(%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Combustion Control Refinements..........................               2            0.31             104        $122,000          $1,136  ..............
Neural Network System...................................               5            0.30             260         280,000           1,043  ..............
SNCR....................................................              15            0.27             779       3,797,000           4,712            0.31
SCR.....................................................              74            0.07           3,893      25,036,709           6,299            1.01
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that SNCR was reasonable for BART for both
Unit 1 and Unit 2 based on the cost effectiveness and visibility
improvement associated with this level of control. The State determined
SCR was not reasonable because of the high cost effectiveness value.
Based upon its consideration of the five factors, the State determined
that the NOX BART emission limit for Craig Unit 1 is 0.27
lb/MMBtu (30-day rolling average) and for Unit 2 is 0.27 lb/MMBtu (30-
day rolling average). The State assumed that the BART emission limits
can be achieved through the operation of SNCR. We agree with the
State's BART determination that an emission limit of 0.27 lb/MMBtu is
NOX BART for Craig Unit 1 and Unit 2. The State arrived at
this limit based on a reasonable consideration of the five factors.
    Although the State determined that 0.27 lb/MMBtu was NOX
BART for Craig Unit 1 and Unit 2, the State adopted a more stringent
emission limit for Craig Unit 2 in its SIP and a slightly less
stringent limit for Unit 1. Tri-State and the State agreed to a
NOX emissions control plan for Craig Unit 1 and Unit 2 that
is more stringent overall. It consists of emission limits associated
with the operation of SNCR for Unit 1 and the operation of SCR for Unit
2. These NOX emission limits are 0.28 lb/MMBtu (30-day
rolling average) for Craig Unit 1 and 0.08 lb/MMBtu (30-day rolling
average) for Craig Unit 2. The State adopted these emission limits in
its SIP, and these are the emission limits Tri-State must meet for
purposes of the RH program. We are proposing to approve the State's
NOX emission limits for Craig Unit 1 and for Craig Unit 2 as
satisfying the requirements of 40 CFR 51.308(e).

PM BART Determination

    Craig Units 1 and 2 are each equipped with fabric filter baghouses
to control PM emissions with an emission limit of 0.03 lb/MMBtu. Stack
tests show that the fabric filter baghouses are achieving a 99%
reduction in PM. Fabric filter baghouses are the most stringent control
technology for controlling PM emissions. The State also evaluated what
would constitute the most stringent level of control for PM by looking
at recent BACT determinations. Based on this evaluation, the State
determined that an emission limit of 0.03 lb/MMBtu represents the most
stringent level of control for this type of source. Consistent with the
BART Guidelines, the State did not provide a full five-factor analysis
because the State determined BART to be the most stringent control
technology and limit. The State determined that the PM BART emission
limit is 0.03 lb/MMBtu (30-day rolling average) at Craig Unit 1 and
Craig Unit 2. The State assumes the BART emission limits can be met
through the operation of the current fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM BART determinations for Craig Unit 1 and Unit 2.
v. PSCO Hayden Station Units 1 and 2

Background

    The Hayden facility is located four miles east of Hayden, Colorado
in Routt County. This facility consists of two steam driven turbine/
generator units, Units 1 and 2, and the associated equipment needed for
generating electricity. Unit 1 is a pulverized-coal front-fired dry-
bottom boiler, firing coal, with natural gas and No. 2 fuel oil used
for startup, shutdown, and/or flame stabilization. Unit 2 is a
pulverized-coal tangentially-fired dry-bottom boiler, firing coal, with
No. 2 fuel oil used for startup, shutdown, and/or flame stabilization.
Units 1 and 2 are the only subject-to-BART units at the facility. The
State's BART determination for Hayden Units 1 and 2 can be found in
Chapter <IP_ADDRESS> and Appendix C of the SIP.

SO2 BART Determination

    PSCO Hayden Units 1 and 2 are currently controlled with LSDs. Both
units have a current SO2 emission limit of 0.16 lb/MMBtu
(30-day rolling average) and a requirement to achieve an 82% reduction
of SO2 (30-day rolling average). As mentioned earlier, if a
BART source has current SO2 controls achieving at least 50%
control, then the state needs to evaluate upgrades to the existing
control technology but does not need to consider the replacement of
that technology. The State's BART analysis evaluated numerous LSD
upgrades including: (1) Use of performance additives; (2) use of more
reactive sorbent; (3) increasing the pulverization

level of sorbent; (4) engineering redesign of atomizer or slurry
injection system (including an additional scrubber vessel); and (5)
additional equipment and maintenance. The State determined that the
application of the first three upgrades in the list above would not
result in lower SO2 emissions. The State determined that
engineering redesign using an additional scrubber vessel and additional
equipment and maintenance were technically feasible and would
potentially achieve SO2 emissions reductions.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. Baseline SO2 emissions are 1,172 tpy for Unit 1
and 1,469 tpy for Unit 2 based on the average of 2006-2008 actual
emissions. A summary of the State's SO2 BART analysis and
the visibility impacts is provided in Tables 14 and 15 below. The
emission rate for each control option in the tables is reflective of
the 30-day rolling average contained in the State's BART analysis.

                                                  Table 14--Summary of Hayden Unit 1 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Additional Equipment and Maintenance....................             5.2            0.13              61        $141,150          $2,317             .10
Additional Scrubber Vessel..............................            41.7            0.08             488       4,142,538           8,490            0.14
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                  Table 15--Summary of Hayden Unit 2 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Additional Equipment and Maintenance....................             2.7            0.13              39        $141,150          $3,626            0.21
Additional Scrubber Vessel..............................            40.1            0.08             589       4,808,896           8,164            0.26
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that the cost of an additional scrubber vessel
was not reasonable for BART controls. The State determined that
additional equipment and maintenance was reasonable for SO2
BART controls and that a more stringent 30-day rolling SO2
limit represents an appropriate level of emissions control for BART for
Hayden Units 1 and 2. Based on its consideration of the five factors,
the State has determined that the SO2 BART emission limit
for Hayden Unit 1 is 0.13 lb/MMBtu (30-day rolling average) and for
Unit 2 is 0.13 lb/MMBtu (30-day rolling average). The State assumes the
BART emission limit can be met with the operation of the existing LSD.
    We agree with the State's conclusions, and we are proposing to
approve its SO2 BART determinations for Hayden Unit 1 and
Unit 2.

NOX BART Determination

    Hayden Units 1 and 2 are currently controlled with LNBs plus OFA,
achieving emission reductions of 54 percent and 33 percent,
respectively. The State determined that upgrades to the existing LNBs,
SNCR, and SCR were technically feasible. The State determined that ECO,
RRI, ROFA, and coal reburn plus SNCR were not technically feasible. The
State did not identify any energy or non-air quality environmental
impacts that would preclude the selection of any of the controls
evaluated, nor are there any remaining-useful-life issues for this
source. Baseline NOX emissions are 3,750 tpy for Unit 1 and
3,743 tpy for Unit 2 based on the average of 2006-2008 actual
emissions. A summary of the State's NOX BART analysis and
the visibility impacts is provided in Tables 16 and 17 below. The
emission rate for each control option in the tables is reflective of
the 30-day rolling average contained in the State's BART analysis.

                                                  Table 16--Summary of Hayden Unit 1 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................              37            0.30           1,391        $572,010            $411            0.69
SNCR....................................................              37            0.30           1,391       1,353,500             973            0.69
SCR.....................................................              83            0.08           3,120      10,560,612           3,385            1.12
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                  Table 17--Summary of Hayden Unit 2 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNBs....................................................              35            0.24           1,303        $992,729            $762            0.40
SNCR....................................................              43            0.21           1,610       1,893,258           1,176            0.48
SCR.....................................................              81            0.07           3,032      12,321,491           4,064            0.85
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on its consideration of the five factors, the State has
determined that the NOX BART emission limit for Hayden Unit
1 is 0.08 lb/MMBtu (30-day rolling average) and for Unit 2 is 0.07 lb/
MMBtu (30-day rolling average). The State assumes the BART emission
limit can met through the installation and operation of SCR.
    We agree with the State's conclusions, and we are proposing to
approve its NOX BART determinations for Hayden Unit 1 and
Unit 2.

PM BART Determination

    Hayden Units 1 and 2 are each equipped with fabric filter baghouses
to control PM emissions with an emission limit of 0.03 lb/MMBtu. Stack
tests show that the fabric filter baghouses are achieving a 99%
reduction in PM. Fabric filter baghouses are the most stringent control
technology for controlling PM emissions. The State also evaluated what
would constitute the most stringent level of control for PM by looking
at recent BACT determinations. Based on this evaluation, the State
determined that an emission limit of 0.03 lb/MMBtu represents the most
stringent level of control for this type of source. Consistent with the
BART Guidelines, the State did not provide a full five-factor analysis
because the State determined BART to be the most stringent control
technology and limit. The State has determined that the PM BART
emission limit is 0.03 lb/MMBtu (30-day rolling average) for Hayden
Unit 1 and Unit 2. The State assumes the BART emission limit can be met
through the operation of the current fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM BART determinations for Hayden Unit 1 and Unit 2.
vi. CSU Martin Drake Units 5, 6, and 7

Background

    The CSU's Martin Drake facility is located in Colorado Springs,
Colorado. This facility consists of three steam driven turbine/
generator units, Units 5, 6, and 7, and the associated equipment needed
for generating electricity. Units 5, 6, and 7 are the only BART-
eligible units at the facility. These units fire coal as the primary
fuel and use natural gas for backup and startup. All three boilers are
pulverized-coal, dry-bottom, front-fired boilers. The State's BART
determination for CSU Martin Drake can be found in Chapter <IP_ADDRESS> and
Appendix C of the SIP.

