average limit, the State increased the calculated annual emissions rate
of 0.18 lb/MMBtu to 0.24 lb/MMBtu to account for coal variability over
the shorter averaging period. The estimated average cost effectiveness
of the spray dryer with a fabric filter was $1,330 per ton of
SO2 removed, and the capital and annualized costs were
estimated to be $77,840,000 and $11,220,000 per year, respectively.
This control option will result in a significant improvement in
visibility at Theodore Roosevelt, estimated to be 1.007 deciviews and
43 fewer days above 0.5 deciviews.
    SO2 BART Review (Powder River Basin Coal): North Dakota
concluded that the technically feasible control options for Unit 1 are
the same whether the source is burning lignite or Powder River Basin
coal. North Dakota conducted its analyses based on two different
baseline SO2 emission limits which vary due to anticipated
sulfur content variations in the Powder River Basin coal as the result
of a new coal contract.\16\ The State determined that the incremental
cost of $16,000 per ton (with a 1.2 lb/MMBtu baseline emission rate)
for a circulating dry scrubber compared to a spray dryer was excessive.
In addition, the State considered the incremental cost of over $11,800
per ton (with a 0.64 lb/MMBtu baseline emission rate) for a wet
scrubber as compared to a spray dryer

to be excessive. Therefore, the State removed the wet scrubber and
circulating dry scrubber from further consideration. The State also
found that a wet scrubber would only reduce SO2 emissions by
311 tons per year more than the spray dryer/fabric filter option and
that the incremental visibility improvement would be less than 0.112
deciviews, the value for lignite. A summary of the State's
SO2 BART analysis with Powder River Basin coal is provided
in Table 8.
---------------------------------------------------------------------------

    \16\ Appendix B.3, pp. 17-22, of the SIP describes the basis for
the 1.2 lb/MMBtu and 0.64 lb/MMBtu SO2 baseline emission
rates.

                              Table 8--Summary of Stanton SO2 BART Analysis for Unit 1 Boiler With Powder River Basin Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber.......................................................               95            0.06             5,905            13.18            2,232
Circulating Dry Scrubber...........................................               93            0.084            5,781            14.22            2,460
SD/FF..............................................................               90            0.12             5,594            11.22            2,006
Wet Scrubber with 10% Bypass.......................................               86            0.168            5,346             9.49            1,775
DSI/FF.............................................................               55            0.54             3,419             8.43            2,466
DSI/ESP............................................................               35            0.78             2,176             3.20            1,471
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For use of Powder River Basin coal, North Dakota determined BART to
be a spray dryer with a fabric filter to achieve a minimum control
efficiency of 90% (30-day rolling average) on the inlet SO2
concentration to the pollution control equipment or an emission limit
of 0.16 lb/MMBtu (30-day rolling average). In establishing the 30-day
rolling average BART limit, the State increased the calculated annual
emissions rate of 0.12 lb/MMBtu to 0.16 lb/MMBtu to account for coal
variability over the shorter averaging period. The estimated cost of a
spray dryer with a fabric filter was $2,006 per ton of SO2
removed, and the capital and annualized costs were estimated to be
$77,840,000 and $11,220,000 per year, respectively. The projected
visibility improvements from this option, as well as for all other
control options, when the source burns Powder River Basin coal, are
anticipated to be less than when the source burns lignite coal.
    We are proposing to approve the State's SO2 BART
determinations for Stanton Unit 1 for both lignite and Powder River
Basin coal. The State's assessment of costs and other impacts was
reasonable. The spray dryer with fabric filter represents a stringent
level of control and will result in a reduction in annual
SO2 emissions from the plant of approximately 8,438 tons
when lignite is burned and 5,594 tons when Powder River Basin coal is
burned. This substantial reduction will result in a significant
improvement in visibility at Theodore Roosevelt, estimated to be 1.007
deciviews and 43 fewer days above 0.5 deciviews. Higher performing
alternatives (wet scrubber or circulating dry scrubber) would only
produce a slightly greater reduction in SO2 and improvement
in visibility, at higher cost. We are proposing to find that, based on
its consideration of the BART factors, the State's elimination of these
control options was reasonable.
    NOX BART Review (Lignite Coal): Unit 1 is already
equipped with LNB for NOX control. North Dakota indicates in
the SIP that Unit 1 has baseline controlled NOX emissions of
1,740 tons per year with an emission rate of 0.36 lb/MMBtu. North
Dakota identified the following control options as having potential
application as BART: selective catalytic reduction (SCR), low
temperature oxidation (LTO), non-selective catalytic reduction (NSCR),
electro-catalytic oxidation (ECO), selective non-catalytic reduction
(SNCR), rich reagent injection (RRI), external flue gas recirculation
(FGR), overfire air (OFA), LNB, and the Pahlman Process. The State
identified the following control options as technically infeasible:
ECO, NSCR, the Pahlman Process, RRI, and external flue gas
recirculation. The incremental cost effectiveness of both SCR and LTO
were deemed excessive at $10,000 and $45,400 per ton, respectively,
when compared to a combination of LNB, OFA, and SNCR (LNB + OFA +
SNCR). The State determined that there were no energy and non-air
quality environmental impacts that would preclude the selection of any
of the control equipment alternatives. A summary of the State's
NOX BART analysis with lignite coal, and the visibility
impacts derived from modeling conducted by the source, are provided in
Table 9.

                                    Table 9--Summary of Stanton NOX BART Analysis for Unit 1 Boiler With Lignite Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility Imacts1 2
                                                                            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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR....................................              90           0.044           1,929           12.49            6,475           1.405              59
LTO....................................              90           0.044           1,929           44.78           23,217  ..............  ..............
LNB + OFA + SNCR.......................              45           0.239             983            3.00            3,052           1.110              52
SNCR...................................              33           0.29              738            2.70            3,658           1.027              43
LNB + OFA..............................  ..............  ..............  ..............  ..............  ...............           1.009              43
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ Great River Energy modeled combined SO2 and NOX controls. Thus, the results shown include the noted NOX control option and North Dakota's selected
  SO2 BART control, a spray dryer with fabric filter.

    For use of lignite coal, North Dakota determined BART to be LNB +
OFA + SNCR. North Dakota specified a BART limit as a minimum control
efficiency of 45% and an emission limit of 0.29 lb/MMBtu (30-day
rolling average). The estimated average cost effectiveness of the
selected control combination is $3,052 per ton of NOX
removed. The capital and annualized costs were estimated to be
$10,660,000 and $3,000,000, respectively. This control option, when
combined with the spray dryer/fabric filter determined to be BART for
SO2, will result in a significant improvement in visibility
at Theodore Roosevelt, estimated to be 1.110 deciviews and 52 fewer
days above 0.5 deciviews. This represents an incremental visibility
improvement of 0.103 deciviews and 9 fewer days above 0.5 deciviews
when compared to use of a spray dryer/fabric filter with the existing
low NOx burners.
    NOX BART Review (Powder River Basin Coal): The
technically feasible control options for Powder River Basin coal are
the same. The costs of both SCR and LTO were deemed excessive. The
State determined that there were no energy and non-air quality
environmental impacts that would preclude the selection of any of the
control equipment alternatives. A summary of the State's NOX
BART analysis with Powder River Basin coal is provided in Table 10.

                              Table 10--Summary of Stanton NOX BART Analysis for Unit 1 Boiler With Powder River Basin Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                             Cost
                          Control option                                Control       Emission rate   reduction (tons/  Annualized cost   effectiveness
                                                                     efficiency (%)     (lb/MMBtu)          yr)              (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR...............................................................               88            0.044            1,530             12.49            8,163
LTO...............................................................               88            0.044            1,530             44.78           29,268
LNB + OFA + SNCR..................................................               45            0.196              794              3.0             3,778
SNCR..............................................................               36            0.230              629              2.7             4,293
LNB + OFA.........................................................               21            0.286              358              0.3               838
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For use of Powder River Basin coal, North Dakota determined BART to
be LNB + OFA + SNCR with a minimum control efficiency of 45% and an
emission limit of 0.23 lb/MMBtu (30-day rolling average). The estimated
cost of the selected control combination is $3,778 per ton of
NOX removed. The capital and annualized costs were estimated
to be $10,660,000 and $3,000,000, respectively. The projected
visibility improvements from this option, as well as for all other
control options, when the source burns Powder River Basin coal, are
anticipated to be less than when the source burns lignite coal.
    We are proposing to approve the State's NOX BART
determinations for Stanton Unit 1 for both lignite and Powder River
Basin coal. Given the projected incremental visibility improvement of
just under 0.3 deciviews from the use of SCR or LTO as compared to LNB
+ OFA + SNCR and the average and incremental cost effectiveness values
associated with these technologies, the State reasonably concluded that
the costs associated with SCR and LTO are not warranted.
    Filterable PM BART Review (Lignite Coal): Unit 1 is already
equipped with an ESP for PM control. The State evaluated the following
control options as having potential application as BART: baghouse, new
ESP, and wet ESP. All were deemed technically feasible. The State
determined all options present excessive costs with the least expensive
option being the wet ESP at $112,780 per ton of PM removed. North
Dakota stated there would be negligible visibility improvement with
additional controls. The State determined BART to be no additional
controls with an emission limit of 0.07 lb/MMBtu when burning lignite.
A summary of the State's PM BART analysis with lignite coal is provided
in Table 11.

