DryFining\TM\, and that larger registers are tentatively anticipated to
be installed at CCS 1 in 2014.
    Response: We evaluate potential control options based on baseline
conditions, not on ongoing revisions to a facility after the baseline
period. It is not reasonable to consider controls installed after the
baseline period in determining BART. Such an approach would tend to
lead to higher cost effectiveness values for more effective controls
and encourage sources to voluntarily install lesser controls to avoid
installing more effective BART controls later.
    Comment: Commenter stated that URS reviewed and updated both
capital and operating costs for SNCR, based on their expertise and site
specific investigation. These values were relatively consistent with
values presented to EPA in June and July 2011, but are somewhat higher
than the screening values presented in the original BART analysis.
    Response: The higher cost-effectiveness ($/ton) of SNCR in GRE's
November 2011 submittal can be primarily attributed to the lower
control efficiency value assigned to the technology. The July 2011
study estimates a control efficiency of 50% for SNCR, which yields a
cost effectiveness value of $3,198/ton for both Units 1 and Units 2
(one estimate). The November 2011 study estimates an SNCR control
efficiency of 25% for Unit 1 and 20% for Unit 2, which yields a cost
effectiveness value of $7,629/ton and $10,506/ton for Units 1 and 2
respectively.
    It should be noted that the November study actually estimates lower
capital and annual costs of control, each of which would independently
lower the cost effectiveness value. The total capital investment for
SNCR estimated in the July study was $12.72 million, compared to $12.18
million and $11.80 million for Units 1 and 2, respectively, in the
November study. The annualized capital plus operating costs in the July
study were estimated at $8.91million, compared to $8.79 million and
$8.12 million for Units 1 and 2 in the November study. One of the main
reasons that costs are higher in the July study is maintenance costs;
the annual maintenance costs in the July study are $1,907,375 compared
to approximately $180,000 for each Unit in the November study.
    The baseline emission rate is another factor which would result in
higher cost effectiveness values in the November study. The baseline
emission rate in the July study was estimated at 0.22 lb/MMBtu,
compared to 0.20 lb/MMBtu and 0.153 lb/MMBtu for Units 1 and 2 in the
November study. A lower emission rate would result in less emissions
controlled and a higher cost effectiveness value.
    The lower SNCR control efficiency in the November study results in
less NOX controlled (i.e., 1,152 tons per year (tpy) for
Unit 1 and 772 tpy for Unit 2 in the November study versus 2,786 tpy
NOX controlled in the July study), and a higher overall cost
effectiveness value. The reduced SNCR control efficiency outweighs the
changes to the cost of control, which would otherwise result in lower
cost effectiveness values.\55\
---------------------------------------------------------------------------

    \55\ Our analysis differs in that we considered SNCR combined
with combustion controls.

  Table 1--Comparison Between Cost Effectiveness Factors in GRE's July and November 2011 Cost Estimates for CCS
----------------------------------------------------------------------------------------------------------------
                                   Baseline                                                           Pollution
                                   emission      Control      Emission      Installed    Annual O&M    control
       Study description           rate (lb/    efficiency    reduction   capital cost   cost (MM$/    cost ($/
                                    MMBtu)                    (ton/yr)      (MM$/yr)        yr)          ton)
----------------------------------------------------------------------------------------------------------------
SNCR, July Study, Both Units...         0.22            50       2,786           12.72         8.91        3,198
SNCR, November Study, Unit 1...         0.2             25       1,152.8         12.18         8.79        7,629
SNCR, November Study, Unit 2...         0.153           20         772.5         11.8          8.12       10,506
----------------------------------------------------------------------------------------------------------------

    We do not agree with the capital and operating costs estimated by
GRE. First, URS has inappropriately applied a retrofit factor when
calculating capital costs for the SNCR system. The Control Cost Manual
states:

    The costing algorithms in this report are based on retrofit
applications of SNCR to existing coal-fired, dry bottom, wall-fired
and tangential, balanced draft boilers. There is little difference
between the cost of SNCR retrofit of an existing boiler and SNCR
installation on a new boiler.\56\ Therefore, the cost estimating
procedure is suitable for retrofit or new boiler applications of
SNCR on all types of coal-fired electric utilities and large
industrial boilers.\57\
---------------------------------------------------------------------------

    \56\ Rini, M.J., J.A. Nicholson, and M.B. Cohen. Evaluating the
SNCR Process for Tangentially-Fired Boilers. Presented at the 1993
Joint Symposium on Stationary Combustion NOX Control, Bal
Harbor, Florida. May 24-27, 1993.
    \57\ Control Cost Manual, Section 4.2, p. 1-4.

    Therefore, retrofit costs are inherent in the costs provided by the
Control Cost Manual method and there is no need to introduce a retrofit
factor. In using a retrofit factor of 1.6, URS overestimated capital
costs by 60%.\58\
---------------------------------------------------------------------------

    \58\ It appears that URS overestimated capital costs in other
ways as well. Consistent with the BART Guidelines, and as outlined
in our proposal and in this action, we have applied the factors
permitted by EPA's Control Cost Manual to GRE's estimate of direct
capital equipment costs for SNCR to arrive at a reasonable estimate
of the total capital investment. We do not agree with URS's estimate
of total capital investment because it relies on factors that are
inconsistent with the Control Cost Manual.
---------------------------------------------------------------------------

    Another concern we have is that URS's estimate of reagent usage is
high. The following is an examination of the 0.20 lb/MMBtu inlet level
with 25% reduction case in URS's Table 4.\59\ Using a boiler rating of
5900 MMBtu/hr,\60\ an initial NOX level of 0.20 lb/MMBtu,
and a normal stoichiometric ratio (NSR) of 1.0 (30 lb urea/46 lb
NO2),\61\ the hourly usage of reagent is: 5900 MMBtu/hr *
0.20 lbNO2/MMBtu * (30 lb urea/46 lb NO2) = 770
lb/hr.
---------------------------------------------------------------------------

    \59\ URS did not analyze a case with the parameters we have
determined are most reasonable; we are providing the reagent cost
review of one of URS's cases to highlight our concerns with the
methodology. Considering an inlet emission rate of 0.15 lb/MMBtu and
a 25% reduction, the parameters we find are reasonable, the reagent
cost would be $1,304/ton using a similar analysis.
    \60\ EPA and the North Dakota SIP assume 6,112 MMBtu/hr, but URS
assumes 5,900 MMBtu/hr. The difference will not affect the
conclusion that URS's reagent costs are high.
---------------------------------------------------------------------------

    This is roughly half of what URS calculated as the urea usage. In
all of the cases URS estimated, the result is high. Since URS appears
to have overestimated the reagent cost, it is likely that URS
overestimated the water cost as well.
    In this case, with urea at $500/ton delivered, the reagent portion
of cost would be:

$500/ton * (1 ton/2000 lb)* 770lb/hr = $192/hr.

    The tons removed per hour would equal:

(5900 MMBtu/hr)*(0.20 lb NO2/MMBtu)*(0.25 reduction)*(1 ton/
2000 lb) = 0.148 ton/hr.

    The reagent portion of cost is 192/0.148 = $1,300/ton of
NOX removed.
    This $/ton for reagent would be the same assuming the same cost per
ton of urea and the same chemical utilization (25%, or 25% reduction at
an NSR = 1.0).
    The errors in the URS estimate are carried through to GRE's
estimates.
    Comment: Commenter stated that with the installation of LNC3,
LNC3+, and DryFiningTM;, CCS's NOX emissions are
greatly reduced with respect to ``baseline'' values previously
provided; and it is necessary to update the baseline emissions for
Units 1 and 2 for this technology evaluation in order to reflect
current conditions and unit performance. Commenter stated that the
revised baseline emissions for Units 1 and 2 should be adjusted to
0.201 lb/MMBtu and 0.153 lb/MMBtu, respectively. The commenter stated
that the use of DryFiningTM technology has already been
implemented for use at both units at a cost of $270 million, and GRE
has made a significant investment to achieve multi-pollutant emission
reductions and visibility improvements in the region.
    Response: As stated in our previous comments, we reject GRE's
revised baseline. We evaluate potential control options based on
baseline conditions, not on ongoing voluntary revisions to a facility
after the baseline period. It is not reasonable to consider voluntary
controls installed after the baseline period in determining BART. Such
an approach would tend to lead to higher cost effectiveness values for
more effective controls and encourage sources to voluntarily install
lesser controls to avoid more effective BART controls later.
    Comment: The refined economic impacts analysis provided by GRE
confirms GRE's original conclusion that SNCR is not a cost effective
NOX control option.
    Response: We disagree with the cost effectiveness analysis provided
by GRE in the refined analysis. We disagree with the control efficiency
used for SNCR in combination with SOFA plus LNB used in the refined
analysis, the assumed baseline and controlled emission rates, and the
assumed reduction in ash sales. These issues are further discussed in
the comment responses specific to each issue.
h. CCS General Comments
    Comment: The commenter stated that at the time of this submittal,
GRE has already installed LNC3 combustion controls at Unit 2. In 2011
dollars, this was at a cost of over $6 million and has already resulted
in NOX reductions. The same system is tentatively scheduled
to be installed on Unit 1 during the 2014 outage.
    Response: As stated in our previous comments, we reject GRE's use
of a revised baseline.
3. Stanton Station Unit 1
    Comment: Commenter states that the BART limits for the Stanton
Station are contrary to BART requirements. Commenter states that both
SO2 and NOX emission rates would decrease if only
Powder River Basin (PRB) coal were allowed to be burned, because the
burning of North Dakota lignite coal creates higher emissions of both
pollutants. Commenter also states that EPA's cited 7th Circuit Court of
Appeal decision (76 FR 58589) would not apply to such a requirement
because that decision only applies to the redesign of a source.
    Response: We do not interpret the CAA or the regional haze
regulations as

requiring states to consider limiting the type of coal burned as a BART
control technology. We note that we did not cite the referenced 7th
Circuit decision in support of our proposal to approve the BART limits
for Stanton Station.
    Comment: One commenter states that EPA is proposing to approve SNCR
+ OFA + LNB as NOX controls for Stanton Station Unit 1.
While the commenter supports the use of further NOX controls
at this facility, the commenter asks EPA to further evaluate the cost
estimates for SCR at this facility. According to the commenter, the
cost estimates for SCR that EPA relied on in its proposal appear to
include, at a minimum, costs associated with allowance for funds used
during construction (AFUDC), which is not appropriate under the BART
Guidelines and Control Cost Manual. Further, the underlying
calculations in Stanton Station's BART submission to North Dakota do
not clearly support the resulting cost.
    Response: We relied on cost estimates submitted by North Dakota in
our evaluation of the cost effectiveness of NOX control
options for Stanton Station Unit 1. In turn, North Dakota relied on
costs taken from GRE's BART analysis as found in Appendix C.2 to the
SIP. GRE asserts that these costs were derived ``using the procedures
found in the EPA Air Pollution Control Cost Manual.'' \62\ However, as
suggested by the commenter, there are irregularities in how GRE applied
the SCR cost methods in the Control Cost Manual. In particular, GRE
included a line item for AFUDC in the amount of $8,232,000. However,
closer examination reveals that this line item represents the cost of
replacement power associated with a purported 10 week outage for
installation of the SCR, and does not represent allowance for funds
used during construction. Regardless, elimination of this line item
would only lower the cost effectiveness values for SCR when burning
lignite and PRB coal from $6,475/ton to $6,118/ton and $8,163/ton to
$7,713/ton, respectively. In addition, the total capital investment
stated by GRE for SCR of $55,279,000 equates to $294/kilowatt (kW). We
find this cost consistent with the installed SCR retrofit costs,
ranging from $79/kW to $316/kW (2010 dollars), cited in recent industry
studies.\63\ We expect that the cost at Stanton Station Unit 1 would be
at the higher end of this range given its relatively low generation
capacity of 188 MW. Accordingly, while we agree that there are
questions regarding the underlying calculations, it is our opinion that
further evaluating costs would not change the outcome of the BART
determination.
---------------------------------------------------------------------------