SO2 BART Determination

    Martin Drake Units 5, 6, and 7 are currently uncontrolled for
SO2. The State determined that DSI was technically feasible
for all three units and that dry FGD was technically feasible for Units
6 and 7. The State determined dry FGD was not technically feasible for
Unit 5 because of space constraints surrounding this unit. The State
also examined emission limit tightening based on current operations for
Unit 5.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. Baseline SO2 emissions are 1,269 tpy for Unit
5, 2,785 tpy for Unit 6, and 4,429 tpy for Unit 7 based on an average
of 2006-2008 actual emissions. A summary of the State's SO2
BART analysis and the visibility impacts is provided in Tables 18, 19,
and 20 below. The emission rate for each control option in the tables
is reflective of the 30-day rolling average contained in the State's
BART analysis.

                                               Table 18--Summary of Martin Drake Unit 5 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     Effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.26             762      $1,340,663          $1,760            0.12
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                               Table 19--Summary of Martin Drake Unit 6 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.34           1,671      $2,234,438          $1,741            0.18
Dry FGD.................................................              82            0.15           3,632       6,186,854           2,709            0.24
Dry FGD.................................................              85            0.13           2,368       6,647,835           2,808            0.25

Dry FGD.................................................              90            0.09           2,507       7,452,788           4,064            0.26
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                               Table 20--Summary of Martin Drake Unit 7 SO2 BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI.....................................................              60            0.35           2,657      $3,732,826          $1,405            0.29
Dry FGD.................................................              82            0.16           3,632       8,216,863           2,263            0.39
Dry FGD.................................................              85            0.13           3,764       8,829,321           2,345            0.40
Dry FGD.................................................              90            0.09           3,986       9,898,382           2,483            0.41
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State also examined emission limits tightening based on current
operations for Unit 5. (The State did not evaluate emissions limit
tightening on Units 6 and 7 because the State determined BART to be the
most stringent control technology). In order to evaluate emissions
limit tightening, the State analyzed actual emission data for Unit 5
from the baseline period of 2006-2008. The State found that the maximum
30-day rolling emission rate for Unit 5 was 0.83 lb/MMBtu. The State
applied a 5 percent buffer to the maximum 30-day rolling emission rate
because the Drake facility has limited coal storage capacity and blends
four different types of coals. These factors can lead to a greater
fluctuation in emissions. Assuming no new control technology for Unit 5
and a 5 percent buffer, the State determined that an appropriate
SO2 emission limit would be 0.9 lb/MMBtu on a 30-day rolling
average, which is less control than would be achieved with DSI.
    Based upon its consideration of the five factors, the State
determined that the following are the SO2 BART limits for
Drake Units 5, 6, and 7: 0.26 lb/MMBtu (30-day rolling average) for
Unit 5; 0.13 lb/MMBtu (30-day rolling average) for Unit 6; and 0.13 lb/
MMBtu (30-day rolling average) for Unit 7. The State assumes the BART
emission limits can be met with the installation and operation of DSI
on Unit 5 and the installation and operation of dry FGD on Unit 6 and
Unit 7. The State determined that a lower emissions limit (0.09 lb/
MMBtu) for Units 6 and 7 was not reasonable because the increased
control costs to achieve such an emissions limit would not provide
significant improvements in visibility (0.01 delta dv for each unit
respectively).
    We agree with the State's conclusions, and we are proposing to
approve its SO2 BART determinations for Martin Drake Unit 5,
Unit 6, and Unit 7.

NOX BART Determination

    Martin Drake Units 5, 6, and 7 are currently controlled with LNBs
achieving 54.7%, 52.8%, and 57.7% control, respectively. The State's
BART analysis shows that OFA, ULNBs, ULNBs plus OFA, SNCR, SNCR plus
ULNBs, and SCR are technically feasible for reducing NOX
emissions at Drake Units 5, 6 and 7. The State determined that RRI,
ECO, and coal reburn plus SNCR were technically infeasible.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. Baseline NOX emissions are 768 tpy for Unit 5,
1,413 tpy for Unit 6, and 2,081 tpy for Unit 7 based on an average of
2006-2008 actual emissions. A summary of the State's NOX
BART analysis and the visibility impacts is provided in Tables 21, 22,
and 23 below. The emission rate for each control option in the tables
is reflective of the 30-day rolling average contained in the State's
BART analysis.

                                               Table 21--Summary of Martin Drake Unit 5 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                                improvement
                                                                           Emission rate     Emission                          Cost        (delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.35             154        $141,844            $923            0.07
ULNBs...................................................              26            0.32             200         147,000             736            0.08
ULNBs + OFA.............................................              28            0.31             215         288,844           1,342            0.08
SNCR....................................................              30            0.30             231       1,011,324           4,387            0.08
ULNB/SCR layered approach...............................            81.5            0.08             626       4,467,000           7,133            0.12
SCR.....................................................            81.5            0.08             626       4,580,349           7,314            0.12
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                               Table 22--Summary of Martin Drake Unit 6 NOX BART Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                                improvement
                                                                           Emission rate     Emission                          Cost        (Delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.38             283        $104,951            $371            0.18
SNCR....................................................              30            0.33             424       1,208,302           2,851            0.19
ULNBs...................................................              32            0.32             452         232,800             515            0.20
ULNBs + OFA.............................................              36            0.31             509         337,751             664            0.19
ULNB/SCR layered approach...............................              83            0.08           1,175       6,182,800           5,260            0.27
SCR.....................................................              83            0.08           1,175       6,340,797           5,395            0.27
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                               Table 23--Summary of Martin Drake Unit 7 NOX Bart Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                                improvement
                                                                           Emission rate     Emission                          Cost        (Delta dv for
                   Control technology                         Control     (lb/MMBtu) (30-    reduction      Annualized     effectiveness    the maximum
                                                          efficiency (%)    day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA.....................................................              20            0.36             416         $75,217            $181            0.22
SNCR....................................................              28            0.33             583         386,000             662            0.24
ULNBs...................................................              30            0.32             624       2,018,575           3,233            0.26
ULNBs + OFA.............................................              36            0.29             749         461,217             616            0.24
ULNB/SCR layered approach...............................              80            0.08           1,709       8,196,000           4,797            0.37
SCR.....................................................              80            0.08           1,709       8,510,067           4,981            0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State determined that ULNBs plus OFA constitute BART based on
the low dollars-per-ton control costs and the visibility improvement
afforded by this control technology. The State did not choose SNCR as
that technology provides a similar level of NOX reduction
and visibility improvement as ULNBs plus OFA, but at a higher cost per
ton of pollutant removed. The State determined SCR was not cost
effective for any of the units when compared with the visibility
improvement.
    Based upon its consideration of the five factors, the State
determined that the following are the NOX BART limits for
Drake Units 5, 6, and 7: 0.31 lb/MMBtu (30-day rolling average) for
Unit 5 and Unit 6; and 0.29 lb/MMBtu (30-day rolling average) for Unit
7. The State assumes that the BART emission limits can be achieved
through the installation and operation of ULNBs plus OFA.
    We agree with the State's conclusions, and we are proposing to
approve the State's NOX BART determinations for Martin Drake
Units 5, 6, and 7.

PM BART Determination

    Martin Drake Units 5, 6, and 7 are each equipped with fabric filter
baghouses to control PM emissions with an emission limit of 0.03 lb/
MMBtu. Stack tests show that the fabric filter baghouses are achieving
a 95% reduction in PM. Fabric filter baghouses are the most stringent
control technology for controlling PM emissions. The State also
evaluated what would constitute the most stringent level of control for
PM by looking at recent BACT determinations. Based on this evaluation,
the State determined that an emission limit of 0.03 lb/MMBtu represents
the most stringent level of control for this type of source. Consistent
with the BART Guidelines, the State did not provide a full five-factor
analysis because the State determined BART to be the most stringent
control technology and limit.
    The State has determined that 0.03 lb/MMBtu (30-day rolling
average) is the PM BART limit for Martin Drake Units 5, 6, and 7. The
State assumes the limits can be met with the operation of the current
fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM BART determinations for Martin Drake Units 5, 6, and 7.

Summary of Colorado's BART Determinations

    Table 24 provides a summary of the State's BART determinations that
we are proposing to approve.

                                    Table 24--Summary of the State's BART Determinations EPA Is Proposing To Approve
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Assumed particulate
           Emission unit               Assumed NOX control     NOX emission limit     Assumed SO2 control     SO2 emission limit    control and emission
                                              type                                            type                                         limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cemex-Lyons Kiln...................  SNCR..................  255.3 lbs/hr (30-day    None.................  25.3 lbs/hr (12-month  Fabric Filter
                                                              rolling average)                               rolling average)       Baghouse * 0.275 lb/
                                                              901.0 tpy (12-month                            95.0 tpy (12-month     ton of dry feed 20%
                                                              rolling average).                              rolling average).      opacity.
Cemex-Lyons Dryer..................  None..................  13.9 tpy..............  None.................  36.7 tpy.............  Fabric Filter
                                                                                Baghouse * 22.8 tons/
                                                                                yr 10% opacity.