                                    Table 11--Summary of Stanton PM BART Analysis for Unit 1 Boiler with Lignite Coal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission  rate     reduction     Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)       (tons/yr)           (MM$)          ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.015               18             4.98          276,670
New ESP............................................................           99.7              0.015               18             5.80          322,220
Wet ESP............................................................           99.7              0.015               18             2.03          112,780
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Filterable PM BART Review (Powder River Basin Coal): North Dakota
did not conduct a separate analysis for filterable PM when combusting
Powder River Basin coal. The State noted that available pollution
control equipment is expected to control emissions from both lignite
and Powder River Basin coal down to similar emission rates. North
Dakota determined that BART for filterable PM when burning Powder River
Basin coal was the same as when burning lignite: no additional controls
with an emission limit of 0.07 lb/MMBtu.
    We are proposing to approve the State's filterable PM BART
determination for Stanton Unit 1. The State's assessment of costs and
other impacts was reasonable. Existing controls, ESP, already reduce PM
emissions by approximately 99.5%, and North Dakota reasonably
determined that the costs of additional PM controls would be excessive
given the negligible improvement in visibility that would result.
    Condensable PM (PM10) Review (Lignite Coal): The State
provided an estimated emission rate for condensable PM of 0.02 lb/
MMBtu. This emission rate is about equal to the current filterable PM
emission rate of 0.019 lb/MMBtu. Based on the negligible visibility
impacts of filterable PM, the State anticipated that the visibility
impacts of condensable PM would also be negligible. Condensable PM
consists of both organic and inorganic substances. Organic condensable
PM includes VOCs that are in a gaseous

state through the air pollution control devices but eventually change
to a solid or liquid state. The primary inorganic substance from
boilers is sulfuric acid mist with lesser amounts of hydrogen fluoride
and ammonium sulfate. Sulfuric acid mist is the largest component of
condensable PM so controlling it will control most of the condensable
PM. The options for controlling sulfuric acid mist are the same as the
options for controlling SO2. BART for SO2--spray
dryer with a fabric filter--will reduce sulfuric acid mist by
approximately 90%. North Dakota determined that changes that would
provide additional reductions are not warranted given the negligible
improvement in visibility that would result. The State determined that
ongoing good combustion controls and the BART limit for SO2
would also constitute BART for condensable PM.
    Condensable PM (PM10) Review (Powder River Basin Coal):
For the same reasons described above for condensable PM when burning
lignite, North Dakota determined that ongoing good combustion controls
and the BART limit for SO2 would also constitute BART for
condensable PM when burning Powder River Basin coal.
    We are proposing to approve the State's condensable PM BART
determination for Stanton Unit 1. The spray dryer with a fabric filter
required for SO2 BART will substantially reduce sulfuric
acid mist, which is the largest component of condensable PM. North
Dakota reasonably determined that the costs of additional condensable
PM controls would be excessive given the negligible improvement in
visibility that would result.
    Auxiliary Boiler, Emergency Generator, Emergency Fire Pump,
Material Handling and Fugitive Sources
    The State analyzed and determined BART for these small emissions
sources at the plant and determined that BART is existing controls with
no additional controls. The State based its conclusion on the fact that
further controls would not be cost effective and would have virtually
no impact on visibility. For further detail, see the State's BART
analysis.
    We agree with the State's conclusion and are proposing to approve
its BART determination for these sources.
c. Minnkota Power Cooperative, Milton R. Young Station (MRYS)
Background
    Milton R. Young Station is a two-unit 794 MW electrical generating
plant located near Center, North Dakota. Both units are Babcock &
Wilcox cyclone boilers burning lignite coal. Commercial operation
commenced for Unit 1 (277 MW) in 1970 and for Unit 2 (517 MW) in 1977.
Both units have an expected remaining useful life of at least 20 years.
In addition, there are ten BART-eligible material handling transfer
operations that are negligible sources of PM and four other BART-
eligible units consisting of auxiliary or emergency equipment that are
negligible sources of PM, SO2, and NOX. The State
analyzed each pollutant and its effect on the visibility in Class I
areas. A summary of the State's analysis of existing controls and
potential BART controls is set forth below, except for the discussion
of NOX BART for Units 1 and 2, which we address in section
V.D.1 below. The State's BART determination for Milton R. Young Station
is provided in Appendix B.4 of the SIP. The company's BART analysis is
provided in Appendix C.4 of the SIP.
Unit 1 Boiler
    SO2 BART Review: Unit 1 had no existing SO2
control system at the time of the State's BART analysis, but as a
result of a consent decree resolving alleged New Source Review
violations at Milton R. Young Station, Minnkota installed a wet
scrubber in April 2011. The consent decree states that if Minnkota
installs a wet scrubber, it must comply with a 95% control efficiency
with no alternative emission limit (lb/MMBtu) limit. The deadline to
meet the new emission limit is December 31, 2011. The baseline
uncontrolled SO2 emissions that North Dakota reported in the
SIP are 21,519 tons per year with an emission rate of approximately
1.87 lb/MMBtu.
    The State evaluated the following SO2 control options
for having potential application as BART: wet scrubber, spray dryer,
circulating dry scrubber, Powerspan ECO, fuel switching, and coal
cleaning. North Dakota identified Powerspan ECO and coal cleaning as
technically infeasible. The State also cited a court case as a
rationale for not further analyzing fuel switching.\17\ The State found
all three remaining technologies to be cost effective. The State
determined that there were no energy and non-air quality environmental
impacts that would preclude the selection of any of the control
equipment alternatives. A summary of the State's SO2 BART
analysis, and the visibility impacts derived from modeling conducted by
the source, are provided in Table 12.
---------------------------------------------------------------------------

    \17\ A decision by the Seventh Circuit Court of Appeals on a
BACT determination for Prairie Generating Company, LLC indicated
that fuel switching was not required for mine mouth coal generating
facilities. The State's position is this would also apply to BART
determinations. We agree that a State is not required to consider
switching from coal to natural gas as part of a BART analysis for a
coal-fired power plant. As EPA noted in the BART Guidelines, we do
not consider BART as a requirement to redesign the source when
considering available control alternatives. 79 FR at 39164.

                                    Table 12--Summary of Milton R. Young Station SO2 BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2
                                                                        Emissions                            Cost      ---------------------------------
          Control option               Control       Emission rate      reduction        Annualized     effectiveness      Visibility
                                    efficiency (%)     (lb/MMBtu)       (tons/yr)       cost  (MM$)        ($/ton)       benefit (delta   Fewer days 0.5
                                                                                dv)           dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber.....................               95             0.10           20,443            22.58            1,105            2.076               71
Circulating Dry Scrubber.........               93             0.14           20,013            24.65            1,232  ...............  ...............
Spray Dryer......................               90             0.20           19,367            23.68            1,222            2.002               62
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ Visibility impacts are presented for each SO2 control option with NOX emissions at pre-control emission rates.

    North Dakota determined BART to be a wet scrubber, the most
efficient control alternative, operating at a minimum 95% control
efficiency (30-day rolling average). Since the wet scrubber is the most
efficient

technology, further evaluation of the other alternatives is not
necessary. Minnkota did conduct modeling for the 90% and 95% control
options; the results are included in Table 12. The estimated cost of a
wet scrubber was $1,105 per ton of SO2 removed, and the
capital and annualized costs were estimated to be $111,776,000 and
$22,584,000 per year, respectively.
    We are proposing to approve the State's SO2 BART
determination for Milton R. Young Station Unit 1. The State selected
the most efficient control technology at a 95% control level, which we
consider to be consistent with the most stringent level of control
currently available. Per our BART Guidelines, a state may skip the
five-factor analysis if it is imposing the most stringent level of
control. Nonetheless, we note that the wet scrubber will produce a
reduction in annual SO2 emissions from the unit of
approximately 20,443 tons. This substantial reduction will result in a
significant improvement in visibility at Theodore Roosevelt--estimated
to be 2.076 deciviews and 71 fewer days above 0.5 deciviews.
    Filterable PM BART Review: Unit 1 is equipped with an ESP rated at
approximately 99% control efficiency. The baseline controlled PM
emissions that North Dakota reported in the SIP are 268 tons per year
with an emission rate of 0.019 lb/MMBtu. The State evaluated the
following PM control options for having potential application as BART
with all four being found technically feasible: a new baghouse; a new
ESP; a compact hybrid particulate collector (CoHPAC); and upgrading the
existing ESP. All were deemed to have excessive costs. The alternative
with the least cost was a new baghouse at $39,433 per ton of PM
removed. The State determined BART to be no additional controls.
Minnkota is subject to a consent decree limiting PM emissions to 0.030
lb/MMBtu in the event Minnkota installs a wet scrubber. North Dakota
stated there would be insignificant visibility improvement with
additional controls. Since Minnkota has installed a wet scrubber, the
State proposed that BART is an emission limit of 0.030 lb/MMBtu
(average of three test runs). A summary of the State's PM BART analysis
is provided in Table 13.

                                     Table 13--Summary of Milton R. Young Station PM BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              134             5.28           39,433
New ESP............................................................           99.7              0.015               90             4.64           51,589
CoHPAC.............................................................           99.7              0.015               90             3.63           40,355
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART
determination for Milton R. Young Station Unit 1. The State's
assessment of costs and other impacts was reasonable. Existing
controls, ESP, already reduce PM emissions by approximately 99%, and
North Dakota reasonably determined that the costs of additional PM
controls would be excessive given the negligible improvement in
visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the largest
component of condensable PM. North Dakota stated that the options for
controlling sulfuric acid mist are the same as the options for
controlling SO2. Based on the negligible visibility impacts
of filterable PM, the State anticipated that the visibility impacts of
condensable PM would also be negligible. The State determined that
ongoing good combustion controls and the BART limit for SO2
would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART
determination for Milton R. Young Station Unit 1. The wet scrubber
required for SO2 BART will substantially reduce sulfuric
acid mist, which is the largest component of condensable PM. North
Dakota's determination is reasonable.
Unit 2 Boiler
    SO2 BART Review: At the time of the State's BART analysis, Unit 2
was equipped with a wet scrubber system which treated approximately 78%
of the flue gas with the remaining flue gas by-passed for stack gas
reheat. The wet scrubber system achieved approximately 75%
SO2 removal. The baseline controlled SO2
emissions that North Dakota reported in the SIP are 18,090 tons per
year with an emission rate of approximately 0.88 lb/MMBtu. The Milton
R. Young Station consent decree imposed a deadline for Unit 2 to be
upgraded and achieve 90% control efficiency by December 31, 2010. The
upgraded scrubber was placed into operation on December 8, 2010.
    The State evaluated the following SO2 control options
for BART: A new wet scrubber; upgrade to existing scrubber (either to
90% or 95%); circulating dry scrubber; spray dryer; flash dryer
absorber; Powerspan ECO; fuel switching; and coal cleaning. The Stated
found coal cleaning, Powerspan ECO, and fuel switching to be
technically infeasible. The average cost effectiveness of all remaining
alternatives was deemed reasonable. The State determined that there
were no energy and non-air quality environmental impacts that would
preclude the selection of any of the control equipment alternatives. As
the 95% control efficiency scrubber upgrade had equal or greater
control efficiency at lower cost as compared to a new wet scrubber or a
circulating dry scrubber, and the 90% control efficiency scrubber
upgrade had equal control efficiency at lower cost as compared to a
spray dryer or flash dryer, the State reduced the options to the 95%
and 90% control efficiency scrubber upgrades. A summary of the State's
SO2 BART analysis, and visibility impacts derived from
modeling conducted by the source, are provided in Table 14.

                                    Table 14--Summary of Milton R. Young Station SO2 BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts1 2
                                             Control                        Emissions                         Cost      --------------------------------
             Control option                efficiency     Emission rate     reduction      Annualized     effectiveness    Visibility
                                               (%)         (lb/MMBtu)       (tons/yr)      cost  (MM$)       ($/ton)         benefit       Fewer days >
                                                                                (delta dv)     0.5 dv  (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Upgrade Existing Scrubber..............              95            0.11          16,126            8.41             522           1.627               52
Upgrade Existing Scrubber..............              90            0.23          14,162            7.33             518           1.423               40
--------------------------------------------------------------------------------------------------------------------------------------------------------
1 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.
2 Visibility impacts are presented for each SO2 control option with NOX emissions at pre-control emission rates.

