Coronado Generating Station consists of two EGUs with a total
plant-wide generating capacity of over 800 MW. Units 1 and 2 are both
dry-bottom, turbo-fired boilers, each with a gross unit output of 411
MW. Both units are BART-eligible and are coal-fired boilers operating
on primarily Powder River Basin sub-bituminous coal.
    SRP entered into a consent decree with EPA in 2008.\63\ This
consent decree resolved alleged violations of the CAA which occurred at
Units 1 and 2 of the Coronado Generating Station, arising from the
construction of modifications without obtaining appropriate permits
under the Prevention of Significant Deterioration provisions of the
CAA, and without installing and applying best available control
technology. The consent decree resolved the claims alleged by EPA in
exchange for SRP's payment of a civil penalty and SRP's commitment to
perform injunctive relief including: (1) Installation of pollution
control technology to control emissions of NOX,
SO2, and PM--including flue gas desulfurization devices to
control SO2 on Units 1 and 2 at the Coronado Station and
installation of SCR to control NOX on one of the units (Unit
2); (2) meet specified emission rates or removal efficiencies for
NOX, SO2, and PM; (3) comply with a plant-wide
emissions cap for NOX; and (4) perform $ 4 million worth of
mitigation projects. The consent decree is not a permit, and compliance
with the consent decree does not guarantee compliance with all
applicable federal, state, or local laws or regulations. The emission
rates and

removal efficiencies set forth in the consent decree do not relieve SRP
from any obligation to comply with other state and federal requirements
under the CAA, including SRP's obligation to satisfy any State modeling
requirements set forth in the Arizona SIP.
---------------------------------------------------------------------------

    \63\ See Docket Item G-01, Consent Decree between United States
and Salt River Project Agricultural Improvement and Power District.
---------------------------------------------------------------------------

a. BART for NOX
    ADEQ's Analysis: ADEQ's BART analysis relied in large part on an
analysis submitted by SRP in February 2008. In its analysis, SRP
developed baseline NOX emissions by examining continuous
emission monitoring system (CEMS) data from 2001 to 2003.\64\ SRP
examined several NOX control technologies, including
combustion controls and add-on post combustion controls. A summary of
the costs of compliance and visibility impacts associated with these
options is presented in Table 13. This information was contained in the
SRP Coronado BART analysis, and was relied on by ADEQ in developing its
RH SIP. Estimates of control technology emission rates were developed
based on information provided by equipment vendors.\65\ SRP's analysis
did not provide an estimate of annual emissions.
---------------------------------------------------------------------------

    \64\ See Docket Item B-10, SRP Coronado BART Analysis, page 3-1.
    \65\ See Docket Item B-10, SRP Coronado BART Analysis, p. 4-5.

                                                         Table 13--Coronado Units 1 and 2: Arizona's Cost and Visibility Summary for NOX
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Emission rate  (lb/                           Cost-effectiveness \b\        Visibility                         Improvement in
                                                                     MMBtu)                                          ($/ton)             improvement \c\                   visibility index \e\
                                                            ------------------------   Total       Total    ------------------------       (deciviews)         Cost per         (deciviews)
                                                                                emissions   annualized                         ------------------------    total    -----------------------
                       Control option                                                 removed     cost ($/              Incremental                            deciview     Total
                                                               Unit 1      Unit 2    \a\ (tons/    year)      Average      (from       Total    Incremental  improvement    (from    Incremental
                                                                                yr)                              previous)     (from       (from      \d\ ($/dv)     base       (from
                                                                                baseline)   previous)                  case)     previous)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline).............................................       0.433       0.466  .........  ...........  .........  ...........  .........  ...........  ...........  .........  ...........
Full LNB + OFA.............................................       0.32        0.32       5,838   $1,227,000       $210  ...........       0.12  ...........  $10,225,000       0.11  ...........
Full SNCR + LNB + OFA......................................       0.22        0.22      10,195    4,654,000        456         787        0.16        0.04    29,087,500       0.19       0.080
Partial SCR + LNB + OFA \f\................................       0.32        0.08      11,003    8,557,000        778       4,830        0.24        0.12    35,654,167       0.22       0.030
Full SCR + LNB + SOFA......................................       0.08        0.08      16,730   17,090,000      1,022       1,490        0.39        0.27    43,820,513       0.34       0.120
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ SRP did not provide estimates of annual emissions in its BART analysis. These values are summarized from the Arizona RH SIP.
\b\ Cost-effectiveness was not presented in the Arizona RH SIP. These values are calculated from the emission removal and annualized costs that were included in the RH SIP.
\c\ Visibility improvement at the Class I area exhibiting the greatest baseline visibility impact, Petrified Forest National Park, from the SRP Coronado BART Analysis.
\d\ Cost per total deciview improvement was not presented in the Arizona RH SIP. These values are calculated from the annualized costs that were included in the RH SIP, and the visibility
  improvement at Petrified Forest National Park, from the SRP Coronado BART Analysis.
\e\ Visibility index used in the Arizona RH SIP is the average of the impacts over the nine closest Class I areas.
\f\ This control option examined LNB+OFA on Unit 1 and SCR on Unit 2.