    \62\ Coal Creek Station Units 1 and 2 Best Available Retrofit
Technology Analysis, Revised December 12, 2007, p. 8.
    \63\ Revised BART Cost Effectiveness Analysis for Tail-End
Selective Catalytic Reduction at the Basin Electric Power
Cooperative, Leland Olds Station Unit 2, Final Report, March 2011,
docket EPA-R08-OAR-2010-0406-0076, p. 8.
---------------------------------------------------------------------------

4. Leland Olds Station Unit 1
    Comment: Commenter stated that SCR, not SNCR, is BART at LOS 1.
Commenter further stated that EPA assumed that Basin Electric
overestimated the costs for SCR at this unit, but did not re-estimate
the costs. Commenter analyzed the costs based on the revised cost for
SCR at Unit 2, and considers its lower cost estimate ``well within the
range of values determined to be cost effective in similar regulatory
proceedings.''
    Response: We have included in the docket for our final action an
SCR cost estimate for LOS 1 that was based on methods similar to those
we used for our SNCR cost analyses for MRYS 1 and 2 and LOS 2. The
analysis was not an exhaustive effort but was used as a check of the
analysis provided by North Dakota. Our analysis found the cost of SCR +
SOFA would be approximately $5,132/ton of NOX emissions
removed with an incremental cost effectiveness between the SCR and SNCR
control options of $8,845/ton of NOX emissions removed. The
cost estimates for SCR at LOS 1 that National Parks Conservation
Association (NPCA) and the NPS provided in their comments reflect cost
effectiveness values greater than $4,000/ton of NOX
emissions removed. While these various estimates are lower than those
the State relied on, they are still high enough that we are not
prepared to change our conclusion that the State's BART determination
of SNCR + Basic SOFA for LOS 1 was reasonable.
    Comment: Commenter stated that there is no discussion why SNCR +
Boosted SOFA was rejected as BART.
    Response: In response to this comment, we reviewed the benefits of
SNCR + Boosted SOFA over SNCR + Basic SOFA. We determined that the two
combustion control options achieve very similar results and that the
incremental cost of the Boosted SOFA option at $7,826/ton is excessive
compared to the 92 tons of additional NOX reductions, which
we anticipate would provide a low visibility benefit.

F. General Comments on SO2 and PM Pollution Controls

    Comment: One commenter stated that North Dakota's BART analyses
that EPA proposes to approve fail to include the most stringent level
of control that is achievable using scrubber technology since scrubbers
can achieve 99% control efficiency. Commenters also stated that, with
regard to SO2, EPA should require both the lb/MMBtu limit
and the percent control efficiency limit to be met in order to meet
BART, rather than require that either limit be met as EPA proposed. One
commenter stated that if only the percent reduction limit is set,
emissions will increase with the sulfur content of the fuel unless
sulfur content is also limited. One commenter requested EPA set a
numeric limit rather than percent reductions.
    Response: We agree that the RHR requires states to consider the
most stringent level of control. We also agree that, in most
applications, wet or dry scrubbers can achieve greater emission
reductions than those required by North Dakota. However, there is very
limited data on the performance of wet or dry scrubbers at units firing
lignite, such as those in North Dakota. In a 2007 BACT determination
for two new lignite-fired boilers at Oak Grove Station in Texas, the
Texas Commission on Environmental Quality established an SO2
emission limit of 0.192 lb/MMBtu on a 30-day rolling average. Based on
this, we find that the emission limits established by North Dakota are
not unreasonable. Also, we would like to emphasize that three of the
North Dakota units have existing controls for SO2 and that
the emission reductions that can be achieved with upgrades to these
existing controls may not be as great as those that can be achieved by
a new scrubber installation. Finally, on the point of allowing either a
lb/MMBtu or a percent control efficiency limit, we typically prefer a
single limit. However, the BART guidelines list the presumptive levels
in units of lb/MMBtu or a percent reduction, and we cannot say that the
State's approach is inconsistent with the guidelines. The State chose
to take advantage of this point and specifically found that it was not
appropriate to establish limits on a lb/MMBtu and percent reduction
basis. This was in part to allow for the potential that higher sulfur
coals might be burned in the future, in which case the State believed
that the percent reduction basis would extend greater flexibility.
Based on these factors and our consideration of all the circumstances
involved, we find that the SO2 emission limits established
by North Dakota are not unreasonable and we are approving them.
    Comment: Commenters stated that North Dakota did not consider
upgrading ESPs to decrease PM emissions, as is required by the BART
Guidelines.

    Response: As noted in our proposal, the ESPs already reduce
emissions by 99% or greater. Where new wet or dry scrubbers or
modifications to existing scrubbers will be installed, additional PM
emission reductions, particularly of sulfuric acid mist, will be
achieved. Moreover, as noted in North Dakota's SIP, the visibility
improvement that can be achieved by further reducing PM is minor. For
example, North Dakota's BART determination for M.R. Young Unit 2 shows
that the highest visibility impact from PM in the baseline was 0.0165
deciviews (LWA, 2001). SIP, Appendix B.4, p. 26. Similarly, North
Dakota's BART determination for Stanton Station Unit 1 shows that
reducing PM from 0.1 lb/MMBtu to 0.015 lb/MMBtu would only improve
visibility by 0.021deciviews (TRNP-SU, 2002). SIP, Appendix B.3, p. 9.
Accordingly, we find that North Dakota reasonably eliminated ESP
upgrades from consideration.
    Comment: One commenter stated that the control efficiency for
baghouses was underestimated.
    Response: We agree that the control efficiency for baghouses was
underestimated. However, this has no practical bearing on our
evaluation of North Dakota's BART control determinations for PM as,
consistent with the BART Guidelines, North Dakota was not required to
consider the replacement of existing PM control devices. Stanton
Station is the only facility where North Dakota is requiring new PM
controls, but this is only in association with the spray dryer absorber
needed to control SO2.
    Comment: Commenters stated that a PM continuous emission monitoring
system (CEMS) must be installed, operated and used to demonstrate
continuous compliance with the PM emission limits on units that are
subject to BART.
    Response: PM CEMS would provide the most robust means of
demonstrating continuous compliance with the PM emission limits.
However, we disagree that their use is required. We find that the
monitoring requirements in the RH SIP are adequate to demonstrate
continuous compliance with the PM emission limits.
    Comment: BART should be evaluated for both course particulate
matter (PM10) and PM 2.5, but was only evaluated
for PM10. EPA should therefore impose a BART limit on total
PM2.5.
    Response: In our BART Guidelines, for the purposes of identifying
visibility impairing pollutants, we allowed states to use emissions of
PM10 as an indicator for PM2.5, as the components
of PM2.5 are a subset of PM10. 70 FR 39160. For
the same reasons, we find that it is reasonable for North Dakota to
have explicitly evaluated BART only for PM10. We also note
that North Dakota did evaluate BART for condensable PM which comprises
a large portion of the PM2.5.
    Comment: Commenter stated that North Dakota incorrectly set a limit
for PM at .07 lbs/MMBtu. Commenter stated that the actual emissions
from most units averaged .03 lbs/MMBtu to .05 lbs/MMBtu, and there is
therefore no support for limits higher than .03 lbs/MMBtu.
Additionally, the commenter asserted that these limits should be set on
a unit-by-unit basis.
    Response: As noted in prior responses to comments, the visibility
improvement that could be achieved with new or upgraded PM controls is
negligible. That response also holds true within the context of setting
tighter emission limits. Therefore, we find that PM emission limits set
by North Dakota are not unreasonable.
    Comment: Commenter stated that EPA deviates from the BART
guidelines in failing to establish a clear time period (hourly, 24-
hour, 30-day or annual) over which the proposed PM limits would apply.
Commenter further stated that North Dakota's BART determinations are
unenforceable because there are no proposed monitoring, recordkeeping
and reporting requirements that would ensure compliance with the
filterable PM limits. Commenter stated that this was contrary to the
CAA, because BART is defined as based on continuous emission
reductions, which cannot be ensured.
    Response: We disagree with the commenter. First, we seek to clarify
that while emission limits must be enforceable as a practical matter,
the BART Guidelines clearly state that CEMs are not required in every
instance. 70 FR 39172. Moreover, the BART Guidelines recognize that
monitoring requirements are in many instances governed by other
regulations, such as compliance assurance monitoring. North Dakota
established monitoring, recordkeeping and reporting requirements for PM
emission limits in permits to construct which are included in Appendix
D of the SIP. The monitoring requirements for PM include emission
testing using EPA-approved test methods, such as Method 5B and Method
17. As specified in each permit to construct, these tests must consist
of three test runs, with each test run at least 120 minutes in
duration. The monitoring requirements also require the use of a
Continuous Assurance Monitoring (CAM) Plan developed in accordance with
NDAC 33-15-14-06.10. The CAM Plan will include other provisions
necessary to show compliance. We find that these monitoring provisions
are adequate to ensure continuous emission reductions as required under
BART.