    North Dakota determined BART to be the improvements to the wet
scrubber to achieve a 95% control efficiency (from scrubber inlet to
outlet, 30-day rolling average). Minnkota would have to comply with
either the 95% reduction requirement or the 0.15 lb/MMBtu limit, but
not both. The 90% control efficiency requirement from the consent
decree resolving the alleged new source review violations is also
incorporated into the BART permit, which is part of the SIP.
    We are proposing to approve the State's SO2 BART
determination for Milton R. Young Station Unit 2. The State's
assessment of costs and other impacts was reasonable. The upgrade to
the existing wet scrubbers represents a stringent level of control and
will result in a reduction in annual SO2 emissions from the
plant of approximately 16,126 tons. This substantial reduction will
result in a significant improvement in visibility at Theodore
Roosevelt--estimated to be 1.627 deciviews and 52 fewer days above 0.5
deciviews.
    Filterable PM BART Review: Unit 2 is equipped with an ESP rated at
approximately 99% control efficiency with a baseline emission rate of
0.06 lb/MMBtu. The average emission rate for this unit for 2000-2004
was 0.028 lb/MMBtu. The baseline controlled PM emissions that North
Dakota reported in the SIP are 1,135 tons per year. The State evaluated
the following PM control options for BART and found all four to be
technically feasible: A new baghouse; a new ESP; a CoHPAC; and upgrades
to the existing ESP. The cost of all options was deemed excessive, with
the least expensive being CoHPAC at $6,693 per ton of PM removed. North
Dakota stated that visibility impacts even at 100% control would be
minimal due to the low emission reductions of 849 tons per year
compared to the baseline conditions with the existing 99% efficient
ESP. The State proposed BART to be no additional controls. The consent
decree limits PM emissions to 0.030 lb/MMBtu. Therefore, the State
proposed that BART is an emission limit of 0.030 lb/MMBtu (average of
three test runs). A summary of the State's PM BART analysis is provided
in Table 15.

                                     Table 15--Summary of Milton R. Young Station PM BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate      reduction     Annualized cost   effectiveness
                                                                     efficiency  (%)     (lb/MMBtu)       (tons/yr)          (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              887             8.25            9,300
New ESP............................................................           99.7              0.015              849             7.52            8,857
CoHPAC.............................................................           99.7              0.015              849             5.68            6,693
Baseline...........................................................           99.0              0.060  ...............             2.97  ...............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART
determination for Milton R. Young Station Unit 2. The State's
assessment of costs and other impacts was reasonable. Existing
controls, ESP, already reduce PM emissions by approximately 99%, and
North Dakota reasonably determined that the costs of additional PM
controls would be excessive given the negligible improvement in
visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the largest
component of condensable PM. North Dakota stated that the options for
controlling sulfuric acid mist are the same as the options for
controlling SO2. Based on the negligible visibility impacts
of filterable PM, the State anticipated that the visibility impacts of
condensable PM would also be negligible. The State determined that
ongoing good combustion controls and the BART limit for SO2
would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART
determination for Milton R. Young Station Unit 2. The wet scrubber
required for SO2 BART will substantially reduce sulfuric
acid mist, which is the largest component of condensable PM. North
Dakota's determination is reasonable.
    Auxiliary Boiler, Emergency Generator, Emergency Fire Pumps, and
Material Handling and Fugitive Sources
    The State analyzed and determined BART for these small emissions
sources at the plant and determined that BART is existing controls with
no additional controls. The State based its conclusion on the fact that
further controls would not be cost effective and would have virtually
no impact on visibility. For further detail, see the State's BART
analysis.
    We agree with the State's conclusion and are proposing to approve
its BART determination for these sources.
d. Basin Electric Power Cooperative, Leland Olds Station (LOS)
    This is a 656 MW coal-fired electrical generating plant located in
Stanton, North Dakota with two boiler units. Unit 1 is a Babcock &
Wilcox wall-fired, dry-bottom, pulverized coal-fired boiler serving a
turbine generator with a nameplate rating of 216 MW. Unit 2 is a
Babcock & Wilcox cyclone-fired unit burning crushed coal, with a
turbine-

generator name plate rating of 440 MW. Unit 1 began commercial
operation in 1966 and Unit 2 began operation in 1976. Both boiler units
burn lignite coal and have an expected remaining useful life of at
least 20 years. In addition, there are seven BART-eligible material
handling transfer operations that are negligible sources of PM and two
other BART-eligible units consisting of auxiliary and emergency
equipment that are negligible sources of PM, SO2, and
NOX. Each pollutant and its effect on the visibility in
Class I areas was analyzed by the State. A summary of the State's
analysis of existing controls and potential BART controls for each
pollutant is set forth below, except for the discussion of
NOX BART for Unit 2, which we address in section V.D.1.c
below. The State's BART determination for Leland Olds Station is
provided in Appendix B.1 of the SIP. The company's BART analysis is
provided in Appendix C.1 of the SIP.
Unit 1 Boiler
    SO2 BART Review: Unit 1 has no existing SO2 control
system. The baseline uncontrolled SO2 emissions that North
Dakota reported in the SIP are 34,683 tons per year with an emission
rate of approximately 3.02 lb/MMBtu. The State evaluated the following
SO2 control options for BART: Wet scrubber; spray dryer;
circulating dry scrubber; flash dryer absorber; Powerspan ECO; fuel
switching; and coal cleaning. Powerspan ECO and coal cleaning were
identified as technically infeasible. The State conducted a cost
analysis for the top three options and found all to be cost effective.
The flash dryer absorber was not included in the analysis because it
costs more than a spray dryer with no additional emissions reduction.
The State determined that there were no energy and non-air quality
environmental impacts that would preclude the selection of any of the
control equipment alternatives. A summary of the State's SO2
BART analysis for Unit 1, and visibility impacts derived from modeling
conducted by the source, are provided in Table 16.

                                      Table 16--Summary of Leland Olds Station SO2 BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts1 2
                                             Control                        Emissions                          Cost      -------------------------------
             Control option                efficiency     Emission rate     reduction      Annualized     effectiveness     Visibility
                                               (%)         (lb/MMBtu)       (tons/yr)      cost  (MM$)       ($/ton)          benefit      Fewer days >
                                                                                (delta dv)    0.5 dv  (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber...........................              95            0.15          32,949           19.31              586           1.912              83
Circulating Dry Scrubber...............              93            0.21          32,255           20.72              636           1.743              78
Spray Dryer............................              90            0.30          31,215           18.70              599           1.707              77
--------------------------------------------------------------------------------------------------------------------------------------------------------
1 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.
2 Basin Electric modeled combined SO2 and NOX controls. The results shown include the noted SO2 control option and NOX at the presumptive rate. Given
  that the presumptive NOX emission rate is very close to the pre-control NOX rate, the visibility impacts shown are largely due to the reduction in SO2
  emissions and not the reduction in NOX emissions.

    North Dakota determined BART to be the most efficient control
option, a wet scrubber operating at 95% control efficiency or below an
emission limit of 0.15 lb/MMBtu (30-day rolling average). Basin
Electric would have to comply with either the 95% reduction requirement
or the 0.15 lb/MMBtu limit, but not both. The estimated average cost
effectiveness of a wet scrubber was $586 per ton of SO2
removed, and the capital and annualized costs were estimated to be
$107,220,000 and $19,310,000 per year, respectively.
    We are proposing to approve the State's SO2 BART
analysis and determination for Leland Olds Station Unit 1. The State's
assessment of costs and other impacts was reasonable. The wet scrubber
represents a stringent level of control and will result in a reduction
in annual SO2 emissions from the plant of approximately
32,949 tons. This substantial reduction will result in a significant
improvement in visibility at Theodore Roosevelt, estimated to be 1.912
deciviews and 83 fewer days above 0.5 deciviews.
    NOX BART Review: Unit 1 is equipped with LNB (installed in 1995).
The baseline controlled NOX emissions that North Dakota
reported in the SIP are 2,967 tons per year with an emission rate of
approximately 0.285 lb/MMBtu. The State identified the following
control option combinations for BART:
     Selective catalytic reduction (SCR).
     Electro-catalytic oxidation (ECO).
     Selective non-catalytic reduction (SNCR).
     Hydrocarbon enhanced SNCR (HE-SNCR).
     Rich reagent injection (RRI).
     Rotomix (ROFA + SNCR).
     Conventional gas reburn (CGR).
     CGR + SNCR with SOFA.
     Coal reburn.
     Coal reburn + SNCR.
     Fuel-lean gas reburn (FLGR).
     FLGR + SNCR.
     Rotating overfire air (ROFA).
     Separated overfire air (SOFA).
     New low NOX burners (LNB).
     Combustion improvements.
    The State agreed with Basin Electric's determination that high dust
SCR is not technically feasible but found that low-dust SCR (LDSCR) and
tail-end SCR (TESCR) would be technically feasible. North Dakota also
identified ECO, coal reburn plus SNCR, and RRI as technically
infeasible for Unit 1. The State determined the average cost
effectiveness of the four most efficient options to be excessive with
estimates ranging from $4,400 to $13,600 per ton of NOX
removed. The State also determined the incremental costs of these
options to be excessive with estimates ranging from $12,500 to $80,700.
North Dakota discussed the benefits of pilot testing and based its
acceptance of cost estimates provided by Basin Electric on the
inability to mandate pilot testing in the BART process. The State noted
that EPA, in the BART Guidelines, established a presumptive
NOX emission limit of 0.29 lb/MMBtu for this type of boiler.
The State determined that there were no energy and non-air quality
environmental impacts that would preclude the selection of any of the
control equipment alternatives. A summary of the State's NOX
BART analysis for Unit 1 is provided in Table 17.