    Control costs for the various options considered were developed by
Sargent and Lundy, the engineering firm retained by SRP for emission
control projects at Coronado. In its BART analysis and subsequent
additional response to ADEQ, SRP provided summaries of total control
costs, such as total annual operating and maintenance costs and total
annualized capital cost, but did not provide cost information at a
level of detail that included line item costs. \66\
---------------------------------------------------------------------------

    \66\ See Docket Item B-11, Additional SRP Coronado response.
---------------------------------------------------------------------------

    As part of its BART analysis, SRP performed visibility modeling in
order to evaluate the visibility improvement attributable to each of
the NOX control technologies that it considered. This
visibility modeling was performed using three years of meteorological
data (2001 to 2003), and relied partially on the WRAP protocol with
certain revisions based on EPA and Federal Land Manager guidance that
became available in the intervening period. For example, the WRAP
protocol used CALPUFF model version 6, whereas SRP used the current
EPA-approved CALPUFF version 5.8.
    For assessing the degree of visibility improvement, ADEQ considered
a visibility index, defined as the average of the visibility benefits
at the closest nine Class I areas. The average included the five areas
with the highest baseline impacts. This metric is unlike that used for
Apache and Cholla, for which the benefits at the single area with
maximum baseline impact were used. Since it is an average, it is
somewhat similar to the sum of benefits over the nine areas, a
cumulative metric used in other analyses, except it is divided by nine
to compute the average. (Typically the sum would be computed over all
17 Class I areas impacted by the Coronado facility.) For each control,
ADEQ listed the average visibility improvement in deciviews, and cost
in millions of dollars per average deciview improvement.\67\
Improvements in the visibility index ranged from 0.11 dv for LNB with
OFA to 0.34 dv for SCR. Costs per deciview for the index ranged from
$11.1 million for LNB to $50.3 million for SCR (not shown in the Table
above).
---------------------------------------------------------------------------

    \67\ Arizona RH SIP, Appendix D, p. 112.
---------------------------------------------------------------------------

    While an average of the visibility benefits over the nearest areas
is an informative number, it is not directly comparable to the more
typical metrics of the maximum benefit seen at any area, and sum over
the areas. Moreover, neither the ADEQ RH SIP nor the facility's report
(BART Analysis for the Coronado Generating Station Units 1 & 2,
Document No. 05830-012-200, ENSR Corporation, February 2008) include
control benefits for individual Class I areas. Thus, the maximum area
benefit cannot be read from either document. However, the benefits can
be computed from the individual area impacts that are provided in SRP's
report, including for Petrified Forest National Park, which had the
highest baseline impact. Figures that are comparable to those for
Apache and Cholla are included in the Table 13. Coronado's maximum area
visibility benefits range from 0.12 dv for LNB to 0.39 dv for SCR. The
costs per deciview range from $10.2 million for LNB with OFA to $43.8
for SCR.
    In evaluating SRP's BART analysis, ADEQ requested additional
supporting information from SRP regarding control cost calculations,
and for further explanation regarding SRP's recommendation for BART for
NOX. In developing its Regional Haze SIP, ADEQ