CENC Unit 4........................  LNBs with OFA.........  0.37 lb/MMBtu (30-day   None.................  1.0 lb/MMBtu (30-day   Fabric Filter
                                                              rolling average) Or                            rolling average).      Baghouse * 0.07 lb/
                                                              0.26 lb/MMBtu                                                         MMBtu.
                                                              Combined Average for
                                                              Units 4 & 5 (30-day
                                                              rolling average).
CENC Unit 5........................  LNBS with SOFA and      0.19 lb/MMBtu (30-day   None.................  1.0 lb/MMBtu (30-day   Fabric Filter
                                      SNCR.                   rolling average) Or                            rolling average).      Baghouse * 0.07 lb/
                                                              0.26 lb/MMBtu                                                         MMBtu.
                                                              Combined Average for
                                                              Units 4 & 5 (30-day
                                                              rolling average).
Comanche Unit 1....................  LNBs *................  0.20 lb/MMBtu (30-day   Lime Spray Dryer *...  0.12 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average) 0.15                          rolling average)       Baghouse * 0.03 lb/
                                                              lb/MMBtu (combined                             0.10 lb/MMBtu          MMBtu.
                                                              annual average for                             (combined annual
                                                              units 1 & 2).                                  average for units 1
                                                                                & 2).
Comanche Unit 2....................  LNBs*.................  0.20 lb/MMBtu (30-day   Lime spray Dryer *...  0.12 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average) 0.15                          rolling average)       Baghouse * 0.03 lb/
                                                              lb/MMBtu (combined                             0.10 lb/MMBtu          MMBtu.
                                                              annual average for                             (combined annual
                                                              units 1 & 2).                                  average for units 1
                                                                                & 2).
Craig Unit 1.......................  SNCR..................  0.28 lb/MMBtu (30-day   Wet Limestone          0.11 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       scrubber *.            rolling average).      Baghouse * 0.03 lb/
                                                                                MMBtu.
Craig Unit 2.......................  SCR...................  0.08 lb/MMBtu (30-day   Wet Limestone          0.11 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       scrubber *.            rolling average).      Baghouse * 0.03 lb/
                                                                                MMBtu.
Hayden Unit 1......................  SCR...................  0.08 lb/MMBtu (30-day   Lime Spray Dryer *...  0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                MMBtu.
Hayden Unit 2......................  SCR...................  0.07 lb/MMBtu (30-day   Lime Spray Dryer *...  0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                MMBtu.
Martin Drake Unit 5................  ULNBs with OFA........  0.31 lb/MMBtu (30-day   Dry Sorbent Injection  0.26 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).                              rolling average).      Baghouse * 0.03 lb/
                                                                                MMBtu.
Martin Drake Unit 6................  ULNBs with OFA........  0.31 lb/MMBtu (30-day   Lime Spray Dryer or    0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       Equivalent Control     rolling average).      Baghouse * 0.03 lb/
                                                                                Technology.                                   MMBtu.
Martin Drake Unit 7................  ULNBs with OFA........  0.29 lb/MMBtu (30-day   Lime Spray Dryer or    0.13 lb/MMBtu (30-day  Fabric Filter
                                                              rolling average).       Equivalent Control     rolling average).      Baghouse * 0.03 lb/
                                                                                Technology.                                   MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Indicates controls that are already installed.

vii. PSCO BART Alternative
    Colorado has adopted the PSCO BART Alternative Program (BART
alternative) to meet the requirements for BART for PSCO Cherokee Unit
4, Valmont Unit 5, and Pawnee Station Unit 1 and RP for PSCO Arapahoe
Units 3 and 4 and Cherokee Units 1, 2, and 3. Under 40 CFR
51.308(e)(2), states may choose to meet the BART requirements with a
BART alternative. Section 51.308(e)(2) specifies the requirements that
a state must meet to show that the alternative measure or alternative
program achieves greater RP than would be achieved through the
installation and operation of BART. Section 51.308(e)(3) contains
additional requirements that states must address pertaining to their
alternative program. Table 25 provides a summary of the units covered
under the BART alternative, as well as the required control or shutdown
date for the facility.

                                                Table 25--Sources Covered Under the PSCO BART Alternative
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Particulate type
              Unit                 BART  eligible?     NOX control type   NOX emission uimit   SO2 control type   SO2 emission limit       and limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cherokee Unit 1.................  No...............  Shutdown by 7/1/     0.................  Shutdown by 7/1/    0.................  Shutdown by 7/1/
                                                      2012.                                    2012.                                   2012.
Cherokee Unit 2.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2011.                                    2011.                                   2011.
Cherokee Unit 3.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2016.                                    2016.                                   2016.

Cherokee Unit 4.................  Yes..............  Natural Gas          0.12 lb/MMBtu (30-  Natural Gas         7.81 tpy (12 month  Fabric Filter
                                                      Operation by 12/31/  day rolling         Operation by 12/    rolling average).   Baghouse * 0.03
                                                      2017.                average) by 12/31/  31/2017.                                lb/MMBtu.
                                                                           2017.
Valmont Unit 5..................  Yes..............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2017.                                    2017.                                   2017.
Pawnee Unit 1...................  Yes..............  SCR **.............  0.07 lb/MMBtu (30-  Lime Spray Dryer    0.12 lb/MMBtu (30-  Fabric Filter
                                                                           day rolling         **.                 day rolling         Baghouse * 0.03
                                                                           average) by 12/31/                      average) by 12/31/  lb/MMBtu.
                                                                           2014.                                   2014.
Arapahoe Unit 3.................  No...............  Shutdown by 12/31/   0.................  Shutdown by 12/31/  0.................  Shutdown by 12/31/
                                                      2013.                                    2013.                                   2013.
Arapahoe Unit 4.................  No...............  Natural Gas          600 tpy (12 month   Natural Gas         1.28 tpy (12 month  Fabric Filter
                                                      Operation by 12/31/  rolling average)    operation by 12/    rolling average)    Baghouse * 0.03
                                                      2014.                by 12/31/2014.      31/2014.            by 12/31/2014.      lb/MMBtu.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Controls are already installed.
** The State assumes this is the control technology the source will use to meet the limit.

    A summary of Colorado's BART alternative and the requirements under
40 CFR 51.308(e)(2) and (e)(3) are discussed below. The State's
analysis of the PSCO BART alternative can be found in Chapter <IP_ADDRESS>
of the SIP.
i. A List of All BART-Eligible Sources
    Pursuant to 40 CFR 51.308(e)(2)(i)(A), the State included a list of
all BART-eligible sources in the State in Chapter 6, Table 6-3 of the
SIP. A list of BART-eligible sources can also be found in Table 2 of
this notice.
ii. A List of All Sources Covered by the Alternative
    Pursuant to 40 CFR 51.308(e)(2)(i)(B), the State included in the
SIP a list of the BART-eligible sources that are included in the BART
alternative, as well as the RP sources covered under the program.
iii. Best System of Continuous Emission Control Technology
    As required by 40 CFR 51.308(e)(2)(i)(C), the State determined the
best system of continuous emission control for sources that are subject
to BART and that are covered by the BART alternative program. Because
the State's BART alternative program was designed to meet requirements
other than BART,\17\ our regulation allowed the State to use
simplifying assumptions to determine the best system of continuous
emission control for the BART sources in the State's BART alternative
program. 40 CFR 51.308(e)(2)(i)(C); 71 FR 60619. We have indicated that
our BART presumptive limits for SO2 and NOX, set
forth in our BART Guidelines (70 FR 39171-39172), represent appropriate
simplifying assumptions for determining the best system of continuous
emission control for EGUs. The presumptive limit for SO2 is
0.15 lb/MMBtu. The presumptive limits for NOX vary depending
on boiler and coal type. The State used the presumptive limits in the
BART Guidelines for calculating the best system of continuous emission
control for the BART sources in the State's BART alternative program.
The State also used the presumptive limits as a benchmark for control
levels that might have been anticipated from the non-BART sources that
are included in the BART alternative, if the State had not adopted the
BART alternative.
---------------------------------------------------------------------------

    \17\ Specifically, the program was designed to help the State
achieve its overarching reasonable progress goals and to meet the
requirements of Colorado House Bill 10-1365 and Sec.  40-3.2-202,
C.R.S.--Colorado's Clean Air-Clean Jobs Act.
---------------------------------------------------------------------------

iv. Projected Emissions Reductions
    Pursuant to 40 CFR 51.308(e)(2)(i)(D), the State provided a
calculation of the emission reductions expected from the BART
alternative compared to emissions reductions that would be achieved by
the application of the presumptive limits to sources covered under the
alternative. Tables 26 and 27 show the relative emissions.

           Table 26--SO2 Reductions Under the BART Alternative
------------------------------------------------------------------------
                                                    SO2
                                                 emissions       SO2
                                   SO2 average      with      emissions
               Unit                 emissions   presumptive   under BART
                                    2006-2008      limits    alternative
                                      (tpy)      (0.15 lb/     in 2018
                                                   MMBtu)       (tpy)
------------------------------------------------------------------------
Arapahoe Unit 3..................       924.97       328.51         0.00
Arapahoe Unit 4..................     1,764.70       640.93         1.28
Cherokee Unit 1..................     2,220.80       623.35         0.00
Cherokee Unit 2..................     1,888.37       418.95         0.00
Cherokee Unit 3..................       743.00       611.99         0.00
Cherokee Unit 4..................     2,135.43     1,953.57         7.81
Valmont Unit 5...................       758.47     1,029.19         0.00
Pawnee Unit 1....................    13,472.07     3,007.03     2,405.63
                                  --------------------------------------
    Total........................       23,908        8,614        2,415
------------------------------------------------------------------------