G. Comments on Reasonable Progress and North Dakota's Long-Term
Strategy

    Comment: Minnkota states that EPA's proposed FIP does not follow
EPA guidelines for RP determinations. The commenter cites, without a
page number, the Burns & McDonnell report attached to the comments.
    Response: EPA is unable to identify any support in the Burns &
McDonnell report for the statement. Standing alone, the comment is
insufficiently specific to warrant a response. Below, EPA responds to
comments that EPA's disapproval of the State's RP determination for AVS
is inconsistent with EPA guidelines.
    Comment: Minnkota states that EPA's actions disapproving the
State's RPGs and imposing RP controls on MRYS lack a basis.
    Response: EPA disagrees with this comment. First, as stated in the
proposal, the disapproval of the State's RPGs is based on the State's
failure to demonstrate that the RPGs the State selected are reasonable,
based on the four statutory factors. In particular, the State's use of
a degraded background in modeling for visibility benefits was
unreasonable, as was the State's failure to select RP controls for AVS.
Second, the commenter appears to misinterpret the statements made
regarding MRYS Units 1 and 2 as proposing to impose RP controls on
those units. In any case, the reference to controls on MRYS Units 1 and
2 is no longer relevant, because we have decided to approve North
Dakota's NOX BART determination for MRYS Units 1 and 2.
    Comment: Minnkota states that EPA's action in disapproving the
State's LTS is unreasonable and simplistic.
    Response: EPA disagrees with this comment. The LTS is a compilation
of the State-specific controls relied upon by the State for achieving
its RPGs. We are disapproving the State's RPGs along with certain
NOX BART and RP determinations and promulgating a FIP to
impose RPGs that are consistent with our FIP NOX BART and RP
determinations. To the extent that the State's LTS relies on these
NOX BART and RP determinations, we must also disapprove
those portions of the LTS. Specifically, our partial disapproval of the
State's LTS consists of two parts: (1) Disapproval of the LTS with
regard to permit limits and monitoring, recordkeeping, and reporting

requirements in the State's submittal that correspond to the
NOX BART determinations we are disapproving; and (2)
disapproval of the LTS with regard to the NOX reasonable
progress determination for AVS Units 1 and 2, and with regard to the
corresponding monitoring, recordkeeping, and reporting requirements.
The monitoring, recordkeeping, and reporting requirements for Antelope
Valley are necessary to ensure that the emissions limitations and
control measures to meet RPGs are enforceable. See 40 CFR
51.308(d)(3)(v)(F). In addition, these requirements are generally
necessary to ensure the BART limits are enforceable. See CAA 110(a)(2).
As these requirements are necessary adjuncts to the BART and RP limits,
our disapproval of the State's requirements necessarily flows from our
disapproval of the NOX BART determinations for CCS Units 1
and 2 and the disapproval of the State's NOX RP
determination for AVS Units 1 and 2.
    Comment: NDDH states that EPA incorrectly rejected NDDH's RP
modeling methodology. NDDH believes that the methodology properly took
into account effects of international sources, as provided for in the
RHR. Furthermore, the hybrid methodology was, in NDDH's view, necessary
to accurately simulate transport from large point sources.
    Response: Our response to this comment is provided with our
responses to modeling comments in section V.C.
    Comment: NDDH states that its cumulative modeling methodology more
accurately reflects the visibility improvements from controls at point
sources.
    Response: Our response to this comment is provided with our
responses to modeling comments in section V.C.
    Comment: NDDH notes that EPA supported the development of the WRAP
cumulative modeling, which NDDH states involved considerable time and
resources. NDDH argues that it is inappropriate to diminish this
extensive effort by using what NDDH views as a less sophisticated and
inconsistent single-source approach.
    Response: EPA disagrees with this comment. As discussed elsewhere,
single-source modeling is not ``less sophisticated'' or
``inconsistent.'' EPA supported development of WRAP CMAQ modeling in
order to assist states in developing their RPGs. This support does not
endorse the use of cumulative modeling to determine single-source
impacts, a faulty approach for the reasons discussed above. As
discussed below in responses to comments later in this section, NDDH's
comment conflates the requirements for RPGs with the requirements for
evaluating RP controls for single sources.
    Comment: NDDH states that, on a dollar-per-ton-removed basis, LNB +
SNCR appears to be reasonable for AVS. However, NDDH argues that its
dollar-per-deciview evaluation of visibility benefits from installing
LNB + SNCR at AVS shows that the cost is excessive.
    Response: EPA disagrees with this comment, to the extent that it
can be understood to argue against EPA's determination to impose LNB at
AVS to meet reasonable progress requirements. The dollar-per-deciview
cost that NDDH relies upon is faulty because, as discussed elsewhere,
it relies on modeling using current degraded background that greatly
underestimates the visibility improvement of single-source controls
when compared to accepted methodology. It therefore provides no basis
for determining that the cost of LNB + SNCR is excessive, or that the
cost of LNB alone is excessive. Elsewhere, we have also discussed some
of the difficulties with using dollar-per-deciview cost effectiveness
values, and how care must be taken not to misinterpret such values. EPA
does note that NDDH describes the dollar-per-ton cost of LNB + SNCR as
reasonable. Using North Dakota's costs, LNB + SNCR has a cost-
effectiveness value of $2,268 per ton removed at Unit 1 and $2,556 per
ton removed at Unit 2. By comparison, LNB alone, using North Dakota's
costs, has a cost-effectiveness value of $586 per ton removed at Unit 1
and $661 per ton removed at Unit 2. This indicates that LNB has a very
reasonable cost effectiveness value on a dollar-per-ton-removed basis,
the metric that is most widely used and understood in making control
technology determinations.
    Comment: NDDH references its CALPUFF modeling of visibility
improvement at AVS from installation of LNB. NDDH states that this
modeling was intended to show greater visibility improvement from
installation of LNB on the two units at Antelope Valley as compared to
installation of SCR at Leland Olds Station. NDDH argues that CALPUFF
overpredicts visibility improvements and does not comply with
51.308(d)(1) and EPA's guidance.
    Response: For reasons expressed elsewhere in this action, we
disagree with North Dakota's argument that CALPUFF overpredicts
visibility improvements. Our response to the argument that use of
CALPUFF does not comply with 51.308(d)(1) and EPA guidance is provided
with other responses in this section. While NDDH may have provided the
CALPUFF modeling for another purpose, we find it informative. The CAA
does not limit EPA in its action on a SIP submittal to considering
materials only for the purpose for which the materials were originally
intended. Instead, EPA may consider all relevant materials, including
the CALPUFF modeling of visibility improvement from installation of LNB
at AVS.
    Comment: NDDH notes that even if all sources of SO2 and
NOX in North Dakota were eliminated, North Dakota could not
achieve the URP. North Dakota states that additional controls for AVS
make almost no difference, and that additional controls on sources
outside of North Dakota are necessary to achieve the URP.
    Response: As we stated in our proposal, we agree that North Dakota
could not achieve the URP in the first planning period even if all
North Dakota sources were eliminated. We do not agree that this means
that North Dakota can accordingly do nothing in the first planning
period to address reasonable progress beyond addressing the BART
requirements or that the State can reject otherwise reasonable control
measures. EPA assumes that NDDH bases its statement regarding ``almost
no difference'' on the modeling using current degraded background
conditions. The CALPUFF modeling for AVS (separately provided by NDDH)
predicts a visibility benefit at TRNP of 0.754 deciviews from
installation of LNB, which EPA does not regard as ``almost no
difference.'' Regardless of whether controls on sources outside of
North Dakota are necessary in order to achieve natural visibility
conditions by 2064, North Dakota is required to provide a reasoned
analysis of RP controls on sources within the State. With respect to
AVS, the State did not do so.
    Comment: North Dakota states that, based on the definition of
``most impaired days'' and ``least impaired days'' in 51.301, and the
requirement in 51.308(d)(1) that the RPGs provide for improvement in
visibility for the most impaired days over the planning period and
ensure no degradation in visibility for the least impaired days over
the planning period, any RP visibility analysis must be a cumulative
analysis and must address the most impaired days. NDDH states that it
consistently modeled BART and RP sources. NDDH argues that, under the
RHR and EPA guidance, progress with respect to the URP must be assessed
using cumulative modeling based on the controls imposed on multiple
sources. It would be

inconsistent with this approach, NDDH asserts, to use single-source
modeling to determine improvements for the controls on an individual
source.
    Response: NDDH conflates (as it does in the next comment and
elsewhere, and as do other commenters) the reasonable progress
requirements for RPGs and for determination of controls for a single
source. The RPGs must provide for improvement in visibility for the
most impaired days over the planning period and ensure no degradation
in visibility for the least impaired days over the planning period. In
evaluating whether the overall RPGs provide for improvement in
visibility for the most impaired days, it is not only appropriate, but
necessary, to employ current degraded background in cumulative
visibility modeling. This allows a comparison of the impact of the
State's proposed overall set of regional haze controls against the
baseline ``most impaired days.''
    We disagree, however, that it is appropriate to analyze and reject
potential control measures at specific sources based on modeling using
current degraded background conditions. Distinct from the requirement
to show that the overall RPGs provide for improvement on the most
impaired days, it was incumbent on North Dakota to show that the URP is
not a reasonable goal for this planning period and that its RPGs and
rejection of reasonable progress controls was reasonable. Just because
a state has met the requirement to show improvement on the most
impaired days does not mean it has met this separate requirement. Our
regulations require that this showing be based on the four statutory
reasonable progress factors: The costs of compliance, the time
necessary for compliance, the energy and non-air quality environmental
impacts of compliance, and the remaining useful life of any potentially
affected sources. 40 CFR 51.308(d)(1)(ii). We must determine whether
the State's showing based on the four factors is reasonable. 40 CFR
51.308(d)(1)(iii).
    Here, it is worth noting the process North Dakota used to evaluate
potential reasonable progress controls. North Dakota employed certain
screening tools to identify sources in North Dakota that potentially
affect visibility in Class I areas. It focused mainly on point sources,
starting with the list of sources subject to Title V permitting
requirements. It further pared this list by focusing on the ratio of
emissions to distance to the nearest Class I area, known as Q/D. A Q/D
value of 10 was chosen as a threshold. North Dakota chose this value
based on FLM guidance and the State's interpretation of statements in
EPA's BART guidelines as to sources that could reasonably be exempted
from the BART review process; i.e., for a state with a BART
contribution threshold of 0.5 deciviews, sources emitting less than 500
tons per year located more than 50 kilometers from a Class I area or
emitting less than 1000 tons per year located more than 100 kilometers
from a Class I area.\64\ We note that North Dakota selected 0.5
deciviews as its contribution threshold for determining which sources
are subject to BART.
---------------------------------------------------------------------------

    \64\ The ratios of these values equal a Q/D of 10.
---------------------------------------------------------------------------

    North Dakota eliminated any source with a Q/D less than 10 from
further consideration for reasonable progress controls. Then, North
Dakota eliminated several sources with a Q/D over 10 that, as a result
of events after the 2000 to 2004 baseline period, had reduced emissions
sufficiently so that the sources' Q/D became less than 10. After this
paring, seven units remained. We note that four of the remaining seven
units are EGUs, and three of them are comparable in size and emissions
to some of the largest BART sources in North Dakota.
    For these seven remaining units only, North Dakota considered the
four statutory reasonable progress factors in evaluating potential
control technologies for reducing SO2 and NOX
emissions. However, when it eliminated all reasonable progress controls
for these pollutants for these units, North Dakota relied almost
exclusively on its cumulative modeling, using current degraded
background to conclude that the cost on a dollar per deciview basis was
excessive.\65\
---------------------------------------------------------------------------

    \65\ Further detail regarding North Dakota's analysis can be
found in our proposal. 76 FR 58624-58628.
---------------------------------------------------------------------------

    As noted in a prior response, we conclude that it was not
reasonable for North Dakota to model visibility improvement for
potential individual source reasonable progress controls using current
degraded background. As explained, we conclude that the State's
approach is inconsistent with the CAA. We also note that the State's
use of current degraded background to analyze single-source controls is
facially inconsistent with the Q/D threshold it used to determine which
sources should be retained for a detailed evaluation of reasonable
progress controls. As noted, the State selected a Q/D of 10 based in
part on EPA BART guidance on sources that could be considered to
contribute to visibility impairment. That guidance relied on a
contribution threshold of 0.5 deciviews, which was premised on CALPUFF
modeling using natural background. By modeling single-source impacts
and benefits using current degraded background, North Dakota employed a
completely different metric that rendered meaningless its Q/D threshold
and subsequent analysis of the four factors.\66\
---------------------------------------------------------------------------