determined that LNB with OFA constitutes BART for NOX at
Coronado Units 1 and 2. In making this determination, ADEQ did not
provide adequate information regarding its rationale or weighing of the
five factors, stating only ``[a]fter reviewing the BART analysis
provided by the company, and based upon the information above, ADEQ has
determined that BART for NOX at Coronado Units 1 and 2 is
advanced combustion controls (Low NOX burners with OFA) with
an associated NOX emission rate of 0.32 lb/MMBtu [..]'' \68\
---------------------------------------------------------------------------

    \68\ Docket Item B-01, Arizona Regional Haze SIP, Appendix D,
Page 112.
---------------------------------------------------------------------------

    EPA's Evaluation: We disagree with several aspects of the BART
analysis for Coronado Units 1 and 2. Regarding the control cost
calculations, we note that SRP did not provide ADEQ with control cost
calculations at a level of detail that allowed for a comprehensive
review. Without such a level of review, we do not believe that ADEQ was
able to evaluate whether SRP's control costs were reasonable. As a
result, we are proposing to find that ADEQ did not follow the
requirements of section 51.308(e)(1)(ii)(A) because ADEQ did not
properly consider the costs of compliance for each control option.
    The modeling procedures relied on by ADEQ for assessing the
visibility impacts from Coronado were generally in accord with EPA
guidance. Coronado Units 1 and 2 were modeled together, and the
modeling was done with the current regulatory version 5.8 of the
CALPUFF modeling system.\69\ However, the use of the modeling results
in evaluating the BART visibility factor was problematic. The modeling
results show that, of the controls considered, only SCR would provide
substantial visibility benefits; the other controls options would
provide roughly half the 0.5 dv contribution benchmark. ADEQ did not
consider the typical visibility metrics of benefit at the area with
maximum impact, nor benefits summed over the areas. Using the default 1
ppb ammonia background concentration would also have increased
estimated impacts and control benefits. For these reasons, EPA proposes
to find that the ADEQ selection of LNB with OFA for Coronado under the
degree of visibility improvement BART factor is not adequately
supported, and that more stringent control may be warranted. ADEQ
provided little reasoning about the visibility basis for the Coronado
BART selection. For example, there is no weighing of the visibility
benefits and visibility cost-effectiveness for the various candidate
controls and the various Class I areas.
---------------------------------------------------------------------------

    \69\ Arizona Regional Haze SIP, Appendix D, p. 112.
---------------------------------------------------------------------------

    In addition to the problems noted above, we find that overall ADEQ
has not documented its evaluation of the results of its five-factor
analysis, as required by 51.308(e)(1)(ii)(A) and the BART Guidelines.
Although ADEQ has developed information regarding each of the five
factors, its selection of BART does not cite or interpret information
from its analyses. ADEQ does not, for example, indicate whether or not
it considered any cost thresholds to be reasonable or expensive in
analyzing the costs of compliance for the various control options. We
note that ADEQ has made similar NOX BART determinations of
LNB with OFA at other facilities, such as Cholla Power Plant. Although
ADEQ's BART determinations for these other facilities implied that cost
of compliance was an important consideration, it does not provide a
rationale for the determination of NOX BART at Coronado.\70\
Therefore, we propose to determine that ADEQ did not follow the
requirements of section 51.308(e)(1)(ii)(A). We propose to disapprove
ADEQ's selection of LNB with OFA as BART for NOX at Coronado
Units 1 and 2.
---------------------------------------------------------------------------

