milton R. Young Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                             Total installed                      Emissions       Average cost
               Control option                  capital cost     Total annual      reductions    effectiveness ($/
                                                  (MM$)          cost (MM$)       (tons/yr)           ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA...............................           17.46            6.444            9,162               703
----------------------------------------------------------------------------------------------------------------

    SCR + ASOFA.
    Our contractor, ERG, prepared a cost analysis for SCR for Milton R.
Young Station Units 1 and 2. For a description of the approach/
assumptions ERG used in preparing its cost analysis, please see our
BART analysis and determination for Milton R. Young Station Unit 1. For
further detail, please refer to our Technical Support Document.
    For the reasons discussed with respect to Milton R. Young Station
Unit 1 in section V.E.2., we find that Scenario 3 with a 3-year
catalyst life is the most reasonable assumption for Milton R. Young
Station Unit 2.
    ERG derived the annual cost of $3,843,000 (2009 dollars) for
installation, operation, and maintenance of ASOFA from tables 4-6SF of
Minnkota's February 2010 Supplement BACT Analysis for Milton R. Young
Station. As we noted above relative to the ASOFA slag issue, EPA does
not concur that this cost is representative, but the ERG analysis
relied on this cost due to time constraints. ERG added the annual costs
for ASOFA to the annual costs for SCR to arrive at a total cost for the
combined controls.
    We summarize our costs from the ERG cost analysis in Tables 44 and
45. See our Technical Support Document for the full analyses, in
particular, our letter to Mr. Terry O'Clair, North Dakota Department of
Health, dated May 10, 2010, and attached spreadsheet.

    Table 44--Summary of EPA NOX BART Capital Cost Analysis for TESCR
         Scenario 3 \1\ on Milton R. Young Station Unit 2 Boiler
------------------------------------------------------------------------
                                   Control cost manual
           Description                  factor or          Cost (MM$)
                                       calculation
------------------------------------------------------------------------
Total Direct Capital Costs, A....  ...................            151.97
Indirect Installation Costs        ...................  ................
    General Facilities...........  0.05 x A...........              7.60
    Engineering and Home Office    0.10 x A...........             15.20
     Fees.
    Process Contingencies........  0.05 x A...........              7.60
Total Indirect Installation        0.20 x A...........             30.39
 Costs, B.
Project Contingency, C...........  0.15 x (A + B).....             27.36
Total Plant Cost, D..............  A + B + C..........            212.53
Preproduction Cost, G............  0.02 x D...........              4.25
Inventory Capital (Reagent), H...  ...................             0.087
Natural Gas Pipeline.............  ...................              2.81
                                  --------------------------------------
    Total Capital Investment, TCI  ...................            216.87
     = D + G + H.
------------------------------------------------------------------------
\1\ See Table 46 for an explanation of Scenarios.

 Table 45--Summary of EPA NOX BART Annual Costs for TESCR Scenario 3 \1\
                            on Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost ($) \2\
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........              3.25
Reagent..........................  ...................             0.396
Catalyst.........................  ...................             0.425
Electricity......................  ...................              3.96
Natural Gas for Flue Gas           ...................              6.00
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various                  17.82
     (TDAC).                        Items Listed Above.
Indirect Annual Cost \3\ (IDAC)..  CRF x TCI..........             18.91
Annual ASOFA Cost (AAC)..........  ...................              3.84
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC + AAC..             40.57
------------------------------------------------------------------------
\1\ See Table 46 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.0872 and is based on a 6%
  interest rate and 20 year equipment life. From Minnkota NOX BACT
  Analysis Study, Milton R. Young Station Unit 1, Table C.1-1, p. C1-4,
  October 2006 (provided in BART Determination Study for Milton R. Young
  Station Units 1 and 2, October 2006, SIP Appendix C.4).

  Table 46--Summary of EPA NOX BART Costs for Various TESCR + ASOFA Scenarios on Milton R. Young Station Unit 2
                                                     Boiler
----------------------------------------------------------------------------------------------------------------
                                                                Emissions                         Average cost
              Scenario                    Description        reductions \1\     Total annual    effectiveness ($/
                                                               (tons/year)       cost ($MM)           ton)
----------------------------------------------------------------------------------------------------------------
1..................................  1 layer replaced                 14,825             43.63             2,943
                                      every year.
2..................................  1 layer replaced                 14,816             41.89             2,827
                                      every 2 years.
3..................................  1 layer replaced                 14,807             40.57             2,740
                                      every 3 years.
4..................................  ASOFA downtime                   14,829             42.89             2,892
                                      allowed.
----------------------------------------------------------------------------------------------------------------
\1\ Reductions vary based on impacts to boiler availability in each scenario (i.e., lower boiler operating hours
  equate to lower emissions).

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and
operation of the evaluated controls are not significant enough to
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Milton R. Young Station Unit 2 is at
least 20 years. Thus, this factor does not impact our BART
determination.
    Factor 5: Evaluate visibility impacts.
    Minnkota modeled the visibility benefits for SNCR + ASOFA using
natural background per the BART Guidelines, North Dakota then performed
additional modeling for the SCR + ASOFA control option. Minnkota and
North Dakota both provided single-source modeling results using natural
background conditions, complying with the BART Guidelines. The SCR +
ASOFA option, when combined with wet scrubbing for SO2,
would result in a significant improvement in visibility at Theodore
Roosevelt--estimated to be 3.945 deciviews and 110 fewer days above 0.5
deciviews. This represents an incremental visibility improvement of
2.318 deciviews and 58 fewer days above 0.5 deciviews beyond that
achieved by wet scrubbing alone. Moreover, when compared to SNCR +
ASOFA, it would result in an incremental visibility improvement of
0.566 deciviews and 21 fewer days above 0.5 deciviews. North Dakota
conducted supplemental cumulative modeling for SCR at Milton R. Young
Station 2 that is discussed in more detail in section V.D.1.e. For the
reasons described there, we are disregarding North Dakota's alternative
modeling in our analysis. More information on our interpretation of the
State's and source's modeling information is included in the Technical
Support Document.
    Step 5: Select BART.
    We propose to find that BART is SCR + ASOFA at Milton R. Young
Station 2 with an emission limit of 0.07 lb/MMBtu (30-day rolling
average). Of the five BART factors, cost and visibility improvement
were the critical ones in our analysis of controls for this source. We
agree with the State that the other three factors are not relevant to
this BART determination.
    In our BART analysis for NOX at Milton R. Young Station
2, we considered SNCR + ASOFA and SCR + ASOFA. The comparison between
our SNCR analysis and our TESCR Scenario 3 analysis is provided in
Table 47.