                                      Table 17--Summary of Leland Olds Station NOX BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCR Low Dust.......................................................               80            0.057            2,374      18.63-26.86     7,849-11,313
SCR Tail End.......................................................               80            0.057            2,374      21.51-31.01     9,061-13,628
Coal Reburn + Boosted SOFA.........................................             48.7            0.146            1,445             7.03            4,866
Coal Reburn + SOFA.................................................             46.2            0.153            1,371             5.98            4,364
SNCR + Boosted SOFA................................................             45.1            0.156            1,338             3.82            2,854
SNCR + Basic SOFA..................................................             42.0            0.165            1,246             3.10            2,487
SNCR + Close Coupled OFA...........................................             24.5            0.215              727             3.36            4,623
Boosted SOFA.......................................................             24.3            0.216              721             1.14            1,577
SOFA...............................................................             19.4            0.230              576             0.14              250
--------------------------------------------------------------------------------------------------------------------------------------------------------

    North Dakota determined BART to be SNCR + basic SOFA with an
emission limit of 0.19 lb/MMBtu (30-day rolling average). The estimated
average cost effectiveness for SNCR + SOFA was $2,487 per ton of
NOX removed, and the capital and annualized costs were
estimated to be $6,234,000 and $3,099,000 per year, respectively.
    Basin Electric did not provide the modeled visibility impacts of
SNCR + basic SOFA for Unit 1 individually. Instead, for this control
option, Basin Electric provided the visibility impacts for Unit 1 and
Unit 2 combined, with the emissions from Unit 2 held constant. The
resulting visibility improvement, when compared to no controls at Unit
1, is estimated to be 0.160 deciviews at Theodore Roosevelt.
    We are proposing to approve the State's NOX BART
determination for Leland Olds Station Unit 1. Based on our review of
North Dakota's submission, we are proposing to find that it was
reasonable for the State to eliminate higher performing control options
and select SNCR + basic SOFA as BART with an emission limit of 0.19 lb/
MMBtu (30-day rolling average). Three of the other controls under
consideration--Coal Reburn + Boosted SOFA, Coal Reburn + SOFA, and SNCR
+ Boosted SOFA--would provide minimal additional reductions of
NOX, (and presumably relatively small improvements in
visibility), but have higher dollar per ton values. The incremental
costs of these options compared to SNCR + basic SOFA are relatively
high. We note that we do not agree with the State's cost analysis for
SCR, but nonetheless find the elimination of SCR for this unit to be
acceptable. As we explain in greater detail in section V.D.1.d below,
Basin Electric deviated significantly from EPA's control cost manual
when it estimated costs for SCR for Leland Olds Station Unit 2, and
substantially overestimated the costs for SCR. The State relied on
Basin Electric's estimates of the costs for SCR for Unit 2 when it
estimated the costs for SCR for Unit 1. Thus, we anticipate that the
State's estimate for Unit 1 also overestimates the costs for SCR.
Nonetheless, Unit 1 is relatively small compared to Milton R. Young
Station Units 1 and 2 and Leland Olds Station Unit 2 and has
substantially lower baseline NOX emissions. And, unlike
those units, Unit 1 is not a cyclone boiler and so is currently fitted
with low-NOX burners. Finally, North Dakota has selected an
emission limit--0.19 lb/MMBtu--based on the use of post-combustion
controls (SNCR) and combustion controls, that is substantially more
stringent than the presumptive BART limit for this type of boiler. This
emission limit represents an adjustment of the annual rate since the
30-day rolling average is expected to be 5-15% higher. These controls
will achieve a reduction in NOX emissions of about 1,246
tons per year. Based on these factors, we are proposing to approve
North Dakota's NOX BART determination.
    Filterable PM BART Review: Unit 1 is equipped with an ESP rated at
approximately 99% control efficiency. The baseline controlled PM
emissions that North Dakota reported in the SIP are 219 tons per year
with an emission rate of approximately 0.040 lb/MMBtu. The State
evaluated the following PM control options for BART and found all to be
technically feasible: A new baghouse; a new ESP; and a CoHPAC. North
Dakota considered the cost effectiveness for all three options to be
excessive with the least expensive option being CoHPAC at an average
cost effectiveness of $11,947 per ton of PM removed. North Dakota
stated there would be negligible visibility improvement with additional
controls. The State proposed BART to be no additional controls with an
emission limit of 0.07 lb/MMBtu (average three test runs). A summary of
the State's PM BART analysis for Unit 1 is provided in Table 18.

                                       Table 18--Summary of Leland Olds Station PM BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate   reduction (tons/ Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)          yr)             (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              224             3.26           15,554
New ESP............................................................           99.7              0.013              207             2.63           12,705
CoHPAC.............................................................           99.7              0.013              207             2.47           11,947
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Condensable PM (PM10) Review: Sulfuric acid mist is the
largest component of condensable PM. The options for controlling
sulfuric acid mist are the same as the options for controlling
SO2; therefore, North Dakota determined that BART for
condensable PM is good SO2 control. The State determined
that ongoing good combustion controls and the BART limit for
SO2 would also constitute BART for condensable PM.
    We are proposing to approve the State's condensable PM BART
determination for Leland Olds Station Unit 1. The wet scrubber required
for SO2 BART will substantially reduce sulfuric acid mist,
which is the largest

component of condensable PM. North Dakota reasonably determined that
the costs of additional condensable PM controls would be excessive
given the negligible improvement in visibility that would result.
Unit 2 Boiler
    SO2 BART Review: Unit 2 has no existing SO2
control system. The baseline uncontrolled SO2 emissions that
North Dakota reported in the SIP are 67,858 tons per year with an
emission rate of approximately 3.02 lb/MMBtu. The State identified the
following as potential control options: new wet scrubber, spray dryer,
circulating dry scrubber, flash dryer absorber, Powerspan ECO, fuel
switching, and coal cleaning. Powerspan ECO and coal cleaning were
determined to be technically infeasible. A summary of the State's
SO2 BART analysis for Unit 2, and visibility impacts derived
from modeling conducted by the source, are provided in Table 19.

                                      Table 19--Summary of Leland Olds Station SO2 BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts1 2
                                                                            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)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wet Scrubber...........................              95            0.15          64,465           29.84              463           3.479              89
Circulating Dry Scrubber...............              93            0.21          63,108           35.58              564  ..............  ..............
Spray Dryer............................              90            0.30          61,072           32.89              539  ..............  ..............
Flash Dryer Absorber...................              90            0.30          61,072           32.43              531  ..............  ..............
Fuel Switching.........................              77            0.69         <52,251           13.49              258  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ Basin Electric modeled combined SO2 and NOX controls. The results shown include the noted SO2 control option and NOX at the SOFA emission rate.
  Given that the NOX emission rate with SOFA is somewhat close to the pre-control NOX rate, the visibility impacts shown are largely due to the
  reduction in SO2 emissions and not the reduction in NOX emissions.

    North Dakota determined BART to be the most efficient control
option, a wet scrubber operating at 95% control efficiency or below an
emission limit of 0.15 lb/MMBtu (30-day rolling average). Basin
Electric would have to comply with either the 95% reduction requirement
or the 0.15 lb/MMBtu limit, but not both. The estimated average cost
effectiveness of a wet scrubber was $463 per ton of SO2
removed, and the capital and annualized costs were estimated to be
$147,600,000 and $29,840,000 per year, respectively.
    We are proposing to approve the State's SO2 BART
determination for Leland Olds Station Unit 2. The State's assessment of
costs and other impacts was reasonable. The wet scrubber represents a
stringent level of control and will result in a reduction in annual
SO2 emissions from the plant of approximately 64,465 tons.
When modeled with modest NOX reductions assumed for SOFA,
the maximum improvement is estimated to be 3.479 deciviews and 89 fewer
days above 0.5 deciviews at Theodore Roosevelt.
    Filterable PM BART Review: Unit 2 is equipped with an ESP rated at
approximately 99% control efficiency. The baseline controlled PM
emissions that North Dakota reported in the SIP are 627 tons per year
with an emission rate of approximately 0.034 lb/MMBtu. The State
evaluated the following PM control options for BART and found all to be
technically feasible: A new baghouse; a new ESP; and a CoHPAC. North
Dakota considered the average cost effectiveness for all three options
to be excessive, with the least expensive option being CoHPAC at
$12,000 per ton. The average PM emission rate for 2000-2004 was 0.025
lb/MMBtu. The State noted that eliminating all PM emissions would
result in a visibility impact of only 0.026 deciviews. The State
established BART as no additional controls and the existing permitted
emission limit of 0.07 lb/MMBtu (average three test runs). A summary of
the State's PM BART analysis for Unit 2 is provided in Table 20.

                                       Table 20--Summary of Leland Olds Station PM BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions                            Cost
                           Control option                                Control       Emission rate      reduction     Annualized cost   effectiveness
                                                                      efficiency (%)     (lb/MMBtu)       (tons/yr)          (MM$)           ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baghouse...........................................................           99.7+             0.013              388             5.89           15,186
New ESP............................................................           99.7              0.015              350             4.95           14,137
CoHPAC.............................................................           99.7              0.015              350             4.21           12,029
Baseline...........................................................           99.3              0.034  ...............  ...............  ...............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We are proposing to approve the State's filterable PM BART
determination for Leland Olds Station Unit 2. The State's assessment of
costs and other impacts was reasonable. Existing controls, ESP, already
reduce PM emissions by approximately 99%, and North Dakota reasonably
determined that the costs of additional PM controls would be excessive
given the negligible improvement in visibility that would result.
    Condensable PM (PM10) Review: Sulfuric acid mist is the
largest component of condensable PM. The options for controlling
sulfuric acid mist are the same as the options for controlling
SO2; therefore, North Dakota determined that BART for
condensable PM is good SO2 control. The State determined
that ongoing good combustion controls and the BART limit for
SO2 would also constitute BART for condensable PM.

    We are proposing to approve the State's condensable PM BART
determination for Leland Olds Station Unit 2. The wet scrubber required
for SO2 BART will substantially reduce sulfuric acid mist,
which is the largest component of condensable PM. North Dakota
reasonably determined that the costs of additional condensable PM
controls would be excessive given the negligible improvement in
visibility that would result.
Auxiliary Boiler, Emergency Fire Pump, and Material Handling and
Fugitive Sources
    The State analyzed and determined BART for these small emissions
sources at the plant and determined that BART is existing controls with
no additional controls. The State based its conclusion on the fact that
further controls would not be cost effective and would have virtually
no impact on visibility. For further detail, see the State's BART
analysis.
    We agree with the State's conclusion and are proposing to approve
its BART determination for these sources.
e. North Dakota BART Results and Summary
    We have summarized North Dakota's BART determinations that we are
proposing to approve in Table 21 for SO2 and Table 22 for
NOX, below. We have not summarized the information for PM as
it has relatively low impact on visibility.
    North Dakota's Regional Haze Rule requires each source subject to
BART to install and operate BART no later than 5 years after we approve
this Regional Haze SIP. NDAC 33-15-25-02.2. This satisfies the
requirement under 40 CFR 51.308(e)(1)(iv), that ``each source subject
to BART be 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.''
    As noted previously, to be approvable, the Regional Haze SIP must
include monitoring, recordkeeping, and reporting requirements to ensure
that the BART limits are enforceable. North Dakota has included
individual source permits in its Regional Haze SIP that contain such
requirements. See SIP Appendix D. We have reviewed these requirements
and find them to be adequate as they relate to the BART limits we are
proposing to approve. In particular, for SO2 and
NOX BART limits, the permits require the use of continuous
emission monitoring systems (CEMS) to determine compliance, generally
in accordance with 40 CFR part 75. For the filterable PM BART limits,
the permits require stack testing and compliance with a compliance
assurance monitoring (CAM) plan. Adequate recordkeeping and reporting
requirements are also specified.
    For the reasons discussed above, we propose to find that, with the
exception of the NOX BART determinations for Milton R. Young
Station Units 1 and 2, Leland Olds Station Unit 2, and Coal Creek Units
1 and 2, North Dakota satisfied the BART requirements of 40 CFR
51.308(e).