    \66\ We note that AVS 1 and 2 had Q/D values exceeding 100, and
Coyote had a Q/D value of 248, all far above the threshold Q/D
value.
---------------------------------------------------------------------------

    Comment: NDDH notes that EPA's guidance, ``Additional Regional Haze
Questions,'' dated August 24, 2006, states that the RP demonstration
involves a test of a strategy and how much progress is made through
that strategy. NDDH also notes that the guidance states that RP
modeling is tied to a strategy and is not a source-specific
demonstration like the BART assessment. NDDH asserts that EPA's
rejection of the North Dakota cumulative modeling for single source
visibility benefits arbitrarily ignores this guidance.
    Response: We find that this comment, like the previous comment,
conflates two separate aspects of reasonable progress: (1) The manner
in which the overall strategy is modeled for purposes of comparison to
the URP, and (2) the determination of controls for potentially affected
sources and source categories. In the latter context, we conclude that
our interpretation is reasonable and that the State's consideration of
visibility improvement based on current degraded visibility was
unreasonable.
    First, we have refined our guidance and our views on reasonable
progress since the cited document was issued. In 2007, we issued formal
reasonable progress guidance, which clearly contemplates that controls
may be evaluated on a source-specific basis.\67\ It is difficult to
imagine how the reasonableness of a control strategy involving large
stationary sources could be determined without considering the
reasonableness of controls for the specific stationary sources. Second,
the comment ignores the fact that North Dakota itself conducted a
source-specific analysis of potential control options using the four
factors.\68\ It was only when it considered the additional factor--
visibility--that North Dakota switched to a cumulative analysis. Third,
the commenter ignores the cited guidance's repeated admonition that
reasonable controls based on the four

statutory factors (which don't include visibility improvement) must be
included in the plan. Thus, for example, the guidance states:
---------------------------------------------------------------------------

    \67\ We note that guidance is not binding on EPA and does not
supersede relevant statutory and regulatory requirements.
    \68\ We note that other states--for example, Colorado--have also
considered reasonable progress control options on a source-specific
basis and that we intend to do so in our FIP for Montana for
regional haze.

    ``However, the statutory factors must be applied before
determining whether given emission reduction measures are
reasonable. In particular, the State should adopt a rate of progress
greater than the glidepath if this is found to be reasonable
---------------------------------------------------------------------------
according to the statutory factors.''

Guidance at 9. Similarly, the guidance states:

    ``If after applying the four statutory reasonable progress
factors, the rate of visibility improvement is still less than the
uniform glide path, States may adopt the calculated RPGs, provided
that they explain in the SIP how achieving the uniform glide path is
not reasonable based on the application of the factors. States must
demonstrate why the slower rate is reasonable * * *''

Guidance at 8-9.
    Comment: Basin Electric states that EPA has no statutory authority
to compel installation of LNB at AVS. Basin Electric argues that the
regional haze program applies only to sources in existence before 1977,
and that sources constructed after that date are subject only to the
PSD permitting program. Basin Electric concludes that EPA cannot impose
retrofit requirements on a source such as Antelope Valley that has
already been subject to the PSD permitting program.
    Response: EPA disagrees with this comment. First, the requirements
established in the RHR provide no basis for the commenter's argument,
as reasonable progress requirements are clearly not limited to sources
in existence before 1977. In particular, section 51.308(d)(1)(i)(A)
requires consideration of the four statutory factors for ``potentially
affected sources,'' a term not limited to sources in existence before
1977, and also requires a demonstration showing how the four statutory
factors were taken into consideration. Section 51.308(d)(1)(iii)
requires the Administrator to evaluate this demonstration, explicit
authority for the action we are finalizing. Finally, section
51.308(d)(3) requires that a state, in developing its LTS to achieve
the RPGs, consider ``major and minor stationary sources,'' a term again
not limited to sources in existence before 1977.
    Nor does the CAA itself provide any basis for the commenter's
argument. The comment is in error in suggesting that the existence of
requirements regarding visibility under the PSD permitting program
necessarily implies that section 169A of the CAA cannot apply to
sources subject to the PSD permitting program. As a general matter, it
is well understood that the CAA frequently imposes overlapping
requirements on sources. Nothing in Subpart I of Part C of Title I of
the CAA, which provides for the PSD permitting program, indicates that
sources subject to the PSD permitting program are somehow excluded from
the requirements of Subpart II. Similarly, nothing in EPA's rules
giving the minimum requirements for a state's PSD permit program at 40
CFR 51.166 or the federal PSD permit program at 52.21 supports the
notion that sources subject to the PSD permit program are excluded from
the requirements of Subpart II.
    Furthermore, any reasonable reading of CAA section 169A reveals
that Congress did not limit the requirements to achieve reasonable
progress to BART and PSD sources. Congress required EPA to promulgate
regulations to:

    ``require each applicable implementation plan for a State in
which any area listed by the Administrator under subsection (a)(2)
of this section is located * * * to contain such emission limits,
schedules of compliance and other measures as may be necessary to
make reasonable progress toward meeting the national goal specified
in subsection (a) of this section, including [BART].''

    There is nothing in this language to suggest that Congress intended
to exempt sources constructed after 1977, or to exempt sources subject
to the PSD permitting program.
    The commenter argues that CAA section 169A(g)(1) supports its view,
claiming that ``Section 169A(g)(1) defines the criteria to be employed
in determining reasonable progress, but limits the application of that
criteria to `any existing source.' '' The commenter interprets this
term to mean sources constructed before 1977, but does not explain how
reasonable progress toward the national goal of remedying existing
impairment of visibility could continue to be made under the
commenter's interpretation. Instead, the statute and our rules
contemplate a periodic, continuing assessment of reasonable progress,
including assessment of the four statutory factors for existing sources
at the time of assessment. Thus, our regional haze regulations reflect
a different interpretation--instead of ``any existing source,'' section
51.308(d)(1)(i)(A) refers to ``potentially affected sources.'' As
discussed above, there is no suggestion that we intended to limit this
to only mean sources constructed after 1977, and it is too late for the
commenter to challenge our regional haze regulations now. Thus, the
commenter's parsing of the statutory language and the legislative
history is irrelevant. Furthermore, EPA's reports to Congress and other
sources cited by the commenter do not reflect our interpretation of the
RHR and therefore have no regulatory weight.
    Comment: Basin Electric states that, under the RHR, if a state
proposes an RPG that doesn't meet the URP, all the state has to do is
explain why meeting the URP isn't reasonable.
    Response: This comment understates the requirements of the RHR. If
a state establishes an RPG that does not meet the URP, the state must
demonstrate, on the basis of the four RP factors, that (1) meeting the
URP isn't reasonable; and (2) the RPG adopted by the state is
reasonable. The commenter's statement ignores the requirement to
consider the four RP factors and to show that the RPG is reasonable.
EPA therefore disagrees with the statement.
    Comment: Basin Electric argues that no state has full control over
its RPGs, because visibility improvements depend largely on reductions
from other states.
    Response: Even if visibility impacts to an in-state Class I area
are largely due to sources in other states, each state is nonetheless
obliged to make RP determinations for in-state sources based on a
reasonable analysis of the four statutory factors. In this case, NDDH's
reliance on current degraded background modeling as an additional
factor was unreasonable. Thus, Basin Electric's argument gives no basis
for EPA to change its disapproval of the State's RPGs or the
NOX RP determination for AVS.
    Comment: Basin Electric states that visibility improvement cannot
be ignored in the RP four-factor analysis.
    Response: As we have noted, the four RP factors are the costs of
compliance, the time necessary for compliance, the energy and non-air
quality environmental impacts of compliance, and the remaining useful
life of any potentially affected sources. As we have also noted, when
visibility benefits are considered in the analysis of potential single-
source controls, such consideration must be reasonable. In this case,
NDDH unreasonably relied on modeling using current degraded background
to reject RP controls for AVS. Finally, in imposing LNB to meet
reasonable progress requirements, EPA has considered visibility
improvement, which, as shown by the CALPUFF modeling provided by NDDH,
is 0.754 deciviews at TRNP for installation of LNB at AVS.
    Comment: Basin Electric states that EPA's disapproval of North
Dakota's RP determination for AVS is based solely on EPA's rejection of
the State's use of a degraded background in modeling.