                Table 47--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Milton R. Young Station Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2 4
                                                             Total                                         Incremental   -------------------------------
                                                           installed     Total annual     Average cost         cost         Visibility
                    Control option                       capital cost     cost (MM$)     effectiveness    effectiveness     improvement    Fewer days >
                                                             (MM$)                          ($/ton)          ($/ton)          (delta          0.5 dv
                                                                                deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)............................      \3\ 216.9            40.57            2,740            5,695           3.945             110

SNCR + ASOFA..........................................           17.45            6.44              703  ...............           3.379              89
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Minnkota's and the State's modeling for both SNCR and SCR was based on lower emissions reductions (fewer tons removed) than we anticipate; thus, we
  anticipate slightly greater visibility benefits (delta deciview) than reflected in these values. The visibility benefit shown is for the most impacted
  Class I area, Theodore Roosevelt.
\2\ Minnkota and the State conducted the modeling with combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of
  wet scrubbing along with the noted NOX control option.
\3\ This installed capital cost estimate does not include the capital cost of ASOFA. The total annualized cost does include the capital cost of ASOFA.
\4\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    As discussed in more detail in the Technical Support Document, we
have concluded that SNCR + ASOFA and SCR + ASOFA are both cost
effective control technologies and that both would provide substantial
visibility benefits. SNCR + ASOFA has a cost effectiveness value of
$703 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it
has a cost effectiveness value of $2,740 per ton of NOX
emissions reduced. This is well within the range of values we have
considered reasonable for BART and that states other than North Dakota
have considered reasonable for BART. Even with more frequent catalyst
replacement, SCR would still be cost effective even at the high end of
the range ($2,892 per ton) allowing for the most frequent catalyst
replacement of one layer per year and allowing for the questionable
costs of lost power generation revenue in TESCR Scenario 4. We also
analyzed the SCR costs assuming the same baseline emissions of 15,507
tons per year used by North Dakota and determined that the high-end
cost effectiveness value, assuming the most frequent catalyst
replacement frequency, would be about $2,949 per ton of NOX
reduced. All of these cost effectiveness values are well within the
range of values that North Dakota considered reasonable in several of
its NOX BART determinations, where predicted visibility
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at
Milton R. Young Station Unit 2, as modeled by Minnkota and the State.
Both sets of controls would have a positive impact on visibility. As
compared to SNCR + ASOFA, SCR + ASOFA would provide an additional
visibility benefit of 0.566 deciview at Theodore Roosevelt and 21 fewer
days above 0.5 deciviews. We consider these impacts to be substantial,
especially in light of the fact that neither of these Class I areas is
projected to meet the uniform rate of progress. We also note that the
0.566 deciview improvement at Theodore Roosevelt is greater than the
improvement in visibility that North Dakota found reasonable to support
other NOX BART determinations in the SIP, at higher cost
effectiveness values. Given the visibility improvement associated with
SCR + ASOFA, the relatively low incremental cost effectiveness between
the two control options ($6,045 per ton), and the reasonable average
cost effectiveness values for SCR + ASOFA, we propose that the
NOX BART emission limit for Milton R. Young Station 2 should
be based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted
the annual design rate of 0.05 lb/MMBtu upwards to allow for a
sufficient margin of compliance for a 30-day rolling average limit that
would apply at all times, including during startup, shutdown, and
malfunction.\51\ We are also proposing monitoring, recordkeeping, and
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \51\ As discussed in the BART Guidelines, section V (70 FR
39172, July 6, 2005), and Section 302(k) of the CAA, emissions
limits such as BART are required to be met on a continuous basis.
---------------------------------------------------------------------------

    As we have noted previously, under section 51.308(e)(1)(iv), ``each
source subject to BART [is] required to install and operate BART as
expeditiously as practicable, but in no event later than 5 years after
approval of the implementation plan revision.'' Based on the retrofit
of other SCR installations we have reviewed, we propose a compliance
deadline of five (5) years from the date our final FIP becomes
effective.
4. BART Analysis for Leland Olds Station 2
    Step 1: Identify All Available Technologies.
    As with the Milton R. Young Station Units, our analysis for Leland
Olds Unit 2 only considers SNCR + ASOFA and SCR + ASOFA. Because the
State selected SNCR + ASOFA as BART, and our concern is that the State
did not properly evaluate SCR as BART, there is no need to consider
lower-performing technologies.
    Step 2: Eliminate Technically Infeasible Options.
    We are not eliminating either SNCR or SCR as being technically
infeasible. Both technologies have been widely employed to control
NOX emissions from coal-fired power plants. The State
determined SNCR was technically feasible for North Dakota EGUs. We
agree with the State that SNCR is technically feasible. The State also
determined, in Section 7 of the SIP, that two forms of SCR are
technically feasible for use on North Dakota EGUs burning lignite coal.
The State based its conclusion on an analysis it provided in Appendix
B.5 to its Regional Haze SIP.
    For further discussion concerning the technical feasibility of SCR,
please see our NOX BART analysis and determination for
Milton R. Young Station Unit 1 and our Technical Support Document.
    Step 3: Evaluate Control Effectiveness of Remaining Control
Technologies.
    For the purposes of our SNCR + ASOFA cost analysis, we used a
control efficiency of 54% and an emission rate of 0.305 lb/MMBtu, the
same control efficiency that North Dakota used. For our TESCR + ASOFA
cost analysis we used a control efficiency of 93% and an emission rate
of 0.05 lb/MMBtu, instead of North Dakota's 90% control efficiency and
0.07 lb/MMBtu emission

rate. We find that SCR technology, by itself, can achieve 90% control
efficiency and that the overall NOX reduction would be even
greater (93%) with the use of combustion controls in combination with
SCR. A summary of emissions and the two control options is provided in
Table 48.

      Table 48--Summary of EPA NOX BART Analysis Control Technologies for Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                                Emissions
             Control option                   Control      Emission rate (lb/ Emissions (tons/  reduction (tons/
                                          efficiency (%)         MMBtu)              yr)               yr)
----------------------------------------------------------------------------------------------------------------
TESCR + ASOFA..........................                93              0.05                900            12,100
SNCR + ASOFA...........................                54              0.305             5,900             7,100
No Controls (Baseline).................                 0              0.67         \1\ 13,000  ................
----------------------------------------------------------------------------------------------------------------
\1\ We calculated our baseline using the same method used by Sargent & Lundy in its May 2009 report, but we
  adjusted the capacity factor downward to 86.5%.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Cost of compliance.
    SNCR + ASOFA.
    We are not relying on North Dakota's costs for SNCR. Though the
North Dakota costs, developed by Sargent & Lundy on behalf of Basin
Electric, are generally consistent with the Control Cost Manual, at
least one cost, related to lost revenue due to outage, is not. To
ensure a fair comparison between the two competing technologies, we
have re-worked the costs for SNCR.
    We relied on Sargent & Lundy's estimate for total capital
investment costs but adjusted them for 2009 dollars.\52\ Then, we
generally used factors and assumptions for annual costs provided by the
Control Cost Manual. In the absence of a Control Cost Manual method for
combustion controls, we used all the costs that North Dakota provided
for ASOFA.
---------------------------------------------------------------------------