                               Table 27--NOX Reductions Under the BART Alternative
----------------------------------------------------------------------------------------------------------------
                                                    NOX average         NOX        NOX emissions   NOX emissions
                                                  emissions 2006-   presumptive        with         under BART
                      Unit                          2008 (tpy)      limit (lb/      presumptive   alternative in
                                                                      MMBtu)       limits (tpy)     2018 (tpy)
----------------------------------------------------------------------------------------------------------------
Arapahoe Unit 3.................................        1,770.47            0.23          503.71            0.00
Arapahoe Unit 4.................................        1,147.67            0.23          982.77          900.00
Cherokee Unit 1.................................        1,556.23            0.39        1,620.71            0.00
Cherokee Unit 2.................................        2,895.20            0.39        1,089.27            0.00
Cherokee Unit 3.................................        1,865.50            0.39        1,591.18            0.00
Cherokee Unit 4.................................        4,274.00            0.28        3,646.67        2,062.86
Valmont Unit 5..................................        2,313.73            0.28        1,921.15            0.00
Pawnee Unit 1...................................        4,537.73            0.23        4,610.78        1,403.28
                                                 ---------------------------------------------------------------
    Total.......................................          20,361  ..............          15,996           4,366
----------------------------------------------------------------------------------------------------------------

v. Evidence That the Alternative Program Achieves Greater RP Than BART
    Tables 26 and 27 demonstrate that the State's BART Alternative
achieves greater RP than would be achieved through the installation of
BART. By applying presumptive limits to the sources, the resulting
emissions would be 8,614 tpy for SO2 and 15,996 tpy for
NOX. Under the BART alternative, the emissions from the
sources in 2018 will be 2,415 tpy for SO2 and 4,366 tpy for
NOX. Thus, EPA concludes that the BART alternative achieves
greater RP than would be achieved through the installation of BART and
meets the requirements of 40 CFR 51.308(e)(2)(i)(E).
vi. All Emission Reductions Take Place During First Planning Period
    Pursuant to 40 CFR 51.308(e)(2)(ii), Table 25 shows that all
controls under the BART alternative will occur by December 17, 2017,
within the first planning period, which ends in December 2018.
vii. Reductions Are Surplus
    As required by 40 CFR 51.308(e)(2)(iv), the State has concluded
that emission controls associated with the BART alternative have not
been used for other SIP purposes and are only a requirement under the
RH SIP. The State has thus determined they are surplus. EPA agrees with
the State's assessment.
viii. Distribution of Emissions
    The State has determined that the distribution of emissions under
the BART alternative is not substantially different than under source-
by-source BART or RP. The BART alternative includes only sources that
are BART or RP sources and does not include any sources that would not
have been included in the RH SIP. All of the units in the BART
alternative are located within or adjacent to the 8-hour ozone non-
attainment area in the Front Range of Colorado. Pursuant to 40 CFR
51.308(e)(3), since the State has determined that the geographic
distribution of emissions is not substantially different under the
alternative program, the State is not required to perform visibility
modeling. We agree that the BART alternative will not result in a
significant shift in the distribution of emissions.
    EPA is proposing to approve the State's BART alternative as it
meets the requirements for alternative programs under 40 CFR
51.308(e)(2) and (e)(3).

D. Reasonable Progress Requirements

    In order to establish RPGs for its Class I areas, and to determine
the controls needed for the long-term strategy, Colorado followed the
process established in the RHR. First, Colorado identified the
anticipated visibility improvement in 2018 in all its Class I areas
using the WRAP Community Multi-Scale Air Quality (CMAQ) modeling
results. This modeling identified the extent of visibility improvement
from the baseline by pollutant for each Class I area. The modeling
relied on projected source emission inventories, which included
enforceable Federal and State regulations already in place and
anticipated BART controls.
    Colorado then identified sources and source categories (other than
BART sources) in Colorado that are major contributors to visibility
impairment and considered whether these sources should be controlled
based on a consideration of the factors identified in the CAA and EPA's
regulations. See CAA 169A(g)(1) and 40 CFR 51.308(d)(1)(i)(A).
    The SIP includes Colorado's analysis and conclusion that reasonable
progress will be made by 2018, including an analysis of pollutant
trends, emission reductions, and improvements expected. The RP
discussion and analyses are included in Chapter 8 and Appendix D of the
SIP. We are proposing to approve Colorado's submitted RP goals as
described more fully below.
1. Visibility Impairing Pollutants and Sources
a. Source Regions of Pollutants
    In order to determine the significant sources contributing to haze
in Colorado's Class I areas, Colorado relied upon two source
apportionment analysis techniques developed by the WRAP. The first
technique was regional modeling using the Comprehensive Air Quality
Model (CAMx) and the PM Source Apportionment Technology (PSAT) tool,
used for the attribution of sulfate and nitrate sources only. The
second technique was the Weighted Emissions Potential (WEP) tool, used
for attribution of sources of OC, EC, PM2.5, and
PM10. The WEP tool is based on emissions and residence time,
not modeling.
    PSAT uses the CAMx air quality model to show nitrate-sulfate-
ammonia chemistry and apply this chemistry to a system of tracers or
``tags'' to track the chemical transformations, transport, and removal
of NOX and SO2. These two pollutants are
important because they tend to originate from anthropogenic sources.
Therefore, the results from this analysis can be useful in determining
contributing sources that may be controllable, both in-state and in
neighboring states.
    WEP is a screening tool that helps to identify source regions that
have the potential to contribute to haze formation at specific Class I
areas. Unlike PSAT, this method does not account for chemistry or
deposition. The WEP combines emissions inventories, wind patterns, and
residence times of air

masses over each area where emissions occur, to estimate the percent
contribution of different pollutants. Like PSAT, the WEP tool compares
baseline values (2000-2004) to 2018 values, to show the improvement
expected by 2018, for sulfate, nitrate, OC, EC, PM2.5, and
PM10. More information on the WRAP modeling methodologies is
available in the document Technical Support Document for Technical
Products Prepared by the Western Regional Air Partnership (WRAP) in
Support of Western Regional Haze Plans in the Supporting and Related
Materials section of the docket. Table 28 shows Colorado's contribution
to extinction at its own Class I areas. Sulfate and nitrate
contribution is based on PSAT results and OC, EC, PM2.5,
PM10, and sea salt contributions are based on WEP.

                 Table 28--Colorado Sources Extinction Contribution 2000-2004 for 20% Worst Days
----------------------------------------------------------------------------------------------------------------
                                                                                CO sources
                                                                     2000-2004        Species      contribution
             Class I area                   Pollutant species     extinction (Mm-  contribution     to species
                                                                        1)           to  total      extinction
                                                                                extinction (%)      (%) \1\
----------------------------------------------------------------------------------------------------------------
GRSA1 (Great Sand Dunes National park   Sulfate.................            5.97            21.1            13.0
 and Preserve).                         Nitrate.................            1.96             6.9            14.7
                                        OC......................            8.47            30.0            34.8
                                        EC......................            1.74             6.2            39.1
                                        PM2.5...................            2.81            10.0            34.9
                                        PM10....................            7.24            25.6            37.7
                                        Sea Salt................            0.05             0.2               *
MEVE1 (Mesa Verde National Park)......  Sulfate.................            6.46            19.9             2.0
                                        Nitrate.................            2.30             7.1            10.4
                                        OC......................           12.28            37.8            35.4
                                        EC......................            2.37             7.3            35.4
                                        PM2.5...................            2.51             7.7            19.0
                                        PM10....................            6.52            20.1            15.3
                                        Sea Salt................            0.04             0.1               *
MOZI1 (Mount Zirkel and Rawah           Sulfate.................            5.25         22.69.3            26.9
 Wilderness Area).                      Nitrate.................            2.16                            39.7
                                        OC......................            9.94            42.7            90.7
                                        EC......................            1.76             7.6            87.9
                                        PM2.5...................            0.98             4.2            51.8
                                        PM10....................            3.15            13.5            48.5
                                        Sea Salt................            0.02             0.1               *
RMHQ1 (Rocky Mountain National Park)..  Sulfate.................            7.91            24.3            31.3
                                        Nitrate.................            5.26            16.2            37.8
                                        OC......................           10.51            32.3            77.4
                                        EC......................            2.56             7.9            77.1
                                        PM2.5...................            1.37             4.2            49.9
                                        PM10....................            4.90            15.1            52.2
                                        Sea Salt................            0.01             0.0               *
WEMI1 (Weminuche Wilderness, Black      Sulfate.................            4.99            23.9             5.0
 Canyon of the Gunnison, and La Garita  Nitrate.................            1.21             5.8             5.0
 Wilderness).
                                        OC......................            8.29            39.7            47.7
                                        EC......................            2.01             9.6            45.1
                                        PM2.5...................            1.26             6.0            20.7
                                        PM10....................            2.99            14.3            18.4
                                        Sea Salt................            0.13             0.6  ..............
WHRI1 (Eagles Nest Wilderness, Flat     Sulfate.................            4.79            24.3             6.5
 Tops Wilderness, Maroon Bells--        Nitrate.................            1.31             6.6            20.0
 Snowmass Wilderness, and West Elk      OC......................            7.83            39.7            60.6
 Wilderness).
                                        EC......................            1.76             8.9            61.1
                                        PM2.5...................            1.18             6.0            39.7
                                        PM10....................            2.82            14.3            35.8
                                        Sea Salt................            0.02             0.1               *
----------------------------------------------------------------------------------------------------------------
* Not modeled by the WRAP.

    Table 29 shows influences from sources both inside and outside of
Colorado per the PSAT modeling for 2018. As indicated, boundary
conditions or outside domain are the highest contributor to sulfate at
all Colorado Class I areas. The boundary conditions represent the
background concentrations of pollutants that enter the edge of the
modeling domain. Depending on meteorology and the type of pollutant
(particularly sulfate), these emissions can be transported great
distances that can include regions such as Canada, Mexico, and the
Pacific Ocean.
    Colorado appears to be a major contributor of particulate sulfate
at those Class I areas near significant sources of SO2,
specifically Rocky Mountain National Park, Mount Zirkel, and Rawah
Wilderness. For nitrate, Colorado appears to be a major contributor at
most of its Class I areas except for the Weminuche Wilderness, La
Garita Wilderness, and Black Canyon of Gunnison National Park. Boundary
conditions are also a major contributor of nitrate at all Colorado
Class I areas.
---------------------------------------------------------------------------

    \18\ OD denotes Outside Domain; MEX denotes the country of
Mexico; CEN denotes the Central Regional Air Partnership; PO denotes
Pacific Offshore.