    Response: The basis for our disapproval is fully explained in our
proposal. 76 FR 58627, 58629-58630. We did not rely solely on the
State's use of improper modeling. We note that, despite the State's
flawed use of current degraded background modeling, we nonetheless
approved several of the State's other reasonable progress
determinations based on our consideration of the statutory reasonable
progress factors.
    Comment: Basin Electric argues that the dollar per deciview benefit
of LNB + SNCR at AVS, computed using North Dakota's modeling, is much
higher than that some FLMs have found acceptable. Basin Electric states
that EPA does not object to the use of dollar per deciview in making an
RP determination. Instead, EPA objects only to the modeling itself.
    Response: EPA guidance indicates that it may be reasonable to
evaluate the dollar per deciview value in appropriate circumstances.
However, EPA has not established a threshold, required or recommended,
below which such value is considered reasonable and above which it is
considered unreasonable. Nor have we endorsed or accepted any values
the FLMs may have found acceptable. Under our regulations, we determine
whether a state's rejection of reasonable progress controls is
reasonable based on the reasonable progress factors. We have explained
in response to other comments why North Dakota's modeling using current
degraded background and dollar per deciview values based on that
modeling are not reasonable. In addition, EPA is imposing only LNB, not
LNB + SNCR, at AVS. Thus, the dollar per deciview benefit of LNB + SNCR
is not directly relevant. We provide further detail regarding use of
dollars per deciview values in our response to prior comments.
    Comment: Basin Electric states that EPA has no basis to disregard
the State's cumulative modeling of visibility improvements at AVS.
Basin Electric argues that the reasoning for using degraded background
conditions in BART modeling applies equally to RP modeling, because the
horizon for RP sources is 2018 (similar to the five-year horizon for
BART).
    Response: As noted elsewhere, the reasoning for using current
degraded background conditions in BART modeling is faulty. That
reasoning therefore gives no basis for using current degraded
background conditions in RP modeling.
    Comment: Basin Electric states that EPA admits that there is no
requirement that states, when performing RP analysis, follow the
modeling procedures set out in the BART guidelines. Basin Electric
states that EPA does not cite any statute or rule that the North Dakota
RP modeling violates.
    Response: As we have noted, our regulations require consideration
of four factors in reasonable progress determinations; visibility
improvement is not one of the specified factors. As we have indicated,
when a state considers visibility improvement as an additional factor
in evaluating single-source control options, that consideration must be
reasonable in light of the explicit goals established by Congress in
CAA section 169A.
    Comment: Basin Electric states that EPA is in error in asserting
that North Dakota modeled BART sources one way and RP sources another
way. Basin Electric argues that even if EPA is correct, there is no
authority that requires the State to model BART and RP sources the same
way.
    Response: We disagree with the commenter. North Dakota relied on
CALPUFF modeling using natural background for almost all BART sources.
The only exceptions were MRYS 1 and 2 and LOS 2, and then only for
NOX. We explained in our proposal why North Dakota's
alternative modeling for these BART units for NOX was
unreasonable. Despite the similarity of several of the reasonable
progress units to the BART units, North Dakota modeled visibility
improvement for potential control options on individual reasonable
progress sources using current degraded background. We have explained
in our other responses and in our proposal why this was unreasonable.
    Comment: Basin Electric argues that states have the responsibility
to set RPGs and evaluate RP controls. Basin Electric states that
nothing prohibits the State from using degraded background conditions.
    Response: For the reasons already expressed, we disagree with the
import of this comment. We agree that the states have the
responsibility to set RPGs and evaluate RP controls in the first
instance, but EPA must determine if a state's determinations for RPGs
and for controls satisfy the requirements of the RHR and are
reasonable. In the case of AVS 1 and 2, the State's determination was
unreasonable.
    Comment: Basin Electric argues that, in considering the CALPUFF
modeling results for AVS, EPA should use the 90th percentile values,
not the 98th percentile values, and should use the three year average,
not the worst-case year.
    Response: For the same reasons expressed in our responses to
similar comments related to BART in section V.C, we disagree.
    Comment: Basin Electric argues that the case for using 90th
percentile values is stronger for RP, as RP is determined based on
improvement for the most impaired days, which is defined as the average
impairment for the 20% of days with the highest impairment. Basin
Electric states that use of the 98th percentile is inconsistent with
this provision.
    Response: EPA disagrees with this comment, which conflates and
misstates requirements of the RHR. Reasonable progress is not
``determined'' based on improvement for the most impaired days;
instead, improvement for the most impaired days is one, and not the
only, requirement for reasonable progress. Separately, states are
required to evaluate, considering the four statutory RP factors,
controls for potentially affected sources. In this separate
determination, when a state considers visibility benefits as an
additional factor, a state's assessment and analysis of visibility
benefits must be reasonable. Use of the 90th percentile, which
seriously understates visibility benefits, is unreasonable, and cannot
be justified by reference to the separate requirement regarding the
most impaired days.
    Comment: Basin Electric notes that EPA evaluated the cost of
controls for AVS Units 1 and 2 separately, but evaluated the visibility
benefits combined. Basin Electric argues that this is an invalid,
apples-to-oranges comparison.
    Response: Given that AVS 1 and 2 are the same size and are co-
located, and reductions would be similar from each, we do not agree
that it is invalid to consider the combined visibility benefits. There
is no requirement, when considering visibility benefits as an
additional factor, to separately model co-located and similar units.
Furthermore, dollar-per-ton values would not change significantly if
costs were evaluated for the two units combined. Finally, EPA notes
that, even if the visibility benefits were evenly divided between the
two units, EPA would still consider LNB appropriate at each unit, based
on the four statutory factors and the additional factor of visibility
benefits.
    Comment: Basin Electric references additional modeling, provided by
Basin Electric, that shows that the visibility benefits (using 90th
percentile, three-year average, and a receptor-by-receptor approach)
for LNB at AVS Units 1 and 2 combined is 0.07 deciviews. Divided
between the units equally, this would be

0.035 deciviews. Basin Electric argues that these improvements do not
support imposing LNB, especially when the dollars per deciview
improvement is considered.
    Response: As discussed elsewhere, we find it reasonable to use the
98th percentile, worst-of-three-year modeled benefit over all
receptors. The use of the 90th percentile, the three-year average, and
the receptor-by-receptor approach understates the visibility benefits
of controls. As a result, the dollar-per-deciview value computed using
that approach, found in Table 8 of Basin Electric's comments and from
which Basin Electric derives the 0.07 deciview figure, is not
reasonable or persuasive.
    Comment: Basin Electric argues that EPA's justification for
disapproving North Dakota's RPGs is insufficient. Basin Electric
asserts that, even if EPA is correctly determining BART and RP limits
for the individual facilities, EPA must provide some additional basis
for disapproving the RPGs, such as: (1) North Dakota is not providing
for improvement for the worst 20% days; or (2) North Dakota is not
ensuring no further degradation for the best 20% days. Basin Electric
also notes that EPA did not assess how far short (presumably
quantitatively) North Dakota's selected goals fall from reasonable
progress.
    Response: EPA disagrees with this comment. The bases suggested by
Basin Electric as necessary for disapproval (improvement for the worst
20% days and no further degradation for the best 20% days) are
requirements of the RHR, but they are not the only requirements. As
noted in the proposal, if a state's RPGs do not meet the URP, the state
must demonstrate that the RPGs are reasonable, based on consideration
of the four statutory factors, and that meeting the URP is
unreasonable. The State's failure to satisfy this requirement (and not
the requirements noted by the commenter) is the basis for the
disapproval of the State's RPGs. In particular, the State's use of
current degraded background in modeling for visibility benefits was
unreasonable, as was the State's failure to select reasonable RP
controls for AVS Units 1 and 2. It is unnecessary to quantify how far
short North Dakota's selected goals fall from the RPGs proposed by EPA
in order to determine that the State's analysis was unreasonable.
Nonetheless, EPA notes that the proposed NOX RP limit, based
on installation of LNB, for AVS Units 1 and 2 will result in combined
emissions reductions of over 7,000 tons per year of NOX,
with a visibility benefit of 0.754 deciviews at TRNP. Due to time and
resource constraints, we lacked the capability to re-do the WRAP
modeling to precisely re-calculate the RPGs.
    Comment: Basin Electric states that the values for cost
effectiveness of LNB at AVS Units 1 and 2 do not reflect up-to-date
costs, which would be higher. However, Basin Electric specifically
disclaims that up-to-date costs, standing alone, would provide a
sufficient reason to reject LNB.
    Response: In its FIP, EPA is relying in part on costs provided by
North Dakota in its RH SIP to meet the requirements of the RHR. In
promulgating the FIP, it is not necessary to regenerate the costs for
AVS 1 and 2. Nonetheless, EPA agrees that regenerated costs for LNB at
AVS Units 1 and 2 would likely support EPA's determination. LNB is a
widely used, inexpensive control option to reduce NOX
emissions.
    Comment: Citing 40 CFR 51.308(d), Basin Electric states that EPA
does not propose a true FIP for RPGs, because RPGs are defined by rule
as a rate of visibility improvement. Basin Electric alleges that
rerunning the WRAP CMAQ modeling with the controls imposed to quantify
the rate of improvement would cost a modest amount of money, and states
that this amount of money should be contrasted with the cost of
controls that will, according to Basin Electric, result in negligible
visibility improvements.
    Response: As discussed elsewhere, the visibility improvements from
AVS alone will not be negligible, as shown by the CALPUFF modeling
provided by North Dakota, and even the CALPUFF modeling provided by
Basin Electric with its comments. We assume Basin Electric bases its
statement about negligible visibility improvements on the modeling
using current degraded background relied on by North Dakota, which, as
discussed elsewhere, we are disregarding. As discussed in the notice of
proposed action, we would have preferred to quantify the rate of
improvement, but time and resource constraints prevented this. Re-
running the WRAP CMAQ modeling would not change our conclusion about
the reasonableness of LNB at AVS 1 and 2.
    Comment: Basin Electric states that, without modeling, there is no
basis for EPA to state that our FIP would increase the rate of
visibility improvement on the 20% worst days. Basin Electric asserts
that emissions reductions from the FIP sources are miniscule compared
with the total reductions assumed in the WRAP CMAQ modeling for RPGs.
Basin Electric notes that that modeling showed an overall 0.6 deciview
improvement at TRNP and a 0.5 deciview improvement at LWA.
    Response: It is logical to infer that the considerable emissions
reductions at CCS and AVS will increase the visibility improvement on
the 20% worst days. We acknowledged in our proposal that this
improvement would not be sufficient to achieve the URP (76 FR 58632)
and agree that the improvement will likely be small given that the
starting point for the cited modeling is current degraded conditions.
But the same could be said for BART sources, yet North Dakota has
acknowledged that such sources contribute to visibility impairment in
the Class I areas in North Dakota.
    Comment: Basin Electric states that the disapproval of North
Dakota's RPGs and our FIP have no meaningful effect.
    Response: As we stated in our proposal, the RPGs are not
enforceable values. To that extent, they do not impose requirements on
anyone. However, we are required to disapprove the RPGs because they do
not reflect reasonable controls at CCS and AVS, and we are required to
impose a FIP in lieu of the State's unapprovable RPGs. Our reasonable
progress controls at AVS and our BART controls at CCS do impose
enforceable requirements.
    Comment: Basin Electric asserts that, because EPA has no basis for
our disapprovals and FIPs at individual facilities, EPA also has no
basis for our FIP for RPGs.
    Response: See our responses to prior comments. We have explained
the bases for our disapprovals.
    Comment: NPCA comments that it is unreasonable for EPA to give
Basin Electric until July 31, 2018 to install LNB at Antelope Valley
because that date is not ``as expeditious as possible.'' NPCA states
that the deadline should be January 26, 2013, which NPCA believes
represents a reasonable amount of time to install the combustion
controls.
    Response: EPA disagrees with this comment. First, unlike for BART
sources, the RHR and the CAA do not explicitly require that limits for
RP sources be met as expeditiously as practicable. Furthermore, the
commenter misstates the deadline: The proposed FIP requires Basin
Electric to meet the proposed NOX emissions limit at
Antelope Valley ``as expeditiously as practicable, but in any event no
later than July 31, 2018.'' Thus, Basin Electric is under an obligation
to install the combustion controls as expeditiously as practicable. The
cutoff date of July 31, 2018 ensures that the RP limit for Antelope
Valley is met by the end of the planning period, thereby also ensuring
that the proposed RPGs are met.
    Comment: NPCA states that EPA should reevaluate the cost estimate
for