    \52\ We obtained capital costs from the company's BART analysis
in Appendix C of the SIP. Adjustment to 2009 dollars was
accomplished using the Chemical Engineering Plant Cost Index (CEPCI)
for 2009 and 2006 (521.9/499.6=1.044). Available from Chemical
Engineering Magazine (http://www.che.com).
---------------------------------------------------------------------------

    This is the same approach we used to analyze the costs for TESCR at
Leland Olds Station 2, which enables us to compare the costs of SNCR
and TESCR on a consistent basis. Our effort to re-estimate the costs
for SNCR was not exhaustive, but it did result in a downward adjustment
in the cost estimate for SNCR. We deem the analysis adequate for
comparing the cost effectiveness values of the two top control
options--SCR and SNCR.
    Regarding specific elements in our cost analysis, we used $475 per
ton to estimate urea costs and did not allow for lost revenue due to
outage because the Control Cost Manual does not allow for lost revenue
due to outage. To estimate the average cost effectiveness (dollars per
ton of emissions reductions), we divided the total annualized cost by
the estimated NOX emissions reductions. We summarize our
costs from our SNCR cost analysis in Tables 49, 50, and 51. See the
Technical Support Document for our full analyses.

   Table 49--Summary of EPA NOX BART Capital Cost Analysis for SNCR on
                    Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Capital Investment ASOFA, A......  ...................        11,440,000
Capital Investment SNCR, B.......  ...................         7,800,000
                                  --------------------------------------
    Total Capital Investment, TCI  A + B..............        19,240,000
     (2009$).
------------------------------------------------------------------------

 Table 50--Summary of EPA NOX BART Annual Costs for SNCR on Leland Olds
                          Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Annual Maintenance...............  .015 x TCI.........           117,000
Reagent..........................  ...................         2,704,208
Electricity......................  ...................            44,656
Water............................  ...................             2,183
Increased Coal...................  ...................            83,927
Increased Ash....................  ...................             6,117
                                  --------------------------------------
    Total Direct Annual Cost       Sum of Various              2,958,090
     (TDAC).                        Items Listed Above.
                                  --------------------------------------
Indirect Annual Cost \1\ (IDAC)..  CRF x TCI..........           736,265
                                  --------------------------------------
    Total Annual Cost SNCR (TACS)  TDAC + IDAC........         3,694,355
                                  --------------------------------------
    Total Annual Cost ASOFA \2\    ...................         1,256,855
     (TACA).
                                  --------------------------------------
    Total Annual Cost SNCR +       TACS + TACA........         4,951,210
     ASOFA.
------------------------------------------------------------------------
\1\ Capital Recovery Factor (CRF) is 0.0944 and is based on a 7%
  interest rate and 20 year equipment life. Office of Management and
  Budget, Circular A-4, Regulatory Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.

\2\ Calculated from Table 2.5-2, Basin Electric letter, May 29, 2009,
  Appendix C.1.

              Table 51--Summary of EPA NOX BART Costs for SNCR on Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                              Total installed       Total          Emissions       Average cost
               Control option                   capital cost   annualized cost     reductions     effectiveness
                                                   (MM$)            (MM$)          (tons/yr)         ($/ton)
----------------------------------------------------------------------------------------------------------------
SNCR + ASOFA................................           19.24             4.95            7,100              700
----------------------------------------------------------------------------------------------------------------

    TESCR + ASOFA.
    Dr. Phyllis Fox, PhD, PE, as subcontractor to our contractor, RTI,
prepared a cost analysis for TESCR for Leland Olds Station Unit 2. Dr.
Fox started with the cost information in the Sargent & Lundy letter
report dated May 27, 2009 with Basin Electric cover letter dated May
29, 2009. See SIP Appendix C.1. As described in greater detail below,
while Dr. Fox relied on Sargent & Lundy's estimate for total capital
investment for TESCR equipment and for the unit cost for catalyst, she
adjusted Sargent & Lundy's assumptions for various other costs to make
them consistent with the Control Cost Manual and reasonable costing
assumptions.
    TESCR + ASOFA Capital Costs.
    The May 27, 2009 Sargent & Lundy Cost Analysis reports a capital
cost range of $165,800,000 to $170,800,000 for installed capital costs
for TESCR + ASOFA in 2009 dollars.\53\ Sargent & Lundy calculated these
costs from a lump sum unit capital cost estimate expressed in dollars
per kilowatt of electricity generated. These costs are significantly
higher than costs reported for similar installations.\54\ We were not
able to determine the basis for the deviation because Sargent & Lundy
did not provide support for its unit capital cost estimate. Contrary to
common practice, Sargent & Lundy did not separately identify equipment
(e.g., reactor housing, ducts, bypass, NH3 injection system,
sonic horns, etc.) and installation costs. Nonetheless, we used Sargent
& Lundy's total capital investment estimate as the basis for our
analysis, with the exception of the total capital costs for sorbent
injection.\55\ The result is a cost estimate that should represent the
upper bound of likely costs.
---------------------------------------------------------------------------

    \53\ 5/27/09 S&L Cost Analysis, Table 2.5-2.
    \54\ Data indicates that Sargent & Lundy's estimate of capital
costs to retrofit SCR at Leland Olds ($373/kW in 2010 dollars) is
higher than actual installed costs for existing retrofit SCRs,
including those with extreme retrofit difficulty and those requiring
flue gas reheat. For further detail, please see our Technical
Support Document. Thus, we consider our resulting cost effectiveness
value to be conservative in favor of Basin Electric and to represent
an upper bound for installation and operation of an SCR on LOS Unit
2. Put another way, we believe the cost effectiveness of SCR on LOS
Unit 2 is more favorable than our estimate suggests.
    \55\ Dr. Fox concluded that a sorbent injection system would not
be needed to reduce sulfuric acid mist because low conversion
catalysts are available and because tail-end SCR would operate at a
much lower temperature than high-dust SCR, which would significantly
reduce the conversion of SO2 to SO3. Dr. Fox
concluded that the conversion could be kept below the significance
level. Our rationale for excluding sorbent injection is further
discussed in our Technical Support Document.
---------------------------------------------------------------------------