                          Table 29--PSAT Source Region Apportionment for 20% Worst Days
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
Class I Area:                                           2018 Sulfate PSAT
                                           2018 Nitrate PSAT
----------------------------------------------------------------------------------------------------------------
    GRSA1 (Great Sand Dunes    Region \18\.....  OD       CO      NM      MEX     OD      NM      CO      CEN
     National Park and
     Preserve).
                               % Contribution..  38.2     9.7     8.1     7.9     28.9    27.2    12.3    8.8
    MEVE1 (Mesa Verde          Region..........  OD       NM      MEX     AZ      NM      CO      OD      AZ
     National Park).
                               % Contribution..  35.4     17.2    11.3    10.2    60.2    12.3    9.7     9.7
    MOZI1 (Mount Zirkel and    Region..........  OD       CO      WY      UT      CO      OD      UT      WY
     Rawah Wilderness Area).
                               % Contribution..  29.3     20.9    9.2     7.6     41.6    17.8    14.1    10.3
    RMHQ1 (Rocky Mountain      Region..........  OD       CO      WY      CEN     CO      OD      WY      UT
     National Park).
                               % Contribution..  29.1     23.5    7.7     7.2     33.7    15.8    11.0    5.9
    WEMI1 (Weminuche           Region..........  OD       NM      MEX     PO      NM      OD      CA      AZ
     Wilderness, Black Canyon
     of the Gunnison, and La
     Garita Wilderness).
                               % Contribution..  34.9     13.2    10.7    9.1     43.7    19.7    14.1    9.9
    WHRI1 (Eagles Nest         Region..........  OD       MEX     AZ      NM      OD      UT      CO      NM
     Wilderness, Flat Tops
     Wilderness, Maroon
     Bells--Snowmass
     Wilderness, and West Elk
     Wilderness).
                               % Contribution..  40.1     10.8    6.8     6.1     55.0    20.0    15.0    10.0
----------------------------------------------------------------------------------------------------------------

b. Source Categories
    The State conducted a detailed evaluation of six visibility
impairing pollutants: nitrates, sulfates, OC, EC, fine soil and coarse
mass (CM) (fine soil and CM are collectively known as PM) contributing
to visibility impairment at Colorado's Class I areas.\19\ The State
relied on WRAP emission inventory information and modeling to determine
what pollutants and sources were contributing to visibility impairment
at its Class I areas. Once the State determined what sources were
contributing to visibility impairment and by what amount, it determined
whether the source/source category was significant and if it was
reasonable to control.
---------------------------------------------------------------------------

    \19\ See Significant Source Categories Contributing to Regional
Haze at Colorado Class I Areas, October 2, 2007, located in the
Supplemental and Related Materials section of the docket.
---------------------------------------------------------------------------

    Based on its analysis, the State determined that the sources of OC,
EC, and area source PM are not well documented because of emission
inventory limitations associated with natural sources (predominantly
wildfires), uncertainty of windblown emissions, and poor model
performance for these constituents. The State determined it would defer
on addressing these pollutants until science and emission inventories
are improved for consideration in future RH SIPs. The State determined
that RP controls would be evaluated for SO2, NOX,
and stationary source PM.
    The State's analysis evaluated the projected sources of
SO2 and NOX in 2018. The State's analysis shows
that 78% of 2018 total statewide SO2 emissions are from
point sources, mainly coal-fired boilers. Area source SO2
emissions (14% of total SO2 emissions) are mainly comprised
of thousands of small commercial boilers and internal combustion
engines spread throughout the State that burn distillate fuel. The
State determined there is no practical way to control thousands of
small boilers and engines. The State determined SO2
emissions from natural fires constitute 6% of total SO2
emissions and are considered uncontrollable. Both off-road and on-road
mobile sources each constitute 1% of SO2 emissions and are
subject to federal ultra-low sulfur diesel fuel requirements that limit
sulfur content to 15 ppm. Ultra-low sulfur diesel fuel was in
widespread use after June 2010 for off-road mobile sources and after
June 2006 for on-road mobile sources. The State has determined that
point sources are the dominant source of emissions and, for this
planning period, the only practical category to evaluate under RP for
SO2.
    Colorado's analysis shows that point sources comprise 36% of total
NOX emissions; these emissions are primarily from coal-fired
external combustion boilers and natural gas-fired internal combustion
engines (in oil and gas compression service). On-road and off-road
mobile sources comprise 16% and 14% of Statewide NOX
emissions, respectively. Because mobile exhaust emissions are primarily
addressed, and will continue to be addressed, through federal programs,
the State did not evaluate mobile sources for RP control in this
planning period. Emissions of NOX from biogenic activity and
natural fire are considered uncontrollable and vary from year-to-year.
Non-oil and gas area sources comprise about 6% of NOX
emissions and involve thousands of combustion sources that the State
determined are not reasonable to control in this planning period. Area
oil and gas emissions contribute 12% of total NOX emissions.
    The State has determined that large point sources are the dominant
source of NOX emissions and are practical to evaluate under
RP in this planning period. The State determined that smaller point
sources (combustion turbines) and area oil and gas emissions,
specifically heater-treaters and reciprocating internal combustion
engines (RICE), significantly contribute to visibility impairment in
Colorado's Class I areas and are also practical to evaluate for RP
controls in this planning period.
c. Stationary Sources
    The State used a RP screening methodology called ``Q/d'' to
determine which stationary (point) sources would be candidates for
controls under RP. The methodology Q/d is a calculated ratio that
evaluates stationary source emissions (mathematical sum of actual
SO2, NOX and PM emissions in tons per year,
denoted as ``Q'') divided by the distance (in kilometers, denoted as
``d'') of the point source from the nearest Class I area. The State
evaluated the visibility impact sensitivity of different Q/d thresholds
and determined that a Q/d ratio equal to or greater than 20
approximated a delta dv impact ranging from 0.06 dv to 0.56 dv. The
resultant average of the range is about 0.3 dv, which is a more
conservative RP threshold than the 0.5 dv that was used in determining
which sources would be subject-to-BART under the federal BART
regulations. Since the threshold is more conservative than the subject-
to-BART threshold, the State determined that a Q/d value of 20 is
reasonable for determining which RP sources the State should consider
for RP controls.

    The evaluation of potential RP sources involved all Colorado
stationary sources with actual SO2, NOX, or
PM10 emissions over 100 tpy in 2007. The State identified
113 sources as exceeding the 100 tpy threshold for any of the three
pollutants and further analyzed these sources using the Q/d analysis.
The State determined that there were seven sources that had a Q/d equal
to or greater than the threshold of 20 that were not already being
controlled under BART.\20\ The State deemed these seven sources to be
subject to RP and the State completed a RP analysis for each of the
sources.
---------------------------------------------------------------------------

    \20\ The State has concluded that it need not reanalyze a source
for RP controls for which it has already made a BART determination.
This conclusion is consistent with our RP guidance.
---------------------------------------------------------------------------

    Table 30 shows the subject-to-RP sources identified by the State.

               Table 30--RP Sources Evaluated for Controls
------------------------------------------------------------------------
                                   Q  (tpy
                                   based on
             Source                  2007      Nearest Class I     Q/d
                                    actual           area         value
                                  emissions)
------------------------------------------------------------------------
Platte River Power Authority--         2,796  Rocky Mountain        49.9
 Rawhide Station.                              National Park.
CENC--Unit 3...................        4,453  Rocky Mountain        81.7
                                               National Park.
CSU-Nixon Power Plant--Nixon           6,668  Great Sand Dunes      63.9
 Unit 1.                                       National Park.
Black Hills Energy Clark Power         2,393  Great Sand Dunes      40.8
 Plant Units 1 and 2.                          National Park.
Holcim--Kiln and Dryer.........        3,250  Great Sand Dunes      49.2
                                               National Park.
Tri-State--Nucla...............        3,327  Black Canyon          47.1
                                               National Park.
Tri-State--Craig Unit 3........       20,628  Flat Tops            432.4
                                               Wilderness Area.
PSCO--Cameo Station............        3,750  Black Canyon          53.2
                                               National Park.
------------------------------------------------------------------------

    We agree with the State's analysis on appropriate source categories
and stationary sources to be evaluated under RP.
2. Four Factor Analyses
    In determining the measures necessary to make RP, states must take
into account the following four factors and demonstrate how they were
taken into consideration in selecting RP goals for a Class I area:
     Costs of Compliance;
     Time Necessary for Compliance;
     Energy and Non-air Quality Environmental Impacts of
Compliance; and
     Remaining Useful Life of any Potentially Affected Sources.
CAA Sec.  169A(g)(1) and 40 CFR 308(d)(1)(i)(A).
    The State performed a four factor analysis for each of the RP
sources pursuant to 40 CFR 51.308(d)(1)(i)(A).

State NOX Control Criteria

    For potential NOX controls in the RP context, the State
adopted the same screening criteria as used to evaluate potential
NOX BART controls. For further detail, see section V.C.3
above. We have some of the same concerns regarding the use of these
criteria for RP as we expressed concerning their use in BART
determinations. Nonetheless, as discussed below, we agree with the
State's determinations concerning NOX controls on the RP
sources.

SO2 Controls--Wet and Dry Scrubbing

    As it did in the BART context, the State eliminated wet FGD from
consideration as a potential RP control for the same reasons--because
of negative non-air quality environmental impact on water usage. EPA is
proposing that the State has provided adequate justification to
eliminate wet FGD as a potential SO2 RP control.
a. Visibility Improvement Modeling
    Colorado concluded that it is also appropriate to consider a fifth
factor for evaluating potential RP control options--the degree of
visibility improvement that may reasonably be anticipated from the use
of the RP controls. Our RP guidance contemplates that states may be
able to consider other relevant factors for RP sources (see EPA's
Guidance for Setting Reasonable Progress Goals under the Regional Haze
Program, (``Reasonable Progress Guidance''), pp. 2-3, July 1, 2007),
and we find it appropriate to consider visibility improvement when
evaluating potential RP controls.
    For the RP modeling, the State followed the BART Guidelines. The
BART Guidelines provide that states may use the CALPUFF modeling system
or another appropriate model to determine the visibility improvement
expected at a Class I area from the potential BART control technology
applied to the source. Colorado performed CALPUFF modeling to determine
the degree of visibility improvement expected at a Class I area based
on the controls evaluated for RP for the subject-to-RP sources.
    The BART Guidelines also recommend that states develop a modeling
protocol for making individual source attributions, and suggest that
states may want to consult with EPA and their RPO to address any issues
prior to modeling. Colorado used the CALPUFF model for Colorado RP
sources in accordance with a protocol it developed titled
``Supplemental BART Analysis CALPUFF Protocol for Class I Federal Area
Visibility Improvement Modeling Analysis, revised August 19, 2010,''
which was approved by EPA and is included in the Supplemental
Information section of the docket. The Colorado protocol follows
recommendations for long range transport described in appendix W to 40
CFR part 51, ``Guideline on Air Quality Models,'' and in EPA's
``Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary
Report and Recommendations for Modeling Long Range Transport Impacts,''
as recommended by the BART Guidelines. (40 CFR part 51, appendix Y,
section III.D.5).
b. Summary of RP Determinations and Limits
    For the subject-to-RP sources, the State provided analyses that
took into consideration the four factors as required by section
169A(g)(1) of the CAA. The State also included visibility improvement
as a fifth factor in its RP analyses for most sources. The State
elected to consider EPA's BART Guidelines as relevant to its RP
evaluations, in addition to EPA's Reasonable Progress Guidance. A
summary of the RP analysis for each source is included in Chapter 8 of
the SIP. The State's complete RP analyses, as well as additional
technical information and materials, are included in Appendix D of the
SIP. EPA is