                              Table 21--North Dakota BART Determinations for SO2 Emissions that EPA is Proposing to Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  BART level
                                        2000-2004     Baseline    of control                            Emissions     Emission
           Source and unit               average      level of        (%           Control device         after      reduction        Emission limit
                                        emissions    control (%   reduction)                             controls   (tons/yr) 2
                                        (tons/yr)    reduction)       1                                 (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Basin Electric Power Cooperative, LOS       16,666            0           95  New Wet Scrubber.......        1,376       15,290  95% reduction or 0.15
 Unit 1.                                                                                lb/MMBtu, 30-day
                                                                                rolling average.
Basin Electric Power Cooperative,           30,828            0           95  New Wet Scrubber.......        2,530       28,298  95% reduction or 0.15
 Leland Olds Station Unit 2.                                                                                lb/MMBtu, 30-day
                                                                                rolling average.
Great River Energy, Coal Creek              14,086           68           95  Modified Existing Wet          3,781       10,305  95% reduction or 0.15
 Station Unit 1.                                                               Scrubber and Coal                                  lb/MMBtu, 30-day
                                                                               Dryer.                                             rolling average.
Great River Energy, Coal Creek              12,407           68           95  Modified Existing Wet          3,621        8,786  95% reduction or 0.15
 Station Unit 2.                                                               Scrubber and Coal                                  lb/MMBtu, 30-day
                                                                               Dryer.                                             rolling average.
Great River Energy, Stanton Station          8,312            0           90  New Spray dryer and            1,179        7,133  90% reduction or 0.24
 Unit 1.                                                                       Fabric Filter.                                     lb/MMBtu (lignite), or
                                                                                0.16 lb/MMBtu (PRB) 30-
                                                                                day rolling average.
Minnkota Power Cooperative, MRYS Unit       20,148            0           95  New Wet Scrubber.......        1,007       19,141  95% reduction, 30-day
 1.                                                                                rolling average.
Minnkota Power Cooperative, MRYS Unit       12,404           65           95  Modified Existing Wet          2,739        9,665  95% reduction, or 0.15
 2.                                                                            Scrubber.                                          lb/MMBtu, 30-day
                                                                                rolling average. Also,
                                                                                90% reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Based on two-year baseline emission rate for BART.
\2\ Based on the average 2000-2004 operating rate.

                              Table 22--North Dakota BART Determinations for NOX Emissions That EPA Is Proposing to Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  BART level
                                        2000-2004     Baseline    of control                            Emissions     Emission
           Source and unit               average     level  of        (%           Control device         after      reduction        Emission limit
                                        emissions    control (%   reduction)                             controls   (tons/yr) 2
                                        (tons/yr)    reduction)       1                                 (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Stanton Unit 1.......................        2,048            0           45  LNB, Overfire Air and          1,425          623  0.29 lb/106 Btu, 30-day
                                                                               SNCR.                                              rolling average.
Leland Olds Unit 1...................        2,501            0           42  SOFA and SNCR..........        1,744          757  0.19 lb/106 Btu, 30-day
                                                                                rolling average.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Based on two-year baseline emission rate for BART.
\2\ Based on the average 2000-2004 operating rate.

D. Evaluation of North Dakota's NOX BART Determinations for
Milton R. Young Station Units 1 and 2, Leland Olds Station Unit 2, and
Coal Creek Station Units 1 and 2

    The discussion below is limited to the NOX BART
assessments for Milton R. Young Station Units 1 and 2, Leland Olds
Station Unit 2, and Coal Creek Units 1 and 2. North Dakota's other BART
assessments are covered in Section V.C.3, above.
1. Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2
a. Milton R. Young Station Unit 1--State Analysis
    At the time Minnkota made its BART submittal upon which the State
based its analysis, Milton R. Young Station Unit 1 had no existing
NOX control system. The baseline uncontrolled NOX
emissions that North Dakota reported in the SIP are 9,032 tons per year
per unit with an emission rate of 0.849 lb/MMBtu. The Minnkota consent
decree, discussed in section V.C.3.c, above, required Minnkota to
install OFA on Unit 1 by December 31, 2009.
    The State has asserted that the Milton R. Young Station units do
not exceed the 750 MW threshold for mandatory application of the BART
guidelines and the presumptive NOX BART limits. That
presumptive limit for a cyclone unit greater than 200 MW burning
lignite is 0.10 lb/MMBtu. To reach its conclusion, North Dakota relied
on the nameplate capacity of the units. We propose to disagree based on
the fact that the actual operating levels for Units 1 and 2 are 277 MW
and 517 MW, respectively--i.e., in excess of their nameplate
capacities.\18\ The sum of these permitted levels results in a total
generating capacity of at least 794 MW, which is above the 750 MW
capacity threshold established by the CAA and the Regional Haze Rule
(see 40 CFR 51.308(e)(ii)(B)). We also note that the State's regional
haze regulations, at NDAC 33-15-25-03, require that facility owners or
operators for whom the guidelines are not mandatory ``shall use
appendix y [EPA's BART Guidelines] as guidance for preparing their best
available control retrofit technology determinations.'' \19\
---------------------------------------------------------------------------

    \18\ See 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.
    \19\ We are proposing to approve the State's regional haze
regulations as part of this action.
---------------------------------------------------------------------------

    The State identified the following as potential control options:
SCR, ECO, SNCR, HE-SNCR, RRI, Rotomix (ROFA + SNCR), CGR, CGR + SNCR +
SOFA, coal reburn, coal reburn + SNCR, FLGR, FLGR + SOFA, ROFA, SOFA,
advanced separated overfire air (ASOFA), combustion improvements
(included with SOFA and ASOFA), and oxygen enhanced combustion (OEC).
The State eliminated the following from further consideration as
technically infeasible: High dust SCR, ECO, HE-SNCR, RRI, Rotomix (ROFA
+ SNCR), CGR + SNCR, coal reburn + SNCR, FLGR + SNCR, and OEC.
    A summary of the State's analysis for NOX BART
alternatives, and modeling results provided by both the source and
State are provided in Table 23 for Unit 1.

                                    Table 23--Summary of Milton R. Young Station NOX BART Analysis for Unit 1 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2
                                                                             Emissions                         Cost      -------------------------------
             Control option                   Control      Emission rate     reduction      Annualized     effectiveness    Visibility
                                          efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)     benefit (delta   Fewer days  >
                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LDSCR + ASOFA...........................              90           0.085           8,129     33.53-52.19     4,124-6,421           3.476             114
TESCR + ASOFA...........................              90           0.085           8,129     39.31-56.10     4,835-6,901           3.476             114
SNCR + ASOFA............................            58.1           0.355           5,248            7.47           1,424           2.923              96
Gas Reburn + ASOFA......................              56           0.374           5,058           37.33           7,381  ..............  ..............
Coal Reburn + ASOFA.....................            54.6           0.385           4,931           11.39           2,309  ..............  ..............
FLGR + ASOFA............................            45.9           0.460           4,146           16.99           4,098  ..............  ..............
ASOFA...................................            39.5           0.513           3,568            2.49             698  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ Minnkota and the State modeled combined SO2 and NOX controls. The results shown include SO2 at an emission rate reflective of SO2 scrubbing along
  with the noted NOX control option. More detail on this approach is provided in the Technical Support Document.

    The State determined that the cost of all control options was
reasonable with the exception of both SCR configurations. The State
considered the average cost effectiveness and incremental cost
effectiveness of LDSCR

and TESCR to be excessive and unreasonable. These control options, 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. However, the State also stated that single source
visibility benefits calculated using the EPA modeling guidelines are
inflated and conducted supplemental cumulative visibility modeling
(i.e., modeling using degraded background, reflecting emissions from
all sources). The results of the State's supplemental cumulative
modeling showed greatly reduced visibility benefits from use of SCR,
benefits that the State considered to be negligible. The State
determined that there were no energy and non-air quality environmental
impacts that would preclude the selection of any of the control
equipment alternatives. North Dakota determined BART to be SNCR + ASOFA
(the next most efficient option after SCR), with an emission limit of
0.36 lb/MMBtu (30-day rolling average) and a separate limit during
startup of 2070.2 lb/hr (24-hour rolling average). North Dakota
estimated the cost effectiveness for SNCR + ASOFA to be $1,424 per ton
of NOX removed, and the capital and annualized costs to be
$8,113,000 and $7,742,000 per year, respectively.
b. Milton R. Young Station Unit 2--State Analysis
    At the time Minnkota made its BART submittal upon which the State
based its analysis, Milton R. Young Station Unit 2 was equipped with an
OFA NOX control system. The baseline controlled
NOX emissions that North Dakota reported in the SIP were
15,507 tons per year per unit with an emission rate of approximately
0.81 lb/MMBtu. The State identified the following as potential control
options: SCR, ECO, SNCR, HE-SNCR, ASOFA, RRI + SNCR + ASOFA, Rotomix
(ROFA + SNCR), CGR + SNCR, coal reburn, coal reburn + SNCR, FLGR, FLGR
+ SOFA, ROFA, SOFA, ASOFA, combustion improvements, and OEC. The State
eliminated the following from further consideration as technically
infeasible: High dust SCR, ECO, HE-SNCR, RRI, Rotomix (ROFA + SNCR),
CGR + SNCR, coal reburn + SNCR, FLGR + SNCR, and OEC. A summary of the
State's analysis for NOX BART alternatives, and modeling
results provided by both the source and State, are provided in Table 24
for Unit 2.

                                    Table 24--Summary of Milton R. Young Station NOX BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2
                                                                            Emissions                          Cost      -------------------------------
            Control option                  Control       Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)      benefit (delta   Fewer  days >
                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LDSCR + ASOFA.........................             90             0.079          13,956     57.35-89.07      4,109-6,382           3.945             110
TESCR + ASOFA.........................             90             0.079          13,956     66.51-98.81      4,765-7,081           3.945             110
SNCR + ASOFA..........................             58.0           0.330           8,994           11.41            1,268           3.379              89
Gas Reburn + ASOFA....................             55.4           0.350           8,591           63.88            7,436  ..............  ..............
Coal Reburn + ASOFA...................             54.2           0.360           8,405           19.48            2,317  ..............  ..............
FLGR + ASOFA..........................             45             0.432           6,978           29.31            4,201  ..............  ..............
ASOFA.................................             37.7           0.489           5,846            4.38              749  ..............  ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\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
  SO2 scrubbing along with the noted NOX control option.