    For our analysis, we used a total installed capital cost estimate
of $164,676,000 in 2009 dollars. This includes the cost of ASOFA but
not the cost of a dry sorbent injection control system. This estimate
is based primarily on the Sargent & Lundy lump sum unit capital cost
estimate expressed in dollars per kilowatt of electricity generated,
$350/kW, in 2009 dollars.
    TESCR + ASOFA Annual Costs.
    As previously discussed, the total capital cost is annualized using
a capital recovery factor. This value is then summed with estimated
annual operating and maintenance costs to arrive at a value for total
annual costs.
    Using an appropriate capital recovery factor of 0.08718, Dr. Fox
calculated an annualized capital cost of $14,356,000 in 2009 dollars.
Dr. Fox estimated that total annual operating and maintenance costs
would be $22,090,000. Sargent & Lundy's estimate of variable operating
and maintenance costs (NH3, catalyst, power, natural gas,
outage cost, and sorbent injection) was three to five times higher than
Dr. Fox's estimate.
    Below, we provide further detail regarding some of the major
assumptions and reasoning underlying our estimate of annual operating
and maintenance costs.\56\
---------------------------------------------------------------------------

    \56\ Contrary to Sargent & Lundy's approach, Dr. Fox did not
``levelize'' annual costs. As explained more fully in our evaluation
of the State's NOx BART determinations for MRYS Units 1 and 2 and
LOS Unit 2, the Control Cost Manual does not provide for
levelization of annual costs.
---------------------------------------------------------------------------

Costs Related to Catalyst
Catalyst Lifetime
    As noted already, an SCR catalyst must be changed out periodically.
Information regarding catalyst life that we relied on for our cost
analysis for Milton R. Young Station Units 1 and 2 is also relevant
here. Leland Olds Station Unit 2 burns similar North Dakota lignite in
a similar cyclone boiler. We note that Dr. Fox examined information
related to catalyst life at Milton R. Young Station and independently
considered relevant data and information to conclude that 24,000 hours
is a reasonable assumption for catalyst life at Leland Olds Station.
This is what Dr. Fox used for her cost analysis for Leland Olds Station
Unit 2. Dr. Fox rejected Sargent & Lundy's estimate that catalyst life
would only be six to 12 months; she found that Sargent & Lundy's
estimate was based on a number of faulty assumptions. For further
detail regarding catalyst life, please see our BART analysis and
determination for Milton R. Young Station Unit 1 and our Technical
Support Document.
    Although we are confident that 24,000 hours represents a
conservative assumption for catalyst life at Leland Olds Station Unit
2, we have also prepared cost estimates using 8,000 and 16,000 hours as
assumptions for catalyst life in order to determine the sensitivity of
costs to this variable. Further information is provided below.
Number of Catalyst Layers
    The catalyst volume required to achieve a given NOX
level is typically divided into layers that can be separately replaced.
Most SCR designs include an empty layer that can be filled with
catalyst as the need arises. The most common configuration is two
active layers with one spare. Initially, two layers are filled with
catalyst. The third layer is added at the end of the initial catalyst
lifetime.
    We assumed an initial configuration of two filled and one empty
layer of catalyst in our cost analysis, which is consistent with the
design of modern SCRs. The empty layer would be filled after 24,000
hours, the assumed catalyst life.
Time Value of Money
    The Control Cost Manual explains that the future worth factor
should be used to amortize catalyst cost over the years preceding the
actual catalyst purchase. As money is allocated in advance of purchase,
the sum of the

annual catalyst replacement cost is less than the purchase price of the
catalyst. Thus, we have multiplied the catalyst purchase price by a
future worth factor. Assuming an interest rate of 7%, a catalyst life
of 24,000 hours, and a capacity factor of 86.5%, the future worth
factor is 0.31.\57\
---------------------------------------------------------------------------

    \57\ Cost Manual, pdf 489-490, Eqn. 2.52: FWF = 0.07[1/(1.07\3\-
1)] = 0.31. Y = 24,000 hr/(8760)(0.865) = 3.2, rounds to 3.
---------------------------------------------------------------------------

Unit Catalyst Cost
    We have assumed a cost of $7,500 per cubic meter of catalyst ($/
m\3\), which is the same cost assumed in Sargent & Lundy's analysis.
This is very high compared to values typically quoted by vendors,
$4,500/m\3\-$6,500/m\3\, depending upon volume per order.\58\ While we
find that $7,500/m\3\ is high, we did not have access to specific
vendor quotes for this element due to confidentiality claims. This is
another element that makes our cost estimate conservatively high.
---------------------------------------------------------------------------

    \58\ Letter from Callie A. Videtich, Director, Air Program, EPA
Region 8, to Terry O'Clair, Director, Division of Air Quality, North
Dakota Department of Health, Re: EPA Region 8 Comments on December
2009 Draft Regional Haze SIP (Public Comment Version), January 8,
2010, Enclosure 2, p. 28; e-mail from Anthony C. Favale, Director--
SCR Products, Hitachi Power Systems America, Ltd., to Anita Lee,
U.S. EPA, Region 9, Re: CX Catalyst Question, April 1, 2010 ($5,500/
m\3\ to $6,000/m\3\); e-mail from Flemming Hansen, Manager SCR DeNOx
Catalyst, Haldor T[oslash]psoe, to Phyllis Fox, P.E., Re: Catalyst
Cost, January 23, 2008 ($6,000/m\3\).
---------------------------------------------------------------------------

Catalyst Volume
    Sargent & Lundy assumed a catalyst volume of 530 m\3\ in its cost
calculations.\59\ The Sargent & Lundy spreadsheets produced in response
to our CAA section 114 request indicate that this figure was derived by
arbitrarily increasing a catalyst volume of 440 m\3\ by 20%.\60\ The
source of the starting point (440 m\3\) and the 20% adjustment are not
disclosed.
---------------------------------------------------------------------------

    \59\ 5/27/09 S&L Cost Analysis, p. 7.
    \60\ See, e.g., Sargent & Lundy spreadsheet: low-high dust scr-
leland old2--Sens2-cat life--05109.xls, cell E25 (440x1.20).
---------------------------------------------------------------------------

    As we commented on the draft Regional Haze SIP, the value of 530
m\3\ is high for a TESCR. Typically, cyclone fired units require about
1.5 m\3\ of catalyst per MW for a high-dust SCR, while TESCRs require
less than half the catalyst volume of a high-dust SCR.\61\ Thus, one
would expect a catalyst volume of about 330 m\3\ for Leland Olds
Station Unit 2. However, we used the unadjusted catalyst volume of 440
m\3\ from Sargent & Lundy's spreadsheets as a highly conservative upper
bound.
---------------------------------------------------------------------------

    \61\ 1/8/10 EPA Comments, Enclosure 1, p. 27.
---------------------------------------------------------------------------