SCR + reheat at AVS. NPCA argues that North Dakota's cost estimate is
flawed in the same way as for LOS 2 and MRYS 2. EPA proposed to
disapprove the costs for Leland Olds Unit 2; NPCA argues that EPA
therefore cannot rely on the same costs in determining RP controls for
Antelope Valley.
    Response: While EPA agrees that the cost estimates for SCR at LOS 2
and MRYS 2 are flawed, the costs for AVS nonetheless present a
sufficient basis for EPA's RP determination. EPA accepts, and NPCA does
not question, the costs for LNB alone. Even if the cost estimate for
SCR + reheat was redone, it would likely remain considerably more
costly than LNB. LNB is very cost-effective and achieves reductions of
about 78% of SNCR + LNB and 64% of SCR with reheat. Given the extreme
cost-effectiveness of LNB and reductions of at least 64% of more
expensive controls, and taking into account the four statutory factors
as well as visibility benefits of LNB, EPA has determined that it is
reasonable to impose LNB at Antelope Valley in this planning period. Of
course, the imposition of LNB at AVS does not rule out the imposition
of post-combustion controls in the next planning period.
    Comment: NPCA states that North Dakota's cost estimates for SCR +
reheat and ASOFA + SCR + reheat at Coyote Station are flawed. NPCA
argues that EPA should redo the RP analysis for Coyote, and that a
revised RP four-factor analysis would show that SCR + reheat is
reasonable. In addition, NPCA notes that the facility is fairly close
to TRNP, the State cannot meet the URP, and SCR + reheat would reduce
emissions by over 10,000 tpy.
    The NPS states similar concerns with North Dakota's use of
inappropriate dollar per deciview estimates as a basis for determining
that no additional controls were appropriate under RP for Coyote
Station. NPS notes that EPA has recognized that the methods North
Dakota used to reach that conclusion, both for estimating costs and
visibility improvement, are invalid. NPS infers that North Dakota has
not met its responsibility to conduct a valid RP analysis and that EPA
must therefore assume that responsibility. An NPS analysis indicates
SCR at Coyote would be more cost effective than at any other North
Dakota EGU. NPS concludes that EPA must impose an RP emissions limit
for Coyote of 0.07 lb/MMBtu (the same as for MRYS 1 and 2, and LOS 2).
    Response: EPA has now decided that the rejection of SCR at Coyote
is appropriate regardless of the State's cost analysis, based on the
court's upholding of North Dakota's determination in the BACT
proceeding for MRYS that SCR is technically infeasible. Like MRYS,
Coyote is a cyclone unit burning North Dakota lignite. Thus, based on
current evidence, we cannot conclude that North Dakota's rejection of
SCR at Coyote was unreasonable.
    Comment: NPCA states that the record shows that a wet scrubber
would be cost effective at Coyote Station, and believes that the actual
cost effectiveness may be better. NPCA computes that a 99% efficient
wet scrubber would remove about 13,000 tons per year of SO2.
The cost overestimates made by other facilities indicate that EPA
should revisit this cost analysis.
    Response: EPA disagrees with this comment. First, NPCA did not
identify any cost overestimates related to wet scrubbers. The issues
EPA identified in its proposal related to costs of SCR, which provides
no basis for inferring cost overestimates for wet scrubbers. As far as
the record, Table 9.8 in North Dakota's RH SIP submittal shows a cost
effectiveness value of $2,593 per ton of SO2 removed at a
control efficiency of 95%. As stated in our proposal, while this value
is within the range of cost effectiveness values that North Dakota,
other states, and we have considered reasonable in the BART context, it
is not so low that we are prepared to disapprove the State's conclusion
in the reasonable progress context. In addition, Coyote Station
currently employs a spray dryer to control SO2 emissions at
a control efficiency of approximately 66%. The existence of this
control supports our approval of the State's determination. Analogous
to our policy in the BART context, we do not expect sources to install
entirely new SO2 controls where they are already achieving
reductions greater than 50%.
    Comment: NPCA notes EPA's response to a petition from the Dakota
Resource Council regarding violations of PSD Class I SO2
increments, in which EPA stated that a SIP call would not achieve any
better result than other pending actions, including regional haze
actions. NPCA argues that, based on this response, EPA should require
SO2 controls at Coyote Station to reduce consumed Class I
SO2 increment.
    Response: EPA disagrees with this comment. As discussed extensively
in our response to a prior comment, PSD permit program requirements in
Subpart I, Part C of title I of the CAA are separate from visibility
protection requirements in Subpart II of Part C. Therefore, Class I
SO2 increments are not relevant to our action on North
Dakota's RH SIP submittal to meet the requirements of CAA section 169A
and the RHR. Nonetheless, EPA notes that SO2 emissions will
be substantially reduced by our action on the North Dakota RH SIP, as
detailed in Table 21 of our notice proposing action.
    Comment: NPCA argues that limestone injection at Heskett Station is
a cost effective and reasonable RP control that would achieve
SO2 reductions of 1614 tons per year. However, NPCA notes
that the agreement between North Dakota and the facility only requires
reductions of 573 tons per year of SO2. NPCA concludes that
EPA should require Heskett to achieve an SO2 limit that
reflects the capabilities of limestone injection.
    Response: EPA considers the State's determination to impose the
stated reductions in the permit included in SIP Supplement No. 1 to be
reasonable and to satisfy reasonable progress requirements in this
initial planning period. Further reductions may be appropriate in a
subsequent planning period.
    Comment: NPCA argues that staged combustion is a cost effective
control for NOX at Heskett Station at $1,700/ton. Even
though the emission reduction is only 215 tons per year, NPCA argues
that EPA must consider all potential sources that can contribute to
achieving RPGs, including NOX reductions from Heskett
Station.
    Response: EPA disagrees with this comment. In the first instance,
it is the responsibility of the State to consider the four statutory
factors for potentially affected sources. EPA's task is to determine if
the State's analysis of controls satisfies the requirements of the RHR
and is reasonable. In this case, the State did consider the four
statutory factors, as well as an additional factor--visibility
improvement based on modeling using current degraded background. While
EPA does not consider the State's use of modeling based on current
degraded background reasonable, EPA nonetheless considers the result of
the State's analysis in this instance to be reasonable, based on the
relatively low emissions reductions and the costs of controls.
    Comment: NPCA states that several NOX control options
for Tioga Gas Plant are cost effective, with the lowest at $521/ton.
Although the emissions reductions are lower, NPCA argues that EPA
should consider all potential sources that can contribute to achieving
RPGs. In addition, NPCA notes that the facility is only 35 km from LWA
and is also near TRNP.
    Response: EPA disagrees with this comment for the same reasons
discussed in response to the prior comment.

    Comment: NPCA states that EPA should re-run the WRAP CMAQ modeling
with emissions that reflect the BART and RP controls that EPA proposes
to approve or impose through a FIP. NPCA argues that EPA and the State
should track actual visibility improvements versus projected visibility
improvements, and that this would assist in estimating visibility
improvements from other measures.
    Response: As stated in our notice of proposed action, we could not
re-run the WRAP modeling due to time and resource constraints. We
expect the State to quantify the visibility improvement in its next RH
SIP revision.
    Comment: The NPS stated that North Dakota did not meet its
responsibility to perform a valid RP analysis, as the State's cost
analysis and modeling for RP sources were flawed. Although the NPS
stated that this was a general issue, the comment specifically noted
flaws in the State's cost analysis for Coyote Station. The NPS argued
that EPA must redo the analysis, and cannot propose to approve any RP
determinations.
    Response: EPA disagrees with the conclusion of this comment.
Although EPA agrees that the State's cost analysis for SCR at Coyote
Station was flawed, and that the State's modeling of visibility
benefits of controls on RP sources using degraded background conditions
was flawed, there is a sufficient basis for EPA's actions. As noted in
a prior response, EPA has now decided that the rejection of SCR at
Coyote is appropriate regardless of the State's cost analysis, based on
the court's upholding of North Dakota's determination in the BACT
proceeding for MRYS that SCR is technically infeasible. Like MRYS,
Coyote is a cyclone unit burning North Dakota lignite.
    As noted, with respect to other reasonable progress units, we have
disregarded the State's visibility analysis in our review of the
State's reasonable progress determinations and instead focused on the
four reasonable progress factors. Except for AVS 1 and 2, we have
determined that the State's reasonable progress determinations were not
unreasonable.
    Comment: The NPS stated that the RP analysis of SCR for Coyote
Station was cursory. The NPS noted that, under the 0.50 lb/MMBtu annual
rate agreed to by the State, Coyote Station would still have the
highest controlled emissions rate of any EGU in North Dakota and would
be the 13th largest emitter of NOX among all EGUs, using
2010 rates in the Clean Air Markets Division database. NPS argues that,
as a result, SCR should have been given more consideration.
    Response: First, EPA disagrees with some of the NPS computations.
Based on 2010 Clean Air Markets Division data, Coyote Station was the
124th largest emitter of NOX among EGUs at 13,691 tons. At
the rate of 0.50 lb/MMBtu agreed to by the State, the emissions (with
the same heat input) would have been 8,800 tons, which would have made
Coyote Station the 183rd largest emitter of NOX for that
year. This represents a reduction of over 4,800 tons per year. In any
case, the relative rank of a facility among other facilities nationwide
in overall emissions is not a necessary component of the RP analysis.
    We have already explained why we are not disapproving the State's
rejection of SCR at Coyote.
    Comment: The NPS noted that the RP analysis for Coyote Station did
not consider upgrades to the existing dry scrubber.
    Response: In making an RP determination, the State must consider a
reasonable range of controls. For SO2, the State considered
a new wet scrubber. While EPA agrees that upgrades to the existing dry
scrubber should have been considered, starting with feasibility, EPA is
not prepared to determine, on the basis of this consideration, that the
State was unreasonable in addressing RP requirements for Coyote Station
through imposing the 0.50 lb/MMBtu NOX limit and not
imposing an SO2 limit. EPA does expect the State to revisit
the range of controls in the next planning period.
    Comment: NPS provided cost estimates for installation of SCR at
Coyote Station, showing a cost effectiveness value of $1,600 per ton
removed and an incremental cost effectiveness value of $2,300 per ton
removed. NPS stated that these costs are lower than those for SCR at
LOS 2 and MRYS 1 and 2. NPS argued that, for consistency, EPA must
impose SCR at Coyote Station.
    Response: The basis for our decision regarding the State's
rejection of SCR at Coyote is explained in prior responses.

H. Comments on Health and Ecosystem Benefits, and Other Pollutants

    Comment: Several commenters stated that haze pollution
significantly impacts human health and ecosystem health, in addition to
obscuring scenic vistas. Specifically, commenters asserted that haze
pollution contributes to heart attacks, asthma attacks, chronic
bronchitis and respiratory illness, increased hospital admissions, lost
work days, and even premature death. One commenter noted the specific
haze pollutants NOX, SO2 and PM, which the
commenter stated are all harmful to the human body.
    Some commenters cited a 2009 Clean Air Task Force report in stating
that coal-fired power plants in North Dakota put 207 people at risk of
premature death, 321 people at risk of a heart attack, and 3,500 at
risk of an asthma attack each year. Several commenters encouraged EPA
to finalize the regional haze proposal citing their own health
problems, most notably individuals with asthma or respiratory problems,
seniors, and parents of asthmatic children. One commenter stated the
rate of asthma in North Dakota children is increasing rapidly.
    Some commenters stated that haze pollution negatively impacts
ecosystem health. Commenters expressed concern for the effects of haze
pollution on wildlife, farm animals, plants including crops, and water
bodies. Several commenters generally expressed their disapproval of
coal as an energy source because it is dirty, with some insisting that
North Dakota invest in cleaner energy.
    Response: We appreciate the commenters' concerns regarding the
negative health impacts of emissions from the coal-fired power plants
in North Dakota. We agree that the same PM2.5 emissions that
cause visibility impairment can be inhaled deep into lungs, which can
cause respiratory problems, decreased lung function, aggravated asthma,
bronchitis, and premature death. We also agree that the same
NOX emissions that cause visibility impairment also
contribute to the formation of ground-level ozone, which has been
linked with respiratory problems, aggravated asthma, and even permanent
lung damage. We agree that these pollutants can have negative impacts
on plants and ecosystems, damaging plants, trees and other vegetation,
and reducing forest growth and crop yields, which could have a negative
effect on species diversity in ecosystems. However, for purposes of
this action, we are not authorized to consider these impacts in
evaluating the State's RH SIP and promulgating our FIP, and we have not
done so.
    Comment: Some commenters stated that regional haze is not a health-
based standard.
    Response: We agree that regional haze is not a health-based
standard.