    The State determined the average cost effectiveness of all control
options was reasonable with the exception of both SCR configurations.
The State considered the average cost effectiveness and incremental
cost effectiveness of LDSCR and TESCR to be excessive and unreasonable.
These control options, when combined with wet scrubbing for
SO2, would result in a significant improvement in visibility
at Theodore Roosevelt National Park--estimated to be 3.945 deciviews
and 110 fewer days above the 0.5 dv threshold. This represents an
incremental visibility improvement of 2.318 deciviews and 58 fewer days
above the 0.5 dv threshold beyond that achieved by wet scrubbing alone.
Moreover, when compared to SNCR + ASOFA, SCR + ASOFA would result in an
incremental visibility improvement of 0.566 deciviews and 21 fewer days
above the 0.5 dv threshold. However, using the same approach it used
for Milton R. Young Station Unit 1, the State determined that the
visibility benefits from use of SCR would be negligible. The State
determined that there were no energy and non-air quality environmental
impacts that would preclude the selection of any of the control
equipment alternatives. North Dakota determined BART to be SNCR + ASOFA
(the next most efficient option after SCR), with an emission limit of
0.35 lb/MMBtu (30-day rolling average) and a separate limit during
startup of 3,995.6 lb/hr (24-hour rolling average). The State estimated
the cost effectiveness for SNCR + ASOFA to be $1,268 per ton of
NOX removed, and the capital and annualized costs to be
$17,128,000 and $11,405,000 per year, respectively.
c. Leland Olds Station Unit 2--State Analysis
    At the time Basin Electric made its BART submittal upon which the
State based its analysis, Unit 2 had no existing NOX control
system. ASOFA was installed in November 2009. The State identified the
following as potential control options: SCR, ECO, SNCR, HE-SNCR, ASOFA,
RRI + SNCR + ASOFA, Rotomix (ROFA + SNCR), CGR + SNCR, coal reburn,
coal reburn + SNCR, FLGR, SOFA, ASOFA, ROFA, combustion improvements,
and OEC. The State eliminated the following from further consideration
as technically infeasible: High dust SCR, ECO, HE-SNCR, Rotamix, CGR +
SNCR, coal

reburn + SNCR, FLGR + SNCR, and OEC.
    A summary of the State's analysis for NOX BART
alternatives, and modeling results provided by both the source and
State are provided in Table 25 for Unit 2.

                                      Table 25--Summary of Leland Olds Station NOX BART Analysis for Unit 2 Boiler
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility impacts 1 2
                                                                            Emissions                          Cost      -------------------------------
            Control option                  Control       Emission rate     reduction      Annualized     effectiveness     Visibility
                                         efficiency (%)    (lb/MMBtu)       (tons/yr)      cost (MM$)        ($/ton)      benefit (delta   Fewer days  >
                                                                                dv)        0.5 dv (days)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low Dust SCR + ASOFA..................             90             0.07           10,821     38.74-55.84      3,581-5,161           4.393             130
Tail End SCR + ASOFA..................             90             0.07           10,821     43.83-63.17      4,050-5,838           4.393             130
RRI + SNCR + ASOFA....................             60.3           0.266           7,250            17.4            2,400           3.963             110
SNCR + ASOFA..........................             54.5           0.305           6,553           10.87            1,659           3.874             105
Coal Reburn + ASOFA...................             51.8           0.323           6,228           14.86            2,386  ..............  ..............
ASOFA.................................             37.7           0.482           3,366            1.24              369           3.479              89
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ 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.

    The State determined that the average and incremental cost
effectiveness of SCR + ASOFA was excessive given its finding that
visibility improvement would be negligible. SCR + ASOFA, when combined
with wet scrubbing 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. However, using the
same supplemental cumulative modeling it used for Milton R. Young
Station units 1 and 2, the State determined that visibility benefits
from use of SCR + ASOFA would be negligible. While the State found that
RRI + SNCR + ASOFA and SNCR + ASOFA both had reasonable average cost
effectiveness values, it found the incremental costs for RRI + SNCR +
ASOFA to be excessive given its finding that incremental visibility
improvement would be negligible. By reference to its analysis for
Leland Olds Station Unit 1, North Dakota noted the difficulty in
accurately predicting costs for SCR based on alleged uncertainties
regarding catalyst size and life. North Dakota accepted the cost
estimates provided by Basin Electric. The State determined that there
were no energy and non-air quality environmental impacts that would
preclude the selection of any of the control equipment alternatives.
North Dakota determined BART to be SNCR plus ASOFA with an emission
limit of 0.35 lb/MMBtu (30-day rolling average). North Dakota estimated
the cost for SNCR plus ASOFA to be $1,659 per ton of NOX
removed, and the capital and annualized costs to be $16,800,000 and
$10,870,000 per year, respectively.
    A summary of the pertinent information related to the State's
NOX BART determinations for Milton R. Young Station Units 1
and 2 and Leland Olds Station Unit 1 is provided in Table 26.

          Table 26--North Dakota BART Determinations for NOX Emissions for Milton R. Young Station Units 1 and 2 and Leland Olds Station Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        2000-2004     Baseline    BART level                            Emissions
                                         average      level of    of control                              after       Emission
           Source and unit              emissions    control (%       (%           Control device        controls    reduction        Emission limit
                                        (tons/yr)    reduction)   reduction)                            (tons/yr)    (tons/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
MRYS Unit 1..........................        8,665            0         58.1  ASOFA and SNCR.........        3,857        4,808  0.36 lb/106 Btu, 30-day
                                                                                rolling average.
MRYS Unit 2..........................       14,705            0           58  ASOFA and SNCR.........        6,392        8,313  0.35 lb/106 Btu, 30-day
                                                                                rolling average.
LOS Unit 2...........................       10,422            0         54.5  ASOFA and SNCR.........        5,904        4,518  0.35 lb/106 Btu, 30-day
                                                                                rolling average.
--------------------------------------------------------------------------------------------------------------------------------------------------------

d. EPA's Evaluation of the State's Cost Analyses for NOX
BART for Milton R. Young Station Unit 1 and 2 and Leland Olds Station
Unit 2
    As noted above, North Dakota found that the costs of SCR at Milton
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2 were
excessive and eliminated it as a control option. We propose to find
that North Dakota did not properly follow the requirements of 40 CFR
51.308(e)(1)(ii)(A) in determining NOX BART for these units.
Specifically, we propose that North Dakota did not properly or
reasonably ``take into consideration the costs of compliance.''
Instead, North Dakota relied on facility-provided cost estimates that
greatly overestimated the costs of SCR. Given that SCR is typically
considered to be a highly cost-effective control option for power
plants with cyclone boilers burning lignite, and that EPA selected a
presumptive NOX limit for cyclone units of 0.10 lb/MMBtu
based on the cost-effectiveness of SCR,\20\ we retained two consultants
(ERG and RTI, subcontractor Dr. Phyllis Fox) to independently assess
the costs of installing, operating, and maintaining these controls.
These consultants found that numerous aspects of the cost estimates for
SCR at these units, which the State relied on, were much higher than
their estimates. Our consultants revised the cost analyses using EPA's
Air Pollution Control Cost Manual,\21\ and where appropriate, costing
assumptions used in the facility-provided analyses. Their revised
analyses resulted in cost effectiveness values that are well within the
range that North Dakota, other states, and we have found cost effective
in the BART context. We have reviewed and evaluated our consultants'
reports and agree with their findings regarding SCR at Milton R. Young
Station Units 1 and 2 and Leland Olds Station Unit 2. Our consultants'
reports have been incorporated into the Technical Support Document.\22\
---------------------------------------------------------------------------

    \20\ The BART Guidelines state, ``Because of the relatively high
NOX emission rates of cyclone units, SCR is more cost-
effective than the use of current combustion control technology for
these units. The use of SCRs at cyclone units burning bituminous
coal, sub-bituminous coal, and lignite should enable the units to
cost-effectively meet NOX rates of 0.10 lb/mmbtu. As a
result, we are establishing a presumptive NOX limit of
0.10 lb/mmbtu based on the use of SCR for coal-fired cyclone units
greater than 200 MW located at 750 MW power plants.'' 40 CFR part
51, appendix Y.
    \21\ U.S. EPA, EPA Air Pollution Control Cost Manual, EPA/452/B-
02-001, 6th Ed., January 2002. The EPA Air Pollution Control Cost
Manual was formerly known as the OAQPS Control Cost Manual.
    \22\ Dr. Phyllis Fox, Revised BART Cost-Effectiveness Analysis
for Tail End Selective Catalytic Reduction at Basin Electric Power
Cooperative Leland Olds Station Unit 2. Report Prepared for U.S.
EPA, RTI Project Number 0209897.004.095, March 2011.
    ERG Minnkota SCR Cost Summaries, May 2010 and August 2011 and
EPA Region 8's Letter to Mr. Terry O'Clair dated May 10, 2010
regarding ``EPA's Comments on the NDDH's [North Dakota's] April 2010
Draft BACT Determination for NOX for the MRYS.''
---------------------------------------------------------------------------

    Table 27, below, contrasts North Dakota's low-end cost
effectiveness values for tail end SCR (TESCR) at the three units with
our estimates.\23\
---------------------------------------------------------------------------

    \23\ The facilities, and hence, North Dakota, presented a range
of cost effectiveness values for low-dust and tail-end SCR based on
the alleged uncertainties with estimating costs for SCR. A
comparison of North Dakota's high-end cost estimates would reflect
an even greater disparity with our cost estimates.