Catalyst Changeout Time
    First, a special outage to change out the catalyst would not be
required. The catalyst can be changed out during scheduled major
outages, which occur every 3 years. The first catalyst change would
occur 3 years after installation. Thus, careful planning would align
the first and subsequent changes with major outages, requiring no lost
generation charges.
    Second, the estimated catalyst exchange rate for a TESCR on the
similar Milton R. Young Station units was 2.2 days for Unit 1 (257 MW)
and 3.8 days for Unit 2 (477 MW).\62\ Based on these values, the
proportional exchange time for Leland Olds Station Unit 2 is 3.6 days.
This is generally consistent with industry experience. Alternatively,
as the boiler is typically down for cleaning 3 to 4 times per year for
a period of about 4 days each time, this downtime would be sufficient
to exchange a layer should one be required before a major outage. SCR
systems are designed to minimize unit downtime to minimize operating
costs.
---------------------------------------------------------------------------

    \62\ Hartenstein Report, April 2010, p. 36.
---------------------------------------------------------------------------

    Thus, we assumed there would be no lost generation during catalyst
replacement because it would be prudent design and operating practice
to schedule these events during routinely scheduled maintenance
outages.
Cost of Utilities and Supplies
    We have included costs for NH3, the reagent used in the
SCR, and natural gas, used to reheat the flue gas. Our costs for these
items do not reflect potential changes in future commodity prices. This
is because cost effectiveness methodology is based on the current
annualized cost without escalation. The Control Cost Manual approach,
recommended by the BART Guidelines, explicitly excludes future
escalation because cost comparisons are made on a current real dollar
basis. Inflation is not included in cost effectiveness analyses as
these analyses rely on the most accurate information available at
current prices and do not try to extrapolate those prices into the
future.\63\
---------------------------------------------------------------------------

    \63\ See, e.g., Cost Manual, p. 2-36, pdf 50.
---------------------------------------------------------------------------

Ammonia (NH3)
    Recent BART analyses have used values in the range of $450 per ton.
Black & Veatch, an engineering firm that designs SCRs, used an
anhydrous ammonia cost of $450 per ton in a September 2010 BART
analysis for Boardman.\64\ Sargent & Lundy used an anhydrous ammonia
cost of $475 per ton in a September 2010 BART analysis for the Navajo
Generating Station.\65\ We used $475 per ton for the cost of
NH3.
---------------------------------------------------------------------------

    \64\ Black & Veatch, Portland General Electric Boardman Plant,
Best Available Retrofit Technology (BART)/Reasonable Progress
Analysis Revision 3: Boardman 2020 Alternative, August 27, 2010,
Table 2-2.
    \65\ Sargent & Lundy, Salt River Project Navajo Generating
Station--Units 1, 2, 3, SCR and Baghouse Capital Cost Estimate
Report, Revision D, August 17, 2010, pdf 58, Table 9-2.
---------------------------------------------------------------------------

Natural Gas
    The temperature of the flue gas exiting the wet scrubber must be
raised to SCR operating temperature. There is more than one method for
doing this. One method uses natural gas. The other uses steam. The cost
of reheating the flue gas is typically one of the most significant
operating costs for a TESCR.
    Steam has important advantages over natural gas for use in flue gas
reheating: lower cost, no increase in flue gas flow rate from gas
combustion byproducts, no moisture condensation on the catalyst, and no
risk of re-vaporization of catalyst poisons in the flame of a duct
burner. Most TESCRs in Europe use steam for reheating.\66\ Vendors in
the Milton R. Young Station case uniformly recommended the use of a
steam coil in place of natural gas-fired duct burners.\67\ However,
Sargent & Lundy did not evaluate the use of steam, and we lack the
information needed to accurately calculate the cost of steam. Thus, we
assumed the use of natural gas in our cost estimates. This is another
indication that our estimate is conservative.
---------------------------------------------------------------------------

    \66\ 1/8/10 EPA Comments, Enclosure 1, p. 25.
    \67\ See, e.g., Hartenstein Report, April 2010, pp. 34-35, 40-
43.
---------------------------------------------------------------------------

    Operating experience with numerous TESCRs in Europe over the past
20 years indicates that an increase of 20 to 25 degrees F is adequate
for reheat.\68\ Further, an SCR operating temperature of 525-550
degrees F is sufficient for a TESCR as the flue gas SO2
concentrations after the wet scrubber are low, eliminating the concern
with deposition of ammonia salts on the catalyst.\69\ Burns & McDonnell
estimated a natural gas firing rate of 66.4

MMBtu/hr for TESCR on Milton R. Young Station Unit 2.\70\ The Burns &
McDonnell estimate is consistent with European experience. Thus, we
used 66.4 MMBtu/hr in our cost analysis.
---------------------------------------------------------------------------

    \68\ Hartenstein Report, April 2010, p. 40.
    \69\ McIlvaine, Next Generation SCR Choices--High-Dust, Low-Dust
and Tail-End, FGD & DeNOx Newsletter, No. 369, January 2009; 5/6/08
Cochran (CERAM) e-mail, p. 2 (``Ammonia should not be injected below
the minimum operating temperatures (MOT). Based on the SO2 to SO3
reported the MOT would be approximately 600 F. For lower sulfur
fuels [such as ND lignite] and/or reduced NOX removal
performance a lower MOT would be possible. Additionally, brief
periods of operation below the MOT would be possible without
permanent degradation. In no event would any ammonia be allowed to
be injected below 530 F for any likely combination of reasonable
sulfur and NOX removal parameters.''), in 5/8/08 Milton
R. Young Additional Information.
    \70\ Burns & McDonnell, Technology Feasibility Analysis and Cost
Estimates for Leland Olds Station Unit 1 and 2, Basin Electric Power
Cooperative, Final Draft, December 2005, p. 86.
---------------------------------------------------------------------------

    Next, we determined an appropriate price assumption for natural
gas. As noted, BART cost effectiveness analyses are based on the best
estimate of current costs at the time of the analysis and do not
consider future escalation. As cost effectiveness is determined
relative to other similar sources, future escalation in gas prices
would affect all natural gas users, not just Leland Olds Station.
    The most recent data reported to the Energy Information Agency
(EIA) indicates that the cost of natural gas to electric power
consumers in North Dakota has ranged from $4.48/MMBtu (October 2010) to
$5.37/MMBtu (June 2010).\71\ As very little natural gas is currently
used in North Dakota, a more reasonable estimate for a dedicated supply
is the Henry Hub spot price plus transportation cost. The 2010 Henry
Hub price of natural gas is $4.37/MMBtu.\72\ The expected Henry Hub
natural gas spot price for 2011 is $4.16/MMBtu, or $0.21/MMBtu lower
than 2010. The Energy Information Agency expects the natural gas market
to begin to tighten in 2012, with the Henry Hub spot price increasing
to an average of $4.58/MMBtu.\73\ Transportation cost is typically less
than $1/MMBtu. Thus, a reasonable estimate for purposes of our analysis
is about $5.50/MMBtu.
---------------------------------------------------------------------------