proposing to approve the RP determinations submitted by the State for:
Platte River Power Authority (PRPA), Rawhide Unit 101; CENC Unit 3; CSU
Nixon Power Plant, Nixon Unit 1; Black Hills Energy Clark Power Plant,
Units 1 and 2; Holcim Florence Cement Plant; Tri-State Generation,
Nucla; Tri-State Generation, Craig Unit 3; and PSCO Cameo Station. A
summary of the RP determination for each source is provided below.
i. Platte River Power Authority--Rawhide Unit 101

Background

    The PRPA Rawhide Energy Station is located in Larimer County
approximately 10 miles north of the town of Wellington, Colorado.
Rawhide Unit 101 is a coal-fired steam-driven EGU with a rated electric
generating capacity of 305 MW (gross). The Rawhide Station also has
five natural-gas-fired combustion turbines. The primary use of these
units is to meet PRPA's energy reliability and peak load requirements.
The turbines operate on limited, intermittent, and unpredictable
schedules as peak loading units. Additionally, the facility includes a
number of fugitive dust sources. The State did not do a RP analysis for
the turbines or fugitive dust sources since these units fall below the
de minimis threshold established by the State.\21\ Unit 101 is the only
subject-to-RP unit at the facility. The State's RP determination can be
found in Chapter <IP_ADDRESS> and Appendix D of the SIP.
---------------------------------------------------------------------------

    \21\ For the purposes of evaluating RP, the State has elected to
set de minimis thresholds for any emission unit at a subject-to-RP
source with actual baseline emissions of SO2,
NOX, or PM10 less than the federal Prevention
of Significant Deterioration (PSD) significance levels. These de
minimis levels are as follows: NOx--40 tons per year;
SO2--40 tons per year; PM10--15 tons per year.
Any unit emitting below these levels is not subject to an RP
analysis. The BART Guidelines allow for states to set de minimis
levels (see 70 FR 39161), and we think it was reasonable for the
State to set de minimis levels for RP sources.
---------------------------------------------------------------------------

SO2 RP Determination

    Rawhide Unit 101 is currently controlled with a dry FGD achieving
over 72 percent SO2 reduction with a current permit limit of
0.09 lb/MMBtu (annual average). Per the BART Guidelines, for EGUs with
preexisting post-combustion SO2 controls achieving removal
efficiencies greater than 50 percent, states should consider cost
effective scrubber upgrades designed to improve the system's overall
SO2 removal efficiency (70 FR 39171). Under the BART
Guidelines, a state is not required to evaluate the replacement of the
current SO2 controls if the removal efficiency is over 50%
(70 FR 39171). We conclude that it is reasonable to follow this
approach for evaluating potential RP controls in this initial planning
period. Colorado should consider replacement of existing scrubbers in
future planning periods. The State's RP analysis evaluated numerous dry
FGD upgrades including: (1) Use of performance additives; (2) use of
more reactive sorbent; (3) increase the pulverization level of sorbent;
and (4) engineering redesign of atomizer or slurry injection system.
The State analyzed each possible upgrade and determined that all were
technically infeasible for Rawhide Unit 101. The State determined that
fuel switching from coal to natural gas was a technically feasible
option for Rawhide Unit 101.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source.
    Baseline SO2 emissions are 913 tpy based on an average
of 2006-2008 actual emissions. A summary of the State's SO2
RP analysis and the visibility impacts for fuel switching is provided
in Table 31 below.

                              Table 31--Summary of Rawhide Unit 101 SO2 RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                   Emission rate                                                    improvement
                                    (lb/MMBtu)       Emission                          Cost        (delta dv for
       Control technology             (30-day        Reduction      Annualized     effectiveness    the maximum
                                      rolling          (tpy)           costs          ($/ton)          98th
                                     average)                                                       percentile
                                                                                impact)
----------------------------------------------------------------------------------------------------------------
Fuel Switching..................            0.00             906    $237,424,331        $262,169            0.87
----------------------------------------------------------------------------------------------------------------

    The State determined it would take PRPA approximately 2-3 years to
switch from coal to natural gas. The State determined fuel switching
was not reasonable based on the high cost effectiveness value.
    The State also assessed emissions limit tightening based on current
operations. Rawhide Unit 101's average 30-day rolling emission rate
during the baseline period (2006-2008) was 0.09 lb/MMBtu. The maximum
30-day rolling emission rate during this period was 0.11 lb/MMBtu. The
State evaluated both these levels as potential emissions limits. The
State also evaluated an emission limit of 0.07 lb/MMBtu. Emissions
limit tightening to emissions levels currently achieved is a no-cost
control option. The State modeled visibility improvement for
SO2 emission limits lower than 0.11 lb/MMBtu. The modeling
showed that, compared to an emission limit of 0.11 lb/MMBtu, an
emission limit of 0.09 lb/MMBtu would result in 0.01 dvs of visibility
improvement, and an emission limit of 0.07 lb/MMBtu would result in
0.03 dvs of visibility improvement.
    The State has determined that the SO2 RP emission limit
for Rawhide Unit 101 is 0.11 lb/MMBtu (30-day rolling average),
reflecting the actual performance of the current controls. It
represents a more stringent limit than the current limit of 0.13 lb/
MMBtu (30-day rolling average). The State assumes the RP limit can be
achieved by the operation of the current LSD. The State determined a
lower SO2 limit was not reasonable as it would not result in
significant visibility improvement (less than 0.02 dv) and would likely
result in frequent non-compliance events.
    We agree with the State's conclusions, and we are proposing to
approve its SO2 RP determination for PRPA Rawhide Unit 101.

NOX RP Determination

    Rawhide Unit 101 is currently controlled with LNB+ close coupled
over fire air + SOFA achieving a 49.6% control. The State determined
that enhanced combustion controls (ECC), SNCR, fuel switching from coal
to natural gas, and SCR were technically feasible NOX
controls for Rawhide Unit 101. The State determined that RRI, ECO, and
coal reburn + SNCR were not technically feasible.
    The State did not identify any energy or non-air quality
environmental

impacts that would preclude the selection of any of the controls
evaluated, nor are there any remaining-useful-life issues for this
source. Baseline NOX emissions are 1,866 tpy based on an
average of 2006-2008 actual emissions. A summary of the State's
NOX BART analysis and the visibility impacts is provided in
Table 32 below. The emission rate for each control option in the table
is reflective of the 30-day rolling average contained in the State's RP
analysis.

                                                  Table 32--Summary of Rawhide Unit 101 NOX RP Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ECC.....................................................              24           0.145             448        $288,450            $644            0.45
SNCR....................................................              27           0.140             504       1,596,000           3,168            0.46
Fuel Switching..........................................              29           0.135             545     237,424,331         435,681            0.47
SCR.....................................................            63.5             .07           1,185      12,103,000          10,214            0.59
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates that the time necessary for compliance after
SIP approval would be approximately 2-3 years for SNCR and 3-4 years
for SCR. ECC could be functional within 6 months of SIP approval.
    The State eliminated switching to natural gas and SCR from
consideration due to the high cost effectiveness values and associated
degree of visibility improvement. The State determined that ECC was
reasonable for RP control. The State made this determination based on
the cost effectiveness and visibility improvement associated with ECC.
SNCR would achieve similar emissions reductions to ECC and would afford
a minimal additional visibility benefit (0.01 delta dv), but it would
do so at a significantly higher dollar-per-ton control cost compared to
the selected ECC. Thus, the State determined that SNCR was not
reasonable. Based upon its consideration of the five factors that it
used for RP, the State determined that the NOX RP emission
limit for Rawhide Unit 101 is 0.145 lb/MMBtu (30-day rolling average).
The State assumes that the RP emission limit can be achieved through
the operation of ECC.
    We agree with the State's conclusions, and we are proposing to
approve its NOX RP determination for PRPA Rawhide Unit 101.

PM RP Determination

    Rawhide Unit 101 is equipped with fabric filter baghouses to
control PM emissions with an emission limit of 0.03 lb/MMBtu. Stack
tests show that the fabric filter baghouses are achieving a 99%
reduction in PM. Fabric filter baghouses are the most stringent control
technology for controlling PM emissions. The State also evaluated what
would constitute the most stringent level of control for PM by looking
at recent BACT determinations. Based on this evaluation, the State
determined that an emission limit of 0.03 lb/MMBtu represents the most
stringent level of control for this type of source. The State did not
provide a full four-factor analysis plus visibility improvement
modeling because the State determined RP to be the most stringent
control technology and limit.
    The State has determined that the PM RP emission limit for Rawhide
Unit 101 is 0.03 lb/MMBtu (30-day rolling average). The State assumes
that the emission limit can be achieved through the operation of the
existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM RP determination for PRPA Rawhide Unit 101.
ii. CENC Boiler 3

Background

    The CENC facility includes five coal-fired boilers (Boilers 1-5)
that supply steam and electrical power to Coors Brewery. Of these five
Boilers, Boilers 4 and 5 are subject to BART and Boiler 3 is subject to
RP. Boiler 3 is a 225 MMBtu/hr boiler. The State did not evaluate
Boiler 1, Boiler 2, or fugitive dust sources at the facility for RP
controls since emissions from these units were below the State's de
minimis levels. The State's RP determination for CENC Boiler 3 can be
found in Chapter <IP_ADDRESS> and Appendix D of the SIP.