             Table 27--Contrast of TESCR Cost Effectiveness
------------------------------------------------------------------------
                                        North Dakota
                                       projected cost    EPA's projected
                Plant                    ($/ton NOX      cost ($/ton NOX
                                          removed)          removed)
------------------------------------------------------------------------
MRYS 1..............................            $4,800            $2,600
MRYS 2..............................             4,800             2,700
LOS 2...............................             4,100             1,800
------------------------------------------------------------------------

    Our Technical Support Document provides a detailed comparison
between the costing methodologies. However, a few general points can be
made that explain why our costs differ so dramatically from North
Dakota's. Both North Dakota and we used the facilities' BART
evaluations as the starting points for the assessments,\24\ and we
largely relied on the facilities' direct capital equipment costs in our
analyses.\25\ However, a major issue is that the companies used
numerous indirect cost and other accounting mechanisms that are not
included in EPA's Air Pollution Control Cost Manual (``Control Cost
Manual'') and are not adequately justified. According to the BART
Guidelines, ``cost estimates should be based on the OAQPS Control Cost
Manual, where possible'' ``[i]n order to maintain and improve
consistency.'' 70 FR 39104, 39166. The use of the Control Cost Manual
provides a reasonable standard for comparison of costs between sources
and across states, and the BART Guidelines indicate that documentation
should be provided for ``any * * * element of the calculation that
differs from Control Cost Manual.'' 70 FR 39166. Most of North Dakota's
other BART determinations did follow the Control Cost Manual and
properly provide a basis for comparison to other control equipment
installations nationally.\26\ In preparing our cost analyses, we
followed the Control Cost Manual where possible.
---------------------------------------------------------------------------

    \24\ Burns & McDonnell, BART Determination Study for Milton R.
Young Station Unit 1 and 2, Prepared for Minnkota Power Cooperative,
Inc., October 2006, Revised August 2007.
     Letter from Cris Miller, Senior Environmental Project
Administrator, Basin Electric Power Cooperative, to Terry L.
O'Clair, North Dakota Department of Health, Attaching Letter from
William DePriest, Senior Vice President, Environmental Services, to
Cris Miller, Re: BART Evaluation Update--Tail End SCR, May 27, 2009
(5/27/09 S&L Cost Analysis).
    \25\ For a detailed discussion, the reader should refer to our
consultants' reports in the Technical Support Document.
    \26\ SIP Appendix C.2, Great River Energy's Coal Creek BART
Analysis, is an example of a cost analysis submitted to North Dakota
as part of a BART submittal that does not include many of the
indirect capital costs and contingencies included in Burns &
McDonnell's analysis. Although EPA is not in agreement with every
aspect of the cost analysis in the example, it does illustrate a
case where the Control Cost Manual format is generally followed and
the estimated SCR capital costs are far less (by a factor of almost
4 for LDSCR on Unit 2, which is a smaller unit in comparison to the
example and should cost less) than what was estimated for MRYS.
---------------------------------------------------------------------------

    In addition to deviating in significant and unjustified ways from
the Control Cost Manual, the companies adopted unreasonable assumptions
related to catalyst size and life, catalyst cost, and outage
requirements for catalyst replacement. Our analyses replaced these
unreasonable assumptions with reasonable ones.
    In the case of Minnkota's analyses for Milton R. Young Station
Units 1 and 2, conducted by Minnkota's consultant, Burns & McDonnell,
the estimated total capital costs are higher by a factor of about 1.8
than would be calculated using the Control Cost Manual,

assuming the same base costs for direct capital costs.
    For indirect capital costs, Table 28 identifies the deviations from
the Control Cost Manual in the Burns & McDonnell estimates.

  Table 28--Comparison of EPA Control Cost Manual and Burns & McDonnell
                        Indirect Capital Costs 27
------------------------------------------------------------------------
                                        Control cost
                                        manual (% of     B&McD analysis
            Indirect cost              direct cap cost  (% of direct cap
                                           ``A'')          cost ``A'')
------------------------------------------------------------------------
General Facilities (Construction              0.05 x A          0.04 x A
 Mgt)...............................
Engineering & Home Office Fees......          0.10 x A          0.15 x A
Startup Expenses....................                 0          0.02 x A
Process Contingency (Scope                    0.05 x A          0.15 x A
 Contingency).......................
Project Contingency (Pricing                  0.18 x A          0.15 x A
 Contingency).......................
                                     -----------------------------------
    Totals..........................          0.38 x A          0.51 x A
------------------------------------------------------------------------

    While this difference is significant, Burns & McDonnell then added
two more contingencies (``cost escalation during project'' and
``owner's costs--other'') and included an allowance for funds during
construction (interest) before calculating the total capital
investment. The Control Cost Manual allows for ``preproduction costs''
of 2% of the sum of the direct capital costs, indirect capital costs,
and ``project contingency.'' Table 29 below compares these ``other''
costs used by Burns & McDonnell to the preproduction costs provided by
the Control Cost Manual. To normalize these costs with those tabulated
above, percentages were related back to the direct capital costs
(``A'').\28\
---------------------------------------------------------------------------

    \27\ Although, Burns & McDonnell stated in its December 11, 2010
submittal to the State that its BACT cost estimates ``follow the
outline of Table 2.5 in the SCR Chapter of EPA's Control Cost
Manual,'' many items do not match in description, so some
assumptions had to be made. Where there are differences, the Burns &
McDonnell cost title is in parentheses. Also, this comparison
assumes that ``project contingency'' of 15% is part of the indirect
costs, so when applied exclusively to the direct capital costs only,
it becomes 18%.
    \28\ Preproduction costs are listed as being 2% of the total
direct (A), indirect (B), and ``project contingency'' (C) costs.
This becomes 3% of the total direct capital costs. (B = 0.20 * A; C
= 0.18 * A; A + B + C = 1.38 A; 0.02 * 1.38 A = 0.03).

    Table 29--Comparison of EPA Control Cost Manual & B&McD ``Other''
                              Capital Costs
------------------------------------------------------------------------
                                        Control cost
                                        manual (% of     B&McD analysis
             Other costs               direct cap cost  (% of direct cap
                                           ``A'')          cost ``A'')
------------------------------------------------------------------------
Cost Escalation.....................                 0          0.30 x A
Allowance for Funds During                           0          0.20 x A
 Construction (Interest During
 Construction)......................
Preproduction Costs.................          0.03 x A                 0
Owners Cost--Other (Owner                            0          0.17 x A
 Contingency).......................
                                     -----------------------------------
    Totals..........................          0.03 x A          0.67 x A
------------------------------------------------------------------------

    From these tables, it is clear that Burns & McDonnell included
contingencies and accounting items that deviate significantly from the
Control Cost Manual and which it did not justify by reference to any
need unique to Milton R. Young Station. Although North Dakota asked
Burns & McDonnell to provide a detailed explanation regarding its high
indirect capital cost estimates, Burns & McDonnell's February 11, 2010,
response to this request (see SIP Appendix C.4) fails to justify why
the Burns & McDonnell cost methodology should be allowed for the Milton
R. Young Station analysis, when it is not part of the Control Cost
Manual and is not the standardized methodology used by other sources.
    While the Control Cost Manual does contemplate some flexibility in
some contingencies (such as degree of retrofit difficulty), Burns &
McDonnell has not substantiated the need to go beyond standard
contingencies provided by the Control Cost Manual. As stated in the
Control Cost Manual, ``[c]ontingencies is a catch-all category that
covers unforeseen costs that may arise, such as possible redesign and
modification of equipment, escalation increases in cost of equipment,
increase in field labor costs, and delays encountered in start-up.''
\29\ Thus, the contingency in the Control Cost Manual should already
account for possible changes in labor costs, and inclusion of a
contingency plus escalation of costs is redundant according to the
Control Cost Manual methodology. Escalation of costs should not be
included as a separate estimate in the estimate of Total Capital
Investment since it is included as part of the contingency estimate.
---------------------------------------------------------------------------

    \29\ See Control Cost Manual, 2002, Chapter 2, Section 2.3.1.
---------------------------------------------------------------------------

    Also, in Table 2.5 of the SCR chapter of the Control Cost Manual,
the ``Allowance for Funds During Construction'' (inflation) is
specifically listed as zero. Therefore, Burns & McDonnell should not
have added what amounts to 20% of the direct capital costs to cover
inflation. Including ``owner's costs'' and ``owner's contingency'' is
also not consistent with the Control Cost Manual methodology and
appears to be redundant.
    Burns & McDonnell mentioned that it anticipated that significant
retrofit work would be required that would affect the scope and price
of the project. However, there have been many SCR retrofits facing much
more difficult challenges with space limitations and boiler
modifications than Milton R. Young Station can be expected to face
installing a LDSCR or TESCR

downstream of the ESP (or flue gas desulfurization system (FGD)) in a
rural location. Thus, we find that Burns & McDonnell's contingencies
for extra retrofit work are not warranted. Instead, we find that the
contingencies outlined in the Control Cost Manual (5% process
contingency and 15% project contingency) are reasonable for purposes of
the Milton R. Young Station NOX BART analyses.
    Our estimate of total installed capital costs with adjusted
indirect capital costs for TESCR at Milton R. Young Station Unit 1 is
$120,629,000 in 2009 dollars, compared to Burns & McDonnell's estimate
of $192,830,000. For Unit 2 our estimate is $216,870,000 and Burns &
McDonnell's is $329,150,000.
    When it calculated annual costs for SCR at Milton R. Young Station,
Burns & McDonnell also deviated from the Control Cost Manual without
reasonable justification and relied on unreasonable operation and
design assumptions. For example, the Control Cost Manual provides an
annual maintenance factor of 1.5% of the total capital investment.
Burns & McDonnell assumed 3%. The Control Cost Manual does not allow
annual operation and maintenance costs to be ``levelized''--i.e.,
adjusted based on predicted future inflation and other factors. Burns &
McDonnell levelized these costs, which increased them by about 25%. The
reason the Control Cost Manual does not use levelized costs is to
ensure that cost comparisons are made on a current real dollar basis,
relying on the most accurate information available at current prices.
(See, Control Cost Manual, Section 1, chapter 1, p. 1-3, footnote 1,
and Section 4.2, Chapter 2, p. 2-50, example problem.)
    Regarding operation and design assumptions, Burns & McDonnell
assumed that the SCR catalyst might have to be replaced as frequently
as three or four times per year. Given that catalyst poisons will be
removed by the ESP, or ESP and SO2 controls, before reaching
the SCR in a low-dust or tail-end configuration, Burns & McDonnell's
assumption about catalyst replacement is unreasonable. While Burns &
McDonnell's low-end SCR cost numbers are based on a two-year frequency
for catalyst replacement, our consultants find that a three-year
frequency is the most reasonable assumption.\30\ Burns & McDonnell also
used unreasonable assumptions related to catalyst cost and necessary
outage time and related electricity costs for catalyst replacement. For
example, Burns & McDonnell failed to consider that catalyst replacement
could occur during outages already occurring at the plant. Our
Technical Support Document contains additional details regarding the
flaws in Burns & McDonnell's analysis.
---------------------------------------------------------------------------

    \30\ Report of Hans Hartenstein: On North Dakota Department of
Health's April 10, 2010 BACT Determination for Minnkota's M.R. Young
Station, On Behalf of United States Department of Justice, April
2010. Report of Phyllis Fox: Revised BART Cost Effectiveness
Analysis for Tail-End Selective Catalytic Reduction at the Basin
Electric Power Cooperative Leland Olds Station Unit 2 Final Report,
March 2011.
---------------------------------------------------------------------------