I. Miscellaneous Comments

    Comment: Several commenters stated that the large economic costs of
installing pollution controls stated by electricity providers failed to
consider

the significant offsets of those costs. One commenter stated that TRNP
is an economic engine, further stating that the park logged over
580,000 recreational visits, was responsible for 500 jobs and $27.4
million in expenditures in 2009 alone. Another commenter stated that,
while the installation of pollution controls costs money, it also
stimulates the economy by providing jobs in construction and
installation. Others stated a willingness to pay the expected increase
in their utility costs, with one commenter stating that North Dakota's
electricity is amongst the least expensive in the U.S.
    Response: We agree with the comments. Although we did not consider
the potential positive benefits to the local and national economies in
making our decision today, we do expect that improved visibility would
have a positive impact on tourism-dependent local economies. Also,
retrofitting CCS with SNCR is a large construction project that we
expect to take 5 years to complete. This project, along with the other
pollution control upgrades proposed in the SIP, will require well-paid,
skilled labor which can potentially be drawn from the local area, which
is expected to benefit the economy.
    Comment: Multiple commenters stated that North Dakota is one of
only 12 states in the U.S. who meet all NAAQS.
    Response: While the relative air quality in North Dakota is
considered good compared to many other states, as further discussed
elsewhere in our responses, our actions pertaining to the RHR are
governed by the national visibility goal established by Congress in the
CAA. The goal is to return the visibility conditions in Class I areas
back to natural conditions. And visibility in Class I areas in North
Dakota is impaired by pollution from industrial sources within the
state. There is no direct correlation between natural visibility
conditions and the current NAAQS.
    Comment: Several commenters stated that the American Lung
Association ranked Mercer County, North Dakota, home to several coal-
fired power plants, as one of the 25 cleanest counties in the U.S., and
ranked Billings County, North Dakota, home to TRNP, the third cleanest
county in the United States.
    Response: The commenters are referring to the 2010 State of the Air
Report, which assigns letter grades for counties with air quality
monitors for ozone and particulate pollution.\69\ The report, issued
every year by the American Lung Association, did give the mentioned
counties an ``A'' grade in 2010 for ground level ozone. The State of
the Air Report does not, however, address regional haze. The RHR relies
on a combination of monitoring data to assess current visibility
conditions and modeling of predicted visibility impacts at federal
Class I areas (primarily national parks and wilderness areas), which is
a different methodology than direct measurement of ozone and
particulate pollution, which is the approach relied on by the American
Lung Association. Current visibility impacts at TRNP and LWA are over
double the impacts estimated for natural conditions, and North Dakota's
Class I areas are not projected to meet the URP in the initial planning
period.
---------------------------------------------------------------------------

    \69\ The American Lung Association State of the Air report is
available at www.stateoftheair.org.
---------------------------------------------------------------------------

    Comment: Commenter cited the NPS's Web page for TRNP, which states
that the park has better air quality than every other U.S. national
park aside from Denali National Park in Alaska.
    Response: In our action, we are responding to the national
visibility goal established by Congress in the CAA. The goal is to
return to natural visibility conditions. TRNP is not meeting the URP
for returning the park to natural visibility conditions. The NPS' Web
page for TRNP does state that air quality is relatively good, but it
also discusses the fact that pollution sometimes causes haze and may
affect other sensitive resources in the park. For current information
on TRNP's air quality visit http://www.nps.gov/thro/naturescience/airquality.htm.
    Comment: Commenter insisted that CCS and LOS should be retired, as
they are respectively rated the 3rd and 19th most polluting coal plants
in the U.S. (Citing sourcewatch.org.)
    Response: While we respect the commenter's opinion, a regulatory
process has been established under the CAA and our regulations for
considering pollution controls to address visibility impairment, and
our action follows that process.
    Comment: Many commenters generally stated that the costs of EPA's
proposed rule are high when compared to benefits. They stated that
NDDH's SIP costs much less to implement than does EPA's plan, and
produces similar benefits. High costs were cited both with respect to
capital costs of the controls as well as increased costs (retail price
per kilowatt hour) to consumers particularly fixed and lower-income
consumers. Negative economic impacts to agriculture and oil and gas
industries were cited, noting that the success of these industries is
dependent on low-cost and reliable electric power. Several commenters
specifically mentioned a cost of $700 million to install EPA's proposed
controls and the potential for lost jobs. Some commenters expressed a
willingness to pay the potential increase in their electric bills
because they supported EPA's action.
    Response: While we disagree with a number of the commenters'
assertions, these comments are largely no longer relevant because we
have decided to approve North Dakota's NOX BART
determinations for MRYS 1 and 2 and LOS 2 on grounds explained
elsewhere. To the degree that some of these comments extend to our FIP
for CCS and AVS, EPA's evaluation of capital and annual expenses
associated with implementation of the FIP shows such expenses to be
justified by the degree of improvement in visibility in relationship to
the cost of implementation.
    We take our duty to estimate the cost of controls very seriously,
and make every attempt to make a thoughtful and well informed
determination. However, we do not consider a potential increase in
electricity rates to be the most appropriate type of analysis for
considering the costs of compliance in a BART determination.
Nevertheless, our analysis indicates that the annual costs to CCS and
AVS associated with our FIP will be relatively modest considering the
size of the plants, and impacts to rate payers should be much lower
than anticipated by commenters.
    Comment: Commenter cited EPA's Clean Air Markets database, which
states that North Dakota ranked 12 in SO2 emissions
and 19 in NOX emissions. The commenter also
provided the SO2 and NOX rankings for the seven
North Dakota EGUs discussed in the SIP.
    Response: We appreciate the commenter providing the SO2
and NOX rankings for North Dakota and its EGUs. We do not
disagree with the information provided and acknowledge the data suggest
the North Dakota plants rank relatively high in the amount of
SO2 and NOX emissions compared to other states.
However, we note that BART and RP determinations involve case-by-case
determinations considering the relevant statutory factors, which do not
include the relative emissions rankings.
    Comment: Commenter requests that EPA set limits on ammonia slip
where SNCR or SCR is required for BART.
    Response: In Section 7.1.2 of the SIP, North Dakota concluded that
ammonia is not a visibility impairing pollutant of concern as ammonia
emissions (and associated regional haze impacts) from BART-eligible
sources are negligible. We concur with this conclusion.

Accordingly, there is no basis to set limits on ammonia slip to address
concerns related to regional haze impacts. Nor is it necessary to set
limits on ammonia slip to ensure compliance with NOX
emission limits because NOX CEMS will be used.

J. Comments Requesting an Extension to the Public Comment Period

    Comment: One commenter requested that the comment period be
extended to December 21, 2011 and Governor Dalrymple and Senator Hoeven
requested the time allotted for the public hearings be increased.
    Response: The comment period for our proposal closed on November
21, 2011. We carefully considered the request for an extension to the
comment period. We took into consideration how an extension might
affect our ability to consider comments received on the proposed action
and still comply with our consent decree deadlines. We do note that our
October 13 and 14, 2011, public hearing in Bismarck, North Dakota was
well attended and provided an opportunity for people to comment on our
proposal. Also regarding the public hearings, we agreed to Governor
Dalrymple's and Senator Hoeven's requests to extend the length of the
public hearing and to allow as much time as needed for state
representatives to present their comments.

K. Comments Generally in Favor of Our Proposal

    Comment: Overall, we received more than 24,000 comment letters in
support of our rulemaking from members representing various
organizations, concerned citizens, and tribal members. These comments
were received at the Public Hearing in Bismarck, North Dakota, by
internet, and through the mail. Each of these commenters was generally
in favor of portions of our proposed decision for North Dakota regional
haze. These comments included comments urging us to require the most
effective pollution control technology, SCR, at LOS 2, and MRYS 1 and 2
and additional emission reductions from CCS 1 and 2 and AVS 1 and 2.
Some of these comments also discussed the detrimental health effects of
haze pollution and the economic impacts of these health effects. Some
of these comments urged us to keep or lower our proposed numeric limits
on NOX for MRYS and LOS 2 in our final decision. These
letters also asked us to require other units at LOS, Heskett Station,
and Stanton Station to modernize and reduce their air pollution
impacts.
    Response: We acknowledge the support of these commenters for our
proposed action. We note that several of the control technology
determinations and emissions limits supported by these commenters in
the proposal have been changed in this final action based on the
Minnkota BACT court decision and all of the information received during
the comment period. Please see the docket associated with this action
for additional detail. To the extent the comments asserted the need for
more stringent controls, we address those comments in other responses.

L. Comments Generally Against Our Proposal

    Comment: Various commenters generally stated they did not support
the proposed rulemaking. Their reasons included: it will affect the
town's economy, affect the coal power plant industry, electricity costs
will increase, they have no direct health problems from actual
emissions, direct and indirect jobs/businesses would be affected, North
Dakota already meets air quality standards, that there will be no
benefit to the community, that our decision relies on unproven
technology, and that it will not result in noticeable visibility
improvements.
    We received three resolutions from cities in Minnesota, including
Roseau, Big Falls, and Little Fork, which opposed our rulemaking. These
resolutions included comments about the proposed FIP for SCR technology
at MRYS, including comments about the high cost, that the technology
had not been shown to work at similar plants, and that there would be
no humanly perceptible visibility improvements over the State's plan.
The resolutions also noted that Minnkota had already incurred
significant costs for installing SNCR and contracting for renewable
sources, and that these expenditures were resulting in rate increases.
    We received petitions and mass mailer letters from nine rural power
cooperative associations and over 3,000 comments generated through a
Web site established by an organization named Partners for Affordable
Energy. Comments from these letters and emails included the following:
that Congress left the primary responsibility for SIPs with states,
that states have superior knowledge of local conditions and needs, and
that EPA's plan would provide imperceptible visibility benefits at huge
costs. The comments also urged EPA to allow North Dakota to make its
own decisions regarding its clean air programs.
    Response: We acknowledge these general comments that opposed our
proposed action. We provide responses that address these issues
elsewhere in this action. We have made changes from our proposal, as
noted elsewhere in this action.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011). As discussed in detail in section C
below, the FIP applies to only two facilities. It is therefore not a
rule of general applicability.

B. Paperwork Reduction Act

    This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Under the Paperwork Reduction Act, a ``collection of information'' is
defined as a requirement for ``answers to * * * identical reporting or
recordkeeping requirements imposed on ten or more persons * * *.'' 44
U.S.C. 3502(3)(A). Because the FIP applies to just two facilities, the
Paperwork Reduction Act does not apply. See 5 CFR 1320(c).
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid Office of Management and Budget (OMB) control number.
The OMB control numbers for our regulations in 40 CFR are listed in 40
CFR Part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare

a regulatory flexibility analysis of any rule subject to notice and
comment rulemaking requirements under the Administrative Procedure Act
or any other statute unless the agency certifies that the rule will not
have a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this action on small
entities, I certify that this proposed action will not have a
significant economic impact on a substantial number of small entities.
The FIP that EPA is finalizing for purposes of the visibility prong of
section 110(a)(2)(D)(i)(II) consists of the combination of the approval
of the State's RH SIP submission and the Regional Haze FIP by EPA that
adds additional controls to certain sources. The Regional Haze FIP that
EPA is finalizing for purposes of the regional haze program consists of
imposing federal controls to meet the BART requirement for
NOX emissions at one source in North Dakota, and imposing
controls to meet the reasonable progress requirement for NOX
emissions at one additional source in North Dakota. The net result of
these two simultaneous FIP actions is that EPA is proposing direct
emission controls on selected units at only two sources. The sources in
question are each large electric generating plants that are not owned
by small entities, and therefore are not small entities. The partial
approval of the SIP merely approves state law as meeting Federal
requirements and imposes no additional requirements beyond those
imposed by state law. See Mid-Tex Electric Cooperative, Inc. v. FERC,
773 F.2d 327 (D.C. Cir. 1985).