SO2 RP Determination

    CENC Boiler 3 is currently uncontrolled for SO2. The
State determined that DSI and fuel switching to natural gas were
technically feasible for reducing SO2 emissions from Boiler
3. The State determined that dry FGD is not technically feasible for
Boiler 3 due to space constraints onsite. Boiler 3's load range varies
from low loads (ready to respond in the event of a malfunction in
Boiler 4 or Boiler 5), medium loads (increased customer steam loads) to
high loads (during Boiler 4 or Boiler 5 overhauls). The load range
varies within the month and has patterns throughout the year. Because
of the varying loads, the State has reasoned that a longer-than-three-
year average of emissions is needed to determine baseline emissions.
The State determined that a baseline average from 2000-2008 represents
a reasonable depiction of actual emissions from this unit.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. The baseline SO2 emissions are 257 tpy. A
summary of the State's SO2 RP analysis is provided in Table
33 below. The emission rate for each control option in the table is
reflective of the 30-day rolling average contained in the State's RP
analysis.

                               Table 33--Summary of CENC Boiler 3 SO2 RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control       (lb/MMBtu)       Emission                          Cost
       Control technology           efficiency        (30-day        reduction      Annualized     effectiveness
                                        (%)           rolling          (tpy)           costs          ($/ton)
                                                     average)
----------------------------------------------------------------------------------------------------------------
DSI.............................              60            0.11             147      $1,340,661          $9,114
Fuel Switching..................             100            0.00             245       1,428,911           5,828
----------------------------------------------------------------------------------------------------------------

    The State determined it would take CENC five years after SIP
approval to install any controls.
    The State used modeling results from CENC Boiler 4 to determine the
projected visibility improvement for Boiler 3 because the units are
similar and located at the same facility. CALPUFF modeling indicates a
0.08 dv improvement for DSI applied to Boiler 4. DSI controls for
Boiler 4 would reduce SO2 emissions by approximately 268
tons per year. DSI controls for Boiler 3 would reduce SO2
emissions by about 147 tons per year. Fuel switching to natural gas
would reduce SO2 emissions by an estimated 245 tons
annually. The State inferred that either control applied to Boiler 3
would yield visibility improvements of less than 0.10 dv.
    The State determined that fuel switching and DSI were not
reasonable to select as RP controls due to the high cost effectiveness
values and low visibility improvement associated with these controls.
Based on a fuel analysis, the State determined that the maximum
SO2 emissions rate from 2000-2010 is 0.99 lb/MMBtu. In
establishing an RP emission limit, the State determined a 20%
contingency factor is warranted for CENC Boiler 3 due to the different
load factors discussed above. Based upon its consideration of the five
factors that it used for RP, the State has determined that the
SO2 RP emission limit for CENC Boiler 3 is 1.2 lbs/MMBtu
(annual average).
    We agree with the State's conclusions, and we are proposing to
approve its SO2 RP determination for CENC Boiler 3.

NOX RP Determination

    The State determined that flue gas recirculation (FGR), SNCR, ROFA,
fuel switching to natural gas, and three options for SCR (regenerative
SCR (RSCR), high temperature SCR (HTSCR), and low temperature SCR
(LTSCR)) were technically feasible for reducing NOX
emissions at CENC Boiler 3. The State determined that LoTOx\TM\, ECO,
RRI, and coal reburn plus SNCR were not technically feasible. The State
determined that because CENC Boiler 3 is a coal stoker boiler, LNBs are
also not technically feasible.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. A summary of the State's NOX RP analysis is
provided in Table 34 below. Baseline NOX emissions are 205
tpy. The emission rate for each control option in the table is
reflective of the 30-day rolling average contained in the State's RP
analysis.

                               Table 34--Summary of CENC Boiler 3 NOX RP Analysis
----------------------------------------------------------------------------------------------------------------
                                                   Emission rate
                                      Control       (lb/MMBtu)       Emission                          Cost
       Control technology           efficiency        (30-day        reduction      Annualized     effectiveness
                                        (%)           rolling          (tpy)           costs          ($/ton)
                                                     average)
----------------------------------------------------------------------------------------------------------------
FGR.............................              20            0.17              34      $1,042,941         $30,292
SNCR............................              30            0.15              51         513,197          10,146
Fuel Switching..................              35            0.14              84       1,428,911          16,950
ROFA w/Rotamix..................              57            0.09              77         978,065           9,496
RSCR............................              75            0.05              96         978,065          10,160
HTSCR...........................              86            0.03             126       1,965,929          15,651
LTSCR...........................              86            0.03             145       2,772,286          19,187
----------------------------------------------------------------------------------------------------------------

    The State estimates that the source would need at least five years
after SIP approval to install the control equipment.
    The State used modeling results from CENC Boiler 4 to determine the
projected visibility improvement for Boiler 3 since the units are
similar and located at the same facility. CALPUFF modeling indicates a
0.12 dv improvement for LNB + SOFA + SNCR applied to Boiler 4. LNB +
SOFA + SNCR controls for Boiler 4 would reduce NOX emissions
by approximately 368 tons per year. The highest performing SCR controls
for Boiler 3 would reduce NOX emissions by about 145 tons
per year. Based on this information, the State has inferred that any
control applied to Boiler 3 would yield visibility improvements of less
than 0.12 dv. The State determined that none of the evaluated controls
were reasonable because of the high cost effectiveness values and low
visibility improvement for each of the controls.
    Based on a review of historical load characteristics of this
boiler, the State determined that RP for Boiler 3 is an annual
NOX limit based on 50% annual capacity utilization using the
maximum capacity year in the last decade. Included in this annual
capacity utilization, there is a 20% contingency factor for reasons
explained above. The State determined that the NOX RP
emission limit for Boiler 3 is 246 tons/year (12-month rolling total).
    We agree with the State's conclusions, and we are proposing to
approve its NOX RP determination for CENC Boiler 3.

PM RP Determination

    CENC Boiler 3 is equipped with a fabric filter baghouse to control
PM emissions with a current emission limit of 0.07 lb/MMBtu. Fabric
filter baghouses are the most stringent control technology for
controlling PM emissions, and stack tests show that the fabric filter
baghouses are achieving a 98% reduction in PM. The State determined
that PM RP for Boiler 3 is an emission limit of 0.07 lb/MMBtu.

The State assumes the RP emission limit can be met with the operation
of the current fabric filter baghouses.
    While we do not agree with all of the State's assumptions and
conclusions in arriving at a PM RP limit of 0.07 lb/MMBtu, we are
proposing to approve the State's PM RP determination for CENC Boiler 3.
Based on our review/analysis, it appears CENC is capable of achieving a
lower emission limit than 0.07 lb/MMBtu with existing equipment.
However, we anticipate that the visibility improvement that would
result from lowering the limit to a value below 0.07 lb/MMBtu would be
insignificant. Under these circumstances, we are proposing to find that
the State's RP determination was reasonable.
    We find that an emission limit of 0.07 lb/MMBtu is reasonable, as a
lower emission limit would not result in significant visibility
improvement. Thus, we are proposing to approve the State's PM RP
determination for CENC Boiler 3.
iii. CSU--Nixon Unit 1

Background

    The Nixon facility is located in Fountain, Colorado. This facility
consists of one coal fired boiler (Unit 1), an auxiliary boiler, the
associated equipment needed for generating electricity, and two
natural-gas-fired simple cycle combustion turbines driving electricity
generators. The facility also includes the various processes necessary
to handle the coal, flyash and bottom ash. The State determined that
Unit 1 and the two combustion turbines were subject to RP. The State
determined the rest of the units at this facility had emissions below
the de minimis thresholds set by the State. The boiler is a 227 MW unit
with a pulverized-coal, dry-bottom, front-fired boiler that fires low
sulfur western coal as the primary fuel. It can currently use No. 2
distillate oil or natural gas for an ignition fuel. The State's RP
determination can be found in Chapter <IP_ADDRESS> and Appendix D of the
SIP. The analysis for the combustion turbines can be found in section
V.D.2.b.x of this notice.

SO2 RP Determination

    Nixon Unit 1 is currently uncontrolled for SO2. The
State determined that DSI and dry FGD were technically feasible for
reducing SO2 emissions from Nixon Unit 1. The State did not
identify any energy or non-air quality environmental impacts that would
preclude the selection of any of the controls evaluated, nor are there
any remaining-useful-life issues for this source. A summary of the
State's SO2 RP analysis is provided in Table 35 below.
Baseline SO2 emissions are 4,121 tpy based on the average of
2006-2008 actual emissions. The emission rate for each control option
in the table is reflective of the 30-day rolling average contained in
the State's RP analysis.

                                                    Table 35--Summary of Nixon Unit 1 SO2 RP Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI--Trona..............................................              60            0.19           2,473      $9,438,692          $1,997            0.44
Dry FGD.................................................              78            0.11           3,215      12,036,604           3,744            0.46
Dry FGD.................................................              85            0.08           3,392      13,399,590           3,950            0.50
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates it would take 3-5 years after SIP approval for
the source to install controls on Nixon Unit 1.
    The State determined that dry FGD was reasonable for RP control for
Nixon Unit 1. Based upon its consideration of the five factors that it
used for RP, the State determined that the SO2 RP emission
limit for CSU Nixon Unit 1 is 0.11 lb/MMBtu (30-day rolling average).
The State assumes that the emission limit can be achieved with dry FGD.
The State determined that a lower emissions limit (85% control
efficiency) for Unit 1 was not reasonable as increased control costs to
achieve such an emissions rate would not provide appreciable
incremental improvements in visibility (0.04 delta dv).
    We agree with the State's conclusions, and we are proposing to
approve its SO2 RP determination for CSU Nixon Unit 1.