    \71\ EIA, Natural Gas Monthly:http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/natural_gas_monthly/ngm.html.
    \72\ http://tonto.eia.gov/dnav/ng/hist/rngwhhda.htm.
    \73\ http://www.eia.doe.gov/analysis/ and http://www.eia.gov/emeu/steo/pub/contents.html.
---------------------------------------------------------------------------

Power
    An SCR increases power demand for auxiliary equipment, including
the induced draft fans used to overcome the increase in backpressure
from the SCR plus electricity to run the NH3 system,
dilution air blower, dilution air heaters, and seal air fans. Thus,
auxiliary power is the electricity required to run the plant, or
electricity not sold.
    This cost is estimated by multiplying the electricity demand in
kilowatts by the cost of electricity in dollars per megawatt hour
(MWh). Cost effectiveness analyses are based on the cost to the owner
to generate electricity, or the busbar cost, not market retail rates.
The unit cost of electricity used by Sargent & Lundy, $50/MWh, is high
for a lignite-fired boiler built near its fuel source. Burns &
McDonnell assumed $38/MWh in the 2005 Feasibility Analysis for Leland
Olds \74\ and $35/MWh for Milton R. Young Unit 1.\75\ We used $38/MWh,
the value Burns & McDonnell reported for Leland Olds.
---------------------------------------------------------------------------

    \74\ Burns & McDonnell, Technology Feasibility Analysis and Cost
Estimate for Leland Olds Station Unit 1 and 2, Basin Electric Power
Cooperative, Final Draft, December 2005, p. 86.
    \75\ Burns & McDonnell, NOX Best Available Control
Technology Analysis Study--Supplemental Report for Milton R. Young
Station Unit 1, Minnkota Power Cooperative, Inc., November 2009, p.
4-42.
---------------------------------------------------------------------------

Capacity Factor
    The capacity factor is the fraction of the available capacity that
is actually used. It is calculated as the ratio of the actual
electrical output to its full capacity, typically over a year. The
emission reductions and variable operating and maintenance costs are
both directly proportional to the capacity factor. The higher the
capacity factor, the larger the emission reductions and the higher the
variable operating and maintenance costs.
    The BART Guidelines indicate that: ``in the absence of enforceable
limitations, you calculate baseline emissions based upon continuation
of past practice.'' \76\ The Sargent & Lundy analysis calculated the
capacity factor assuming the unit would operate at full capacity at all
times except during catalyst change-outs. This resulted in capacity
factors of 92% to 96%, which are higher than operating experience.
---------------------------------------------------------------------------

    \76\ 70 FR 39167 (July 6, 2005).
---------------------------------------------------------------------------

    Dr. Fox calculated a capacity factor of 86.5%. This was based on a
comparison of Leland Olds Station Unit 2's actual electrical output for
a baseline period, obtained from monthly Clean Air Markets data, to its
rated capacity (440 MW).\77\ This 86.5% value was used to calculate
NOX emission reductions and variable operating and
maintenance costs.
---------------------------------------------------------------------------

    \77\ Capacity factor = 3,334,426 MWh/[(440)(8760)] = 0.865.
---------------------------------------------------------------------------

NOX Emission Reduction

    In our calculations, we assumed TESCR + ASOFA reduced baseline
NOX emissions of 0.67 lb/MMBtu \78\ to 0.05 lb/MMBtu. An SCR
outlet NOX emission rate of 0.05 lb/MMBtu can be readily
achieved by TESCR + ASOFA. The May 27, 2009 Sargent & Lundy analysis
and supporting spreadsheets assumed the combination achieved 0.05 lb/
MMBtu. In the Sargent & Lundy analysis, the SCR was specifically
assumed to reduce NOX from an inlet of 0.48 lb/MMBtu, a
level consistent with performance of Leland Olds Unit 2 since
installation of ASOFA, to 0.05 lb/MMBtu or 90% NOX control.
---------------------------------------------------------------------------

    \78\ North Dakota's BART Determination for Leland Olds Station
Units 1 and 2, SIP Appendix B.1, p. 24.
---------------------------------------------------------------------------

    We added the annual costs for ASOFA to the annual costs for TESCR
to arrive at a total annual cost for the combined controls. To estimate
the average cost effectiveness (dollars per ton of emissions
reductions), we then divided the total annual cost by the estimated
NOX emission reductions. We summarize our cost estimates in
Tables 52, 53 and 54. See our Technical Support Document for the full
analyses.

    Table 52--Summary of EPA NOX BART Capital Cost Analysis for TESCR
             Scenario 3 on Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor          Cost ($)
------------------------------------------------------------------------
Capital Investment (2010$) ASOFA,  ...................        11,440,000
 A.
Capital Investment (2010$) SCR, B  ...................       164,121,000
------------------------------------------------------------------------
Total Capital Investment, TCI      A + B..............       175,561,000
 (2010$).
Total Capital Investment, TCI      TCI(2010) x               164,734,423
 (2009$).                           CEPCI(521.9/556.2).
------------------------------------------------------------------------

Table 53--Summary of Some EPA NOX BART Annual Costs for TESCR Scenario 3
                \1\ on Leland Olds Station Unit 2 Boiler
------------------------------------------------------------------------
           Description                 Cost factor        Cost ($) \2\
------------------------------------------------------------------------
Annual Maintenance...............  .015xTCI...........           823,564
Reagent..........................  ...................         2,115,190
Catalyst.........................  ...................           320,796
Electricity......................  ...................         1,878,814
Natural Gas for Flue Gas           ...................         2,595,446
 Reheating and Urea to Ammonia
 Conversion.
                                  --------------------------------------
    Total Direct Annual Cost       ...................         7,733,810
     (TDAC)..
    Indirect Annual Cost \3\       CRF x TCI..........        14,356,473
     (IDAC).
                                  --------------------------------------
    Total Annual Cost (TAC)......  TDAC + IDAC........        22,090,283
------------------------------------------------------------------------
\1\ See Table 54 for an explanation of Scenarios.
\2\ Costs are in 2009 dollars.
\3\ Capital Recovery Factor (CRF) is 0.08718 and is based on a 6%
  interest rate and 20 year equipment life. From Table 1.2-3, BART
  Determination Study, Leland Olds Units 1 and 2, August 2006, SIP
  Appendix C.1.