    Burns & McDonnell's estimate for total annual costs for TESCR at
Milton R. Young Station Unit 1 was $43,290,000; using the Control Cost
Manual factors and other reasonable assumptions, our estimate is
$24,176,000. Burns & McDonnell's estimate for Unit 2 was $73,245,000
and ours is $40,570,000.
    Sargent & Lundy, Basin Electric's consultant, also employed
numerous unreasonable assumptions in estimating costs and cost
effectiveness for NOX BART at Leland Olds Station Unit 2.
For example, Sargent & Lundy overestimated catalyst volume, catalyst
cost, outage time for catalyst replacement, and frequency of catalyst
replacement. Our consultant, Dr. Phyllis Fox, details in her report
that Sargent & Lundy's estimates are often unsupported and why they are
unreasonable. Also, like Burns & McDonnell, Sargent & Lundy levelized
operation and maintenance costs, which increased these costs by about
20%. As noted above, levelizing these costs is inconsistent with the
Control Cost Manual. Sargent & Lundy assumed that a sorbent injection
system might be needed if SCR were installed. As Dr. Fox explains, no
such system is needed since catalyst formulations are available to
minimize sulfuric acid mist emissions. In addition, Sargent & Lundy
used inflated values for the costs of utilities and supplies, including
NH3,\31\ natural gas, and electricity. Further detail
regarding these issues is contained in section V.D.1.d of this action
and in our TSD. Table 30 contains a summary of some of the most
significant differences between Sargent & Lundy's estimates and Dr.
Fox's estimates.
---------------------------------------------------------------------------

    \31\ In the case of NH3, Sargent & Lundy evaluated a
range of costs of $450 per ton to $700 per ton even though it used a
cost of $475 per ton in a September 2010 BART analysis for the
Navajo Generating Station. Our consultant used $475 per ton in her
cost analysis.

 Table 3--Comparison of Sargent & Lundy and Dr. Fox's Tail-End SCR Variable Operation and Maintenance Costs for
                                           Leland Olds Station Unit 2
                                                 [2009 dollars]
----------------------------------------------------------------------------------------------------------------
                                                                               Dr. Fox (MM$/     Sargent & Lundy
                Description                            Cost factor                 year)           (MM$/year)
----------------------------------------------------------------------------------------------------------------
Ammonia....................................  ..............................              2.116             1.655
Catalyst...................................  ..............................              0.321             3.960
Power......................................  ..............................              1.879             2.930
Natural Gas for Flue Gas Reheating.........  ..............................              2.596             7.750
Outage Penalty.............................  ..............................              0                 7.392
Sorbent Injection..........................  ..............................              0                 0.207
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    Total Variable O&M Cost, A.............  Sum of Various Items Listed                 6.913            23.894
                                              Above.
                                            --------------------------------------------------------------------
    Total Fixed O&M Cost, B................  ..............................              0.824             0.827
Total O&M Cost.............................  A + B.........................              7.737            24.721
Levelized for Inflation, Discount Rate, and  (A + B) x 1.193...............  .................            29.496
 Equipment Life \1\.
                                            --------------------------------------------------------------------
    Total Annual Capital Cost, C...........  ..............................             14.361            14.423
                                            --------------------------------------------------------------------

    Total Annual Cost......................  A + B + C.....................             22.098        43.919 \2\
----------------------------------------------------------------------------------------------------------------
\1\ Levelization is included only in the Sargent & Lundy analysis and is not part of the acceptable methods
  presented in the Control Cost Manual.
\2\ Note: The Sargent & Lundy cost breakdown obtained during our review and included in the Technical Support
  Document, when summed, does not exactly match the total annual cost of $43,830,000 provided in SIP Appendices
  B.1 and C.1.

    We also question Sargent & Lundy's estimated capital cost of $373/
kW (2010 dollars) to retrofit SCR at Leland Olds Station. Sargent &
Lundy provided no documentation for this figure, and it is higher than
the actual installed cost for existing retrofit SCRs, including those
with extreme retrofit difficulty and those requiring flue gas reheat.
Despite our concern about Sargent & Lundy's capital cost estimate, we
used it in our cost analysis. Thus, we consider our resulting cost
effectiveness value to be conservative in Basin Electric's favor and to
represent an upper bound for a reasonable cost effectiveness value for
SCR (i.e., it is our opinion that the actual cost effectiveness value
would be lower than our estimate suggests). Our Technical Support
Document contains additional details regarding our concerns regarding
Sargent & Lundy's capital cost estimate for SCR.
    Sargent & Lundy's estimate for total annual costs for TESCR at
Leland Olds Station Unit 2 was $43,830,000; using the Control Cost
Manual factors and other reasonable assumptions, our estimate is
$22,098,000.
    North Dakota's estimates for TESCR ($4,100--$7,100), based on
company-supplied estimates, are roughly two to three times higher than
estimates that are based on accepted estimating practices.\32\ These
differences are significant, particularly because our revised cost
estimates fall within the range that North Dakota, other states, and
EPA have considered as being cost effective for BART determinations.
Accordingly, we do not consider North Dakota's cost estimates to be
consistent with the statutory and regulatory requirement that North
Dakota consider cost in determining BART. Thus, the BART analyses for
these units do not meet the requirements of the regional haze
regulation, and we are proposing to disapprove those analyses and the
resultant BART determinations.
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    \32\ They are also much higher than the values EPA relied on in
determining that SCR is cost effective on coal-fired cyclone units
for purposes of determining presumptive NOX BART limits
in the BART Guidelines: ``Our analysis indicated that cost-
effectiveness of applying SCR on coal-fired cyclone units is
typically less than $1500 a ton, and that the average cost-
effectiveness is $900 per ton.'' 70 FR 39135-39136.
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e. EPA's Evaluation of the State's Visibility Analyses for
NOX BART for Milton R. Young Station Unit 1 and 2 and Leland
Olds Station Unit 2
    Generally, to evaluate visibility improvements associated with
potential BART control options, North Dakota conducted or relied on
CALPUFF modeling that was consistent with the recommended approach in
the BART Guidelines and the State's EPA-approved protocol included in
Appendix A.1 of its Regional Haze SIP. Such modeling assumes natural
background conditions--i.e., without emissions from current emissions
sources. However, for its NOX BART determinations for Milton
R. Young Station Units 1 and 2 and Leland Olds Station Unit 2, North
Dakota conducted supplemental cumulative visibility modeling--i.e.,
modeling that included emissions from all other sources in the
inventory. North Dakota did not use this alternative modeling approach
for any other pollutant or any other BART units within North Dakota.
    The State attached considerable weight to the results of this
alternative modeling when it determined NOX BART for the
three units. SIP appendices B.1 and B.4. The State stated that it
conducted this supplemental cumulative modeling because ``the single
source modeling under the BART Guidelines overestimates the visibility
improvement'' and ``single-source modeling results * * * tend to be
five to seven times larger'' than results when the same source is
combined with all other sources in a cumulative analysis. Id. SIP
Section 7.4.2. Based on its supplemental cumulative modeling, the State
determined that the visibility improvement that would result from SCR
would be ``negligible'' and proceeded to eliminate SCR based on ``the
excessive cost and negligible visibility improvement.'' SIP appendices
B.1 and B.4.
    The perceived change in visibility from controls on a single source
is reduced when background contributions from other sources are
included in the modeling. In other words, cumulative modeling reduces
the predicted visibility benefit in deciviews from any level of control
considered. For three units and one pollutant only, North Dakota relies
on its supplemental cumulative modeling as a partial basis to reject
SCR as BART. Not only is North Dakota's approach arbitrary, it is
inconsistent with the purpose of BART and the regional haze program
generally, as well as the BART modeling approach used by other states
and EPA.
    The CAA establishes a National goal of eliminating man-made
visibility impairment from all mandatory Class I Federal areas. Use of
natural background (i.e., not considering other source emissions) in
the BART context is consistent with the ultimate goal of the program to
reach natural background conditions. Also, the modeling of visibility
improvements from potential control options should be consistent with
the subject-to-BART modeling, which compares single-source impacts to
natural conditions. Otherwise, BART, one of the primary requirements
under the regional haze regulations, could be reduced as to be
meaningless. Thus, the BART Guidelines direct states to ``[c]alculate
the model results for each receptor as the change in deciviews compared
against natural visibility conditions.'' 40 CFR part 51, appendix Y,
section IV.D, step 5. The consistent use of a clean background in BART
evaluations in North Dakota and surrounding states will foster emission
reductions that will speed achievement of natural background
conditions, and will ensure equity among states in achieving this goal.
    Because North Dakota relied on a visibility modeling method that is
inconsistent with the BART Guidelines, its own EPA-approved protocol,
and the purpose of the Regional Haze Rule, we do not consider North
Dakota's analysis of visibility improvement for NOX

BART for the three units to be reasonable.\33\ We propose to find that
North Dakota's analysis is inconsistent with the statutory and
regulatory requirement that North Dakota consider ``the degree of
improvement in visibility which may reasonably be anticipated to result
from the use of such technology.'' Thus, the BART analyses for these
units do not meet the requirements of the regional haze regulation, and
we are proposing to disapprove those analyses and the resultant BART
determinations.\34\
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    \33\ In fact, by adopting a different set of rules for modeling
the visibility benefits of SCR at MRYS and LOS, it appears that
North Dakota singled these units out for preferential treatment
without a valid justification.
    \34\ In addition to the cost and visibility issues, we disagree
with North Dakota that separate NOX limits during startup
at Milton R. Young Station Units 1 and 2 are necessary or represent
BART. The SIP does not demonstrate that such special treatment is
appropriate or needed. We find that a 30-day rolling average limit
is adequate to address emissions variations that may result from
startup at a facility that is properly managing its operations. We
also note that no other source sought or was granted a separate
limit during startup. This forms another basis for our proposed
disapproval of the NOX BART limits for Milton R. Young
Station Units 1 and 2.
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    We are proposing a FIP for NOX BART for these units to
fill the gap left by our proposed disapproval. We discuss our proposed
FIP in section V.G, below.
2. Coal Creek Station Units 1 and 2
a. Coal Creek Station Units 1 and 2--State Analysis
    Each unit is already equipped with LNB and SOFA. The State
identified the following NOX control options as having
potential application to the Coal Creek Station boilers: FGR, high-dust
SCR, ECO, Pahlman ProcessTM, LDSCR, TESCR, LTO, SNCR, and
modified and additional SOFA and LNB. The State eliminated the
following options as technically infeasible: FGR, ECO, and the Pahlman
ProcessTM. The State deemed the incremental cost of LTO,
SCR, and SNCR to be excessive. The State noted SNCR would be cost
effective except for the loss of fly ash sales due to likely
NH3 contamination. The loss of fly ash sales would add to
the cost of SNCR and SCR for Coal Creek Station, which has an