NOX RP determination

    Nixon Unit 1 is currently controlled for NOX emissions
with LNBs. The State determined ULNB, OFA, SNCR, SNCR plus ULNB, and
SCR were technically feasible for reducing NOX emissions at
Nixon Unit 1. The State determined ECO, RRI, and coal reburn plus SNCR
were not technically feasible.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. A summary of the State's NOX RP analysis is
provided in Table 36 below. Baseline NOX emissions are 2,356
tpy based on the average of 2006-2008 actual emissions. The emission
rate for each control option in the table is reflective of the 30-day
rolling average contained in the State's RP analysis.

                                                    Table 36--Summary of Nixon Unit 1 NOX RP Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/MMBtu)       Emission                          Cost        (delta dv for
                   Control technology                       efficiency        (30-day        reduction      Annualized     effectiveness    the maximum
                                                                (%)           rolling          (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ULNBs...................................................              20            0.24             471        $567,000          $1,203            0.15
OFA.....................................................              25            0.22             589         403,000             684            0.15
ULNBs + OFA.............................................              30            0.21             707         907,000           1,372            0.16
SNCR....................................................              30            0.21             707       3,266,877           4,564            0.16

ULNBs + SCR.............................................              73            0.08           1,720      11,007,000           6,398            0.24
SCR.....................................................              73            0.08           1,720      11,010,000           6,400            0.24
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The State estimates it would take CSU 2-3 years to install SNCR and
3-4 years to install SCR after SIP approval.
    The State determined NOX RP is ULNBs plus OFA. The State
eliminated SNCR, ULNBs plus SCR, and SCR from consideration due to the
high cost effectiveness values and low visibility improvement for these
controls. Based upon its consideration of the five factors that it used
for RP, the State determined that the NOX RP emission limit
for Nixon Unit 1 is 0.21 lb/MMBtu (30-day rolling average). The State
assumes that the emission limit can be achieved with ultra-low
NOX burners with overfire air control. The State did not
choose SNCR as it would achieve the same emissions reductions at a
greater expense.
    We agree with the State's conclusions, and we are proposing to
approve the State's NOX RP determination for CSU Nixon Unit
1.

PM RP Determination

    Nixon Unit 1 is equipped with fabric filter baghouses to control PM
emissions with an emission limit of 0.03 lb/MMBtu. Stack tests show
that the fabric filter baghouses are achieving greater than a 95%
reduction in PM. The State determined that fabric filter baghouses are
the most stringent control technology for controlling PM emissions. The
State also evaluated what would constitute the most stringent level of
control for PM by looking at recent BACT determinations. Based on this
evaluation, the State determined that an emission limit of 0.03 lb/
MMBtu represents the most stringent level of control for this type of
source. The State did not provide a full four-factor analysis plus
visibility improvement modeling because the State determined RP to be
the most stringent control technology and limit.
    The State has determined that the PM RP emission limit for CSU
Nixon Unit 1 is 0.03 lb/MMBtu (30-day rolling average). The State
assumes that the emission limit can be achieved through the operation
of the existing fabric filter baghouses.
    We agree with the State's conclusions, and we are proposing to
approve its PM RP determination for CSU Nixon Unit 1.
iv. Black Hills Energy Clark Power Plant, Units 1 and 2
    Black Hills/Colorado Electric Utility Company informed the State
that the Clark Units 1 and 2 will be shut down by December 31, 2013.
The shutdown will result in SO2, NOX and PM
reductions of approximately 1,457 tpy, 861 tpy, and 72 tpy,
respectively. The State determined that the shutdown of Clark Power
Plant Units 1 and 2 by December 31, 2013 is RP for this source. The
State did not provide a RP analysis for this facility since the
shutdown of the facility represents the most stringent control. The
State's discussion for the source can be found in Chapter <IP_ADDRESS> of
the SIP. The shutdown of Black Hills Energy Clark Power Plant Unit 1
and Unit 2 is required by the RH SIP (see section 8.5.2 of the SIP and
Regulation No. 3, Part F, Section VI.B).
v. Holcim Florence Cement Plant

Background

    The Holcim Florence Cement Plant is a Portland cement plant located
in Florence, Colorado. In May 2002, a newly constructed cement kiln
commenced operation at the plant. This more energy-efficient 5-stage
preheater/precalciner kiln replaced three older wet process kilns. The
Florence Plant includes a quarry where major raw materials used to
produce Portland cement, such as limestone, translime and sandstone,
are mined, crushed and then conveyed to the plant site. Emissions from
the kiln system, raw mill, coal mill, alkali bypass and clinker cooler
are all routed through a common main stack for discharge to the
atmosphere. The kiln system is rated at 950 MMBtu per hour of fuel
input with a nominal clinker production rate of 5,950 tons per day. It
is permitted to burn the following fuel types: Coal, tire derived fuel,
petroleum coke, natural gas, dried cellulose, and oil, including non-
hazardous used oil. The State determined that the kiln system, quarry,
and finish mill were subject to RP and that all other units at this
facility fall below the State's de minimis threshold. The quarry and
finish mill only have PM emissions. The State RP determination for the
Holcim Florence Cement Plant can be found in Chapter <IP_ADDRESS> and
Appendix D of the SIP.

SO2 RP Determination

    The kiln system is currently controlled with a wet FGD with a
current SO2 permit limit of 1006.5 tpy. The wet FGD, in
conjunction with good combustion practices and the inherent recycling
and scrubbing of acid gases in the manufacturing process, achieves a
98.3% reduction in SO2 emissions as measured by the total
sulfur input into the system versus the amount of sulfur emitted to
atmosphere. The State estimates that the wet FGD itself achieves an
overall SO2 removal efficiency of greater than 90%.
    On August 9, 2010, EPA finalized changes to the NSPS for Portland
Cement Plants. The NSPS requires new, modified, or reconstructed cement
kilns to meet an emission standard of 0.4 pound of SO2 per
ton of clinker on a 30-day rolling average or a 90% reduction as
measured at the inlet and outlet of the control device. While the new
NSPS does not apply to the Holcim Portland Plant because it is an
existing facility, the State determined that 90 percent control
represents the most stringent level of control and wet FGD the most
stringent control technology for Portland cement plants. Therefore, the
State did not complete a full RP analysis.
    The State did evaluate emissions limit tightening based on current
operations. As a part of its submittals to the State, Holcim analyzed
continuous hourly emission data for SO2. The State used the
hourly emission data from 2004 to 2008 to calculate the daily emission
rates. The State calculated a 30-day rolling average emission rate by
dividing the total emissions from the previous 30 operating days by the
total clinker production from the previous 30 operating days. The State
established two RP limits for the Holcim Florence Cement Plant. The
State used the 99th percentile of the 30-day rolling average data to
establish a short-term SO2 RP emission limit of 1.30 pounds
per ton of clinker (30-day rolling average). The State calculated the
long-term annual

limit by multiplying the long-term baseline SO2 value of
0.77 lb/ton clinker (the mean of 0.51 pound per ton plus one standard
deviation of 0.26 pound per ton) by the annual clinker limit of
1,873,898 tpy, and then dividing by 2,000 pounds per ton. The State
determined that the SO2 RP long-term limit is 721.4 tpy (12-
month rolling total). The State assumes that the emission limits can be
achieved through the operation of the existing wet FGD.
    We agree with the State's conclusions, and we are proposing to
approve its SO2 RP determination for the Holcim Florence
Cement Kiln.

NOX RP Determination

    NOX emissions from the kiln are currently controlled by
a number of technologies, including LNBs. The State determined water
injection (the injection of water into the main flame of the kiln to
act as a heat sink and reduce the flame temperature) and SNCR were
technically feasible. The State determined that SCR is not commercially
available for Portland cement kilns.
    Although we disagree with the State's conclusion on the commercial
availability of SCR for cement kilns, we accept the State's decision,
for purposes of RH, not to analyze this control technology further. We
note that EPA has acknowledged, in the context of establishing NSPS for
Portland Cement Plants, substantial uncertainty regarding the cost
effectiveness associated with the use of SCR at such plants. See 75 FR
54995. We expect the State to reevaluate this technology in subsequent
RP planning periods.
    The State did not identify any energy or non-air quality
environmental impacts that would preclude the selection of any of the
controls evaluated, nor are there any remaining-useful-life issues for
this source. A summary of the State's NOX RP analysis is
provided in Table 37 below. Baseline NOX emissions are 1,931
tpy based on the average of 2007-2009 actual emissions. The emission
rate in the table is reflective of the 30-day rolling average contained
in the State's RP analysis. The State estimates that water injection
would result in a 7 percent or less emission reduction and SCNR could
achieve about 45 percent control.\22\ Since the State's initial
analysis indicated that SNCR would be reasonable for RP control, the
State did not analyze water injection further.
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    \22\ An SNCR control efficiency of 50% is feasible for the
Portland Plant kiln. However, to achieve the necessary system
configuration and temperature profile, SNCR will be applied at the
top of the preheater tower and thus the alkali bypass exhaust stream
cannot be treated. To achieve the proper cement product
specifications, the Portland Plant alkali bypass varies from 0-30%
of main kiln gas flow. Adjusting by 10%, for the alkali bypass to
account for the exhaust gas that is not treated (i.e., bypassed) by
the SNCR system, the State determined the overall SNCR control
efficiency for the main stack will be 45%.

                                            Table 37--Summary of Holcim Florence Cement Kiln NOX RP Analysis
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                                                                                Visibility
                                                                           Emission rate                                                    improvement
                                                              Control       (lb/ton of       Emission                          Cost        (delta dv for
                   Control technology                       efficiency     clinker) (30-     reduction      Annualized     effectiveness    the maximum
                                                                (%)         day rolling        (tpy)           costs          ($/ton)          98th
                                                                             average)                                                       percentile
                                                                                impact)
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SNCR....................................................              45            2.73          1098.9      $2,520,000          $2,293            0.29