Table 54--Summary of EPA NOX BART Costs for Various TESCR + ASOFA Scenarios on Leland Olds Station Unit 2 Boiler
----------------------------------------------------------------------------------------------------------------
                                                                Emissions                         Average cost
            Scenario                    Description            reductions     Total annualized    effectiveness
                                                               (tons/year)       cost  ($MM)         ($/ton)
----------------------------------------------------------------------------------------------------------------
1..............................  1 layer replaced every               12,050             24.31             1,892
                                  year.
2..............................  1 layer replaced every 2             12,050             23.74             1,848
                                  years.
3..............................  1 layer replaced every 3             12,050             23.55             1,833
                                  years.
----------------------------------------------------------------------------------------------------------------

    Factor 2: Energy impacts.
    The additional energy requirements involved in installation and
operation of the evaluated controls are not significant enough to
warrant eliminating either SNCR or SCR.
    Factor 3: Non-air quality environmental impacts.
    The non-air quality environmental impacts are not significant
enough to warrant eliminating either SNCR or SCR.
    Factor 4: Remaining useful life.
    The remaining useful life of Leland Olds Station Unit 2 is at least
20 years. Thus, this factor does not impact our BART determination.
    Average cost effectiveness for each option.
    To estimate the average annual cost effectiveness (dollars per ton
of emissions reductions), we divided the total annual cost by the
estimated NOX emissions reductions. These estimates are
noted in our summary in Table 55. Our average annual cost effectiveness
estimate for SNCR + ASOFA at Leland Olds Station Unit 2 is $700 per ton
of NOX reductions. Our average annual cost effectiveness
estimate for SCR + ASOFA at Leland Olds Station Unit 2 is $1,833 per
ton of NOX reductions.
    Step 5: Evaluate Visibility Impacts.
    Basin Electric modeled the visibility benefits for SNCR + ASOFA
using natural background per the BART Guidelines. North Dakota then
performed additional modeling for the SCR + ASOFA control option. Basin
Electric and North Dakota both provided single-source modeling results
using natural background conditions, complying with the BART
Guidelines. The SCR + ASOFA option, when combined with FGD at 95% for
SO2, would result in a significant improvement in visibility
at Theodore Roosevelt, estimated to be 4.393 deciviews and 130 fewer
days above 0.5 deciviews. As the State did not provide discrete
modeling for individual pollutants, it is not possible to describe the
incremental visibility benefits of SCR + ASOFA or other NOX
control options over the selected SO2 BART control (FGD at
95%). Nonetheless, when compared to SNCR + ASOFA, SCR would result in
an incremental visibility improvement of 0.512 deciviews and 25 fewer
days above 0.5 deciviews. North Dakota conducted supplemental
cumulative modeling for SCR at Milton R. Young Station 1 that is
discussed in more detail in section V.D.1.e. For the reasons described
there, we are disregarding North Dakota's alternative modeling in our
analysis.
    More information on our interpretation of the State's and source's
modeling information is included in the Technical Support Document.
    Step 6: EPA BART Determination for Leland Olds Station 2.
    We propose to find that BART is SCR + ASOFA at Leland Olds Station
2 with an emission limit of 0.07 lb/MMBtu (30-day rolling average). Of
the five BART factors, cost and visibility improvement were the
critical ones in our analysis of controls for this source. We agree
with the State that the other three factors are not relevant to this
BART determination.
    The comparison between our SNCR + ASOFA analysis and our TESCR +
ASOFA Scenario 3 analysis is provided in Table 55.

                  Table 55--Summary of EPA NOX BART Analysis Comparison of TESCR and SNCR Options for Leland Olds Station Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1, 2
                                                             Total                                         Incremental   -------------------------------
                                                           installed         Total        Average cost         cost         Visibility
                    Control option                       capital cost     annualized     effectiveness    effectiveness     improvement    Fewer days >
                                                             (MM$)        cost  (MM$)       ($/ton)          ($/ton)          (delta          0.5  dv
                                                                                deciviews)
--------------------------------------------------------------------------------------------------------------------------------------------------------
TESCR + ASOFA (Scenario 3)............................          164.68           22.09            1,833            3,489           4.393             130
SNCR + ASOFA..........................................           19.24            4.95              700  ...............           3.874             105
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The visibility modeling that North Dakota (for SCR) and Basin Electric (all scenarios but SCR) performed for Leland Olds Station Unit 2 included SO2
  control (FGD 95%) in addition to the noted NOX control. Thus, these values do not reflect the distinct visibility benefit from the NOX control options
  but do provide the incremental benefit between the options.
\2\ The visibility improvement described in this table represents the change in the maximum 98th percentile impact over the modeled 3-year
  meteorological period (2001-2003) at the highest impacted Class I area, Theodore Roosevelt. Similarly, the number of days above 0.5 deciviews is the
  total for the modeled 3-year meteorological period at Theodore Roosevelt.

    We have concluded that SNCR + ASOFA and SCR + ASOFA are both cost
effective control technologies and that both would provide substantial
visibility benefits. SNCR + ASOFA has a cost effectiveness value of
$700 per ton. While SCR + ASOFA is more expensive than SNCR + ASOFA, it
has a cost effectiveness value of $1,833 per ton of NOX
emissions reduced. This is well within the range of values we have
considered reasonable for BART and that states other than North Dakota
have considered reasonable for BART. Even if we assume a catalyst
replacement frequency of one layer per year, which we find is highly
unlikely, SCR would still be cost effective ($1,892 per ton). We also
analyzed the SCR costs assuming the same baseline emissions of 12,023
tons per year used by North Dakota and determined that the high-end
cost effectiveness value, assuming the most frequent catalyst
replacement frequency, would be about $2,035 per ton of NOX
reduced. All of these cost effectiveness values are well within the
range of values that North Dakota considered reasonable in several of
its NOX BART determinations, where predicted visibility
improvement was considerably lower.
    We have weighed costs against the anticipated visibility impacts at
Leland Olds Station 2. Both sets of controls would have a positive
impact on visibility. As compared to SNCR + ASOFA, SCR + ASOFA would
provide an additional visibility benefit 0.512 deciviews and 25 fewer
days above 0.5 deciviews at Theodore Roosevelt. We consider these
impacts to be substantial, especially in light of the fact that neither
of these Class I areas are projected to meet the uniform rate of
progress. We also note that the 0.512 deciview improvement at Theodore
Roosevelt is greater than the improvement in visibility that North
Dakota found reasonable to support other NOX BART
determinations in the SIP, at higher cost effectiveness values. Given
the appreciable incremental visibility improvement associated with SCR
+ ASOFA, the relatively low incremental cost effectiveness between the
two control options ($3,489 per ton), and the reasonable average cost
effectiveness values for SCR + ASOFA, we propose that the
NOX BART emission limit for Leland Olds Station 2 should be
based on SCR + ASOFA.
    In proposing a BART emission limit of 0.07 lb/MMBtu, we adjusted
the annual design rate of 0.05 lb/MMBtu upwards to allow for a
sufficient margin of compliance for a 30-day rolling average limit that
would apply at all times, including during startup, shutdown, and
malfunction.\79\ We are also proposing monitoring, recordkeeping, and
reporting requirements in regulatory text at the end of this proposal.
---------------------------------------------------------------------------

    \79\ As discussed in the BART Guidelines, section V (70 FR
39172, July 6, 2005), and Section 302(k) of the CAA, emissions
limits such as BART are required to be met on a continuous basis.
---------------------------------------------------------------------------

    As we have noted previously, under section 51.308(e)(1)(iv), ``each
source subject to BART [is] required to install and operate BART as
expeditiously as practicable, but in no event later than 5 years after
approval of the implementation plan revision.'' Based on the retrofit
of other SCR installations we have reviewed, we propose a compliance
deadline of five (5) years from the date our final FIP becomes
effective.