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and Tribal
governments and the private sector. Under section 202 of UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and Tribal governments, in
the aggregate, or to the private sector, of $100 million or more
(adjusted for inflation) in any 1 year. Before promulgating an EPA rule
for which a written statement is needed, section 205 of UMRA generally
requires EPA to identify and consider a reasonable number of regulatory
alternatives and to adopt the least costly, most cost-effective, or
least burdensome alternative that achieves the objectives of the rule.
The provisions of section 205 of UMRA do not apply when they are
inconsistent with applicable law. Moreover, section 205 of UMRA allows
EPA to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator
publishes with the final rule an explanation why that alternative was
not adopted. Before EPA establishes any regulatory requirements that
may significantly or uniquely affect small governments, including
Tribal governments, it must have developed under section 203 of UMRA a
small government agency plan. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
    Under Title II of UMRA, EPA has determined that this rule does not
contain a Federal mandate that may result in expenditures that exceed
the inflation-adjusted UMRA threshold of $100 million by State, local,
or Tribal governments or the private sector in any 1 year. In addition,
this rule does not contain a significant Federal intergovernmental
mandate as described by section 203 of UMRA nor does it contain any
regulatory requirements that might significantly or uniquely affect
small governments.

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces
Executive Orders 12612 (Federalism) and 12875 (Enhancing the
Intergovernmental Partnership). Executive Order 13132 requires EPA to
develop an accountable process to ensure ``meaningful and timely input
by State and local officials in the development of regulatory policies
that have federalism implications.'' ``Policies that have federalism
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government.'' Under Executive Order 13132, EPA may not issue a
regulation that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides the funds necessary to pay the direct
compliance costs incurred by State and local governments, or EPA
consults with State and local officials early in the process of
developing the proposed regulation. EPA also may not issue a regulation
that has federalism implications and that preempts State law unless the
Agency consults with State and local officials early in the process of
developing the proposed regulation.
    This rule will not have substantial direct effects on the States,
on the relationship between the national government and the States, or
on the distribution of power and responsibilities among the various
levels of government, as specified in Executive Order 13132, because it
merely addresses the State not fully meeting its obligation to prohibit
emissions from interfering with other states' measures to protect
visibility established in the CAA and not fully meeting its obligation
to adopt a SIP that meets the regional haze requirements under the CAA.
Thus, Executive Order 13132 does not apply to this action.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    Executive Order 13175, entitled Consultation and Coordination with
Indian Tribal Governments (65 FR 67249, November 9, 2000), requires EPA
to develop an accountable process to ensure ``meaningful and timely
input by tribal officials in the development of regulatory policies
that have tribal implications.'' We believe this rule does not have
tribal implications, as specified in Executive Order 13175, and will
not have substantial direct effects on tribal governments. Thus,
Executive Order 13175 does not apply to this rule.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children from Environmental
Health

Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to any
rule that: (1) Is determined to be economically significant as defined
under Executive Order 12866; and (2) concerns an environmental health
or safety risk that we have reason to believe may have a
disproportionate effect on children. EPA interprets EO 13045 as
applying only to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the EO
has the potential to influence the regulation. This action is not
subject to EO 13045 because it implements specific standards
established by Congress in statutes. However, to the extent this rule
will limit emissions of NOX, the rule will have a beneficial
effect on children's health by reducing air pollution.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355
(May 22, 2001)), because it is not a significant regulatory action
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 requires Federal agencies to evaluate existing
technical standards when developing a new regulation. To comply with
NTTAA, EPA must consider and use ``voluntary consensus standards''
(VCS) if available and applicable when developing programs and policies
unless doing so would be inconsistent with applicable law or otherwise
impractical.
    The EPA believes that VCS are inapplicable to this action. Today's
action does not require the public to perform activities conducive to
the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    We have determined that this rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it increases the level of environmental
protection for all affected populations without having any
disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. This rule limits emissions of NOX from two
facilities in North Dakota. The partial approval of the SIP merely
approves state law as meeting Federal requirements and imposes no
additional requirements beyond those imposed by state law.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on May 7, 2012.

L. Judicial Review

    Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by June 5, 2012. Pursuant to CAA section
307(d)(1)(B), this action is subject to the requirements of CAA section
307(d) as it promulgates a FIP under CAA section 110(c). Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. See CAA section 307(b)(2).

Approval and Promulgation of Implementation Plans; North Dakota;
Regional Haze State Implementation Plan; Federal Implementation Plan
for Interstate Transport of Pollution Affecting Visibility and Regional
Haze. Final Rule. (EPA-R08-OAR-2010-0406)

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Intergovernmental
relations, Incorporation by reference, Nitrogen dioxides, Particulate
matter, Reporting and recordkeeping requirements, Sulfur dioxide,
Volatile organic compounds.

    Dated: March 1, 2012.
Lisa P. Jackson,
Administrator.

    40 CFR part 52 is amended as follows:

PART 52--[AMENDED]

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart JJ--North Dakota

0
2. Section 52.1820 is amended by:
0
a. Adding to the table in paragraph (c) an entry entitled ``33-15-25
Regional Haze Requirements'' at the end of the table.
0
b. Revising the table in paragraph (d).
0
c. Adding to the table in paragraph (e)entries ``(23),'' ``(24),'' and
``(25)'' in numerical order at the end of the table.
    The revisions and additions read as follows:

Sec.  52.1820  Identification of plan.

* * * * *
    (c) * * *

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                State
          State citation                Title/subject      effective date    EPA approval date and  citation \1\                Explanations
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      * * * * * * *
                                                           33-15-25 Regional Haze Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
33-15-25-01.......................  Definitions..........          1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                                                            number where the document begins.].
33-15-25-02.......................  Best available                 1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     retrofit technology.                   number where the document begins.].
33-15-25-03.......................  Guidelines for best            1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     available retrofit                     number where the document begins.].
                                     technology
                                     determinations under
                                     the regional haze
                                     rule.
33-15-25-04.......................  Monitoring,                    1/1/07  4/6/12, [Insert Federal Register page   .....................................
                                     recordkeeping, and                     number where the document begins.].
                                     reporting.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column
  for the particular provision.

* * * * *
    (d) * * *

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                State
          Name of source            Nature of requirement  effective date    EPA approval date and  citation \3\                Explanations
--------------------------------------------------------------------------------------------------------------------------------------------------------
Leland Olds Station Unit 1........  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10004.
Leland Olds Station Unit 2........  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10004.
Milton R. Young Station Unit 1....  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10007.
Milton R. Young Station Unit 2....  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10007.
Coal Creek Station Unit 1.........  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   Excluding the NOX BART emissions
                                     permit to construct                    number where the document begins.].     limits for Unit 1 and corresponding
                                     for best available                                                             monitoring, recordkeeping, and
                                     retrofit technology                                                            reporting requirements, which EPA
                                     (BART), PTC10005.                                                              disapproved.

Coal Creek Station Unit 2.........  Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   Excluding the NOX BART emissions
                                     permit to construct                    number where the document begins.].     limits for Unit 2 and corresponding
                                     for best available                                                             monitoring, recordkeeping, and
                                     retrofit technology                                                            reporting requirements, which EPA
                                     (BART), PTC10005.                                                              disapproved.
Stanton Station Unit 1............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air pollution control         2/23/10  4/6/12, [Insert Federal Register page   .....................................
                                     permit to construct                    number where the document begins.].
                                     for best available
                                     retrofit technology
                                     (BART), PTC10006.
Heskett Station Unit 1............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
Heskett Station Unit 2............  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
                                    Air Pollution Control         7/22/10  4/6/12, [Insert Federal Register page   .....................................
                                     Permit to Construct,                   number where the document begins.].
                                     PTC10028.
Coyote Station Unit 1.............  Air Pollution Control         3/14/11  4/6/12, [Insert Federal Register page   .....................................
                                     Permit to Construct,                   number where the document begins.].
                                     PTC10008.
American Crystal Sugar at Drayton.  SIP Chapter 8,                 5/6/77  10/17/77, 42 FR 55471.                  .....................................
                                     Section 8.3,
                                     Continuous Emission
                                     Monitoring
                                     Requirements for
                                     Existing Stationary
                                     Sources, including
                                     amendments to
                                     Permits to Operate
                                     and Department Order.
Tesoro Mandan Refinery............  SIP Chapter 8,                2/27/07  5/27/08, 73 FR 30308.                   .....................................
                                     Section 8.3.1,
                                     Continuous Opacity
                                     Monitoring for Fluid
                                     Bed Catalytic
                                     Cracking Units:
                                     Tesoro Refining and
                                     Marketing Co.,
                                     Mandan Refinery.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\3\ In order to determine the EPA effective date for a specific provision listed in this table, consult the Federal Register notice cited in this column
  for the particular provision.

* * * * *
    (e) * * *

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                        Applicable
    Name of nonregulatory SIP          geographic or       State submittal date/adopted date    EPA approval date and  citation \3\      Explanations
            provision               nonattainment area
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                                      * * * * * * *
(23) North Dakota State            Statewide...........  Submitted: 3/3/10...................  4/6/12, [Insert Federal Register      Excluding portions
 Implementation Plan for Regional                                                               page number where the document        of the following:
 Haze.                                                                                begins.].                             Sections 7.4, 9.5,
                                                                                9.7, and 10.6, and
                                                                                Appendices B.2,
                                                                                and D.2, and all
                                                                                of Appendix A.4,
                                                                                because EPA
                                                                                disapproved the
                                                                                NOX BART
                                                                                determination for
                                                                                Coal Creek Station
                                                                                Units 1 and 2, the
                                                                                reasonable
                                                                                progress
                                                                                determination for
                                                                                Antelope Valley
                                                                                Station Units 1
                                                                                and 2 regarding
                                                                                NOX controls, the
                                                                                reasonable
                                                                                progress goals,
                                                                                and parts of the
                                                                                long-term
                                                                                strategy, and
                                                                                because the
                                                                                provisions
                                                                                applicable to
                                                                                Coyote Station
                                                                                were superseded by
                                                                                a later submittal.
(24) North Dakota State            Statewide...........  Submitted: 7/27/10..................  4/6/12, [Insert Federal Register
 Implementation Plan for Regional                                                               page number where the document
 Haze Supplement No. 1.                                                                         begins.].
(25) North Dakota State            Statewide...........  Submitted: 7/28/11..................  4/6/12, [Insert Federal Register      Including only
 Implementation Plan for Regional                                                               page number where the document        Section <IP_ADDRESS>,