    Note regarding SCR at Milton R. Young Station Units 1 and 2 and
Leland Olds Station Unit 2: Our proposal that SCR is BART at Milton
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 has
been thoroughly analyzed and considered. As we indicate above, the
sources and the State believe that SCR is technically infeasible,
based on their views regarding catalyst deactivation and the lack of
firm vendor guarantees of catalyst life. We disagree with the
sources and the State and have adopted assumptions we and our
consultants consider reasonable regarding SCR catalyst life at these
units. We note that, should we finalize our FIP as proposed,
Minnkota, Basin Electric, and/or the State may request
reconsideration of our final action based on the potential outcomes
of any field testing regarding catalyst life they may choose to
undertake prior to the date the emission limits in our FIP become
effective.

F. Federal Implementation Plan to Address NOX BART for Coal
Creek Station Units 1 and 2

1. Introduction
    As noted above, North Dakota selected SOFA + LNB as NOX
BART for Coal Creek Station Units 1 and 2 but in doing so,
inappropriately eliminated SNCR + SOFA + LNB and SCR + SOFA + LNB as
potential BART based on erroneous cost information for Coal Creek
Station's fly ash sales. Thus, in our proposed FIP, we are re-
evaluating LTO, SCR, SNCR, and low-NOX burners and SOFA as
potential BART. Our analysis follows our BART Guidelines. For Coal
Creek Station Units 1 and 2, the BART Guidelines are mandatory. Coal
Creek Station has a capacity of 1,100 MWs. North Dakota selected low-
NOX burners and SOFA with an associated limit of 0.17 pounds
per million Btu as NOX BART for Coal Creek.
2. BART analysis for Coal Creek Units 1 and 2
    Since Coal Creek Units 1 and 2 are identical, we are considering
average historical data for each unit and then proposing a single BART
determination that applies to each unit.
    Step 1: Identify All Available Technologies.
    Our analysis for Coal Creek Units 1 and 2 considers SOFA + LNB
(combustion controls), and combustion controls in combination with
SNCR, SCR, and LTO.

    Step 2: Eliminate Technically Infeasible Options.
    For the reasons described in our BART analysis and determination
for Milton R. Young Station Units 1 and 2 and Leland Olds Station 2, we
are not eliminating either SNCR or SCR as being technically infeasible.
We are not eliminating any of the other control options as being
technically infeasible. For ease of comparison, we are evaluating LDSCR
(downstream of the particulate control device). This is the option that
North Dakota and Great River Energy (GRE) evaluated, and this location
for the SCR equipment is preferable to a high-dust location (upstream
of the particulate control device) for minimizing the amount of ash and
catalyst poisons that would otherwise be present in the flue gases,
thus increasing catalyst life and decreasing operating costs. A tail-
end location (downstream of the particulate control and the
SO2 wet scrubber control devices) is another feasible
option. (See our BART determinations for Milton R. Young Station and
Leland Olds Station units in sections V.E.2 and V.E.3 for further
discussion of LDSCR and TESCR.) The State determined all options to be
technically feasible, including LDSCR and TESCR, for North Dakota EGUs.
    Step 3: Evaluate Control Effectiveness of Remaining Control
Technology.
    For the purposes of our SOFA + LNB cost analysis, we used a control
efficiency of 29% and an emission rate of 0.15 lb/MMBtu. In our SNCR +
ASOFA cost analysis, we used a control efficiency of 49% and an
emission rate of 0.108 lb/MMBtu. For our LDSCR + ASOFA cost analysis we
used a control efficiency of 80% and an emission rate of 0.043 lb/
MMBtu. We used the same emission rates as North Dakota and calculated
slightly different efficiency ratings based on an emissions baseline
for years 2000 through 2004. Due to limited time, we did not perform a
separate cost analysis for LTO and are accepting the Great River Energy
cost estimates that North Dakota used. These were based on a control
efficiency of 90% and an emission rate of 0.022 lb/MMBtu. A summary of
emissions and control options is provided in Table 56.

        Table 56--Summary of EPA Coal Creek BART Analysis Control Technologies for Units 1 and 2 Boilers
----------------------------------------------------------------------------------------------------------------
                                                      Control                                        Emissions
                 Control option                     efficiency     Emission rate     Emissions       reduction
                                                        (%)         (lb/MMBtu)       (tons/yr)       (tons/yr)
----------------------------------------------------------------------------------------------------------------
LTO + SOFA + LNB................................              90           0.022             536           4,821
LDSCR + SOFA + LNB..............................              80           0.043           1,084           4,210
SNCR + SOFA + LNB...............................              49           0.108           2,722           2,572
SOFA + LNB......................................              29           0.150           3,780           1,514
SOFA + LNB (Baseline)...........................               0            0.22        5,294\1\  ..............
----------------------------------------------------------------------------------------------------------------
\1\ Calculated average for historic baseline (2000-2004) for Unit 1. Units 1 and 2 comparable in size and
  emissions.

    Step 4: Evaluate Impacts and Document Results.
    Factor 1: Costs of compliance.
    SOFA + LNB.
    We relied on North Dakota's and Great River Energy's cost analysis
for SOFA + LNB. (See SIP, Appendices B.2 and C.2.) Great River Energy
evaluated two slightly different emissions rates. We find that the
lower emission rate (higher control efficiency) and associated costs
are reasonable, and we rely on this information to supplement our other
control option cost analyses. We used an emission rate of 0.151 lb/
MMBtu, with a resulting capital cost of $5.37 million, a total annual
cost of $673,100, and an average cost effectiveness of $412 per ton of
NOX emissions reductions.
    SNCR+ SOFA + LNB.
    We are not relying on North Dakota's costs for SNCR due to the
erroneous fly ash cost information used by Great River Energy, which
the State relied on in its analyses. We prepared a cost analysis for
SNCR for Coal Creek Station Units 1 and 2. As explained below, we have
used some of the cost information provided in a Great River Energy
letter from Ms. Mary Jo Roth to Mr. Terry O'Clair dated July 15, 2011.
The original price for fly ash in Great River Energy's analysis was
$36.00 per ton. (See SIP, Appendix C.2). In its July 15, 2011 letter,