    \70\ We do note, however, that SRP does provide some additional
analysis on this position in the BART analysis it submitted to ADEQ
and in the responses it provided to ADEQ's additional questions.
Aside from stating that it reviewed SRP's analysis, ADEQ did not
specifically reference or include any aspects of SRP's analysis in
the RH SIP. As a result, we are not assuming that ADEQ necessarily
agrees with SRP's rationale, and have therefore not provided an
analysis of it.
---------------------------------------------------------------------------

b. BART for PM10
    Emissions of PM10 from Coronado Units 1 and 2 are
currently controlled by hot-side ESPs.\71\ Under the terms of the
Consent Decree described above in Section 4, SRP is required to
optimize its ESPs to achieve a PM10 emission rate of 0.030
lb/MMBtu.\72\
---------------------------------------------------------------------------

    \71\ See Arizona Regional Haze SIP, Appendix D, p. 112 for
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2;
and BART Analysis for Coronado Generating Station Units 1 and 2
(February 2008) for SRP's analysis.
    \72\ Docket Item G-01, Consent Decree between United States and
Salt River Project Agricultural Improvement and Power District,
Sec.  V.
---------------------------------------------------------------------------

    ADEQ's Analysis: ADEQ conducted a streamlined PM10 BART
analysis for Coronado Units 1 and 2. In particular, ADEQ found that
``BART for similar emissions units with similar emissions controls was
determined to be 0.03 lb/MMBtu.'' ADEQ concluded that because Coronado
Units 1 and 2 are already meeting a limit of 0.03 lb/MMBtu, ``further
analysis was determined to be unnecessary.''
    EPA's Evaluation: ADEQ's analysis does not demonstrate that all
potential upgrades to the existing ESPs were fully evaluated. However,
we have no evidence that additional reductions in PM10
emissions would be achievable or cost-effective, or that such
reductions would yield substantial visibility benefits. Therefore, we
propose to approve ADEQ's PM10 BART determination at
Coronado. However, we are seeking comment on whether additional cost-
effective upgrades to the existing ESPs are available that would
warrant a lower emission limit. If we receive comments establishing
that a lower limit is achievable, then we may disapprove the
PM10 emissions limit set by ADEQ and promulgate a revised
limit for one or both of these units.
    Finally, we are seeking comment on whether test methods other than
EPA Method 201 and 202 \73\ (chosen by ADEQ) should be allowed or
required for establishing compliance with the PM10 limits
that we are approving. In particular, as explained below, use of SCR at
these units is expected to result in increased condensable particulate
matter in the form of H2SO4. In effect, the
emission limit would be more stringent than intended by ADEQ and would
likely not be achievable in practice. In order to avoid this result,
while still assuring proper operation of the particulate control
devices, we are requesting on comment on whether to allow compliance
with the PM10 limit to be demonstrated using test methods
that do not capture condensable particulate matter, namely EPA Methods
1 through 4 and Method 5 or Method 5e.\74\ Method 201 is very rarely
used for testing. The typical method used for filterable
PM10 is Method 201A, ``constant sampling rate procedure,''
which is similar to Method 201, but is much more practical to perform
on a stack.
---------------------------------------------------------------------------

    \73\ See 40 CFR part 51 appendix M.
    \74\ See 40 CFR part 60 appendix A.
---------------------------------------------------------------------------

c. BART for SO2
    Emissions of SO2 at Coronado Units 1 and 2 are currently
controlled with the use of low-sulfur coal and partial wet flue
gas.\75\ However, the consent decree between EPA and SRP described
above requires installation of wet flue gas desulfurization (WFGD)
systems at either Unit 1 or Unit 2 by January 2012, and at the
remaining unit by January 1, 2013. Both units must achieve and maintain
a 30-day rolling average SO2 removal efficiency of at least
95.0

percent or a 30-day rolling average SO2 emissions rate of no
greater than 0.080 lb/MMBtu.
---------------------------------------------------------------------------

    \75\ See Arizona Regional Haze SIP, Appendix D, pp. 113-15 for
ADEQ's BART Analysis for PM10 at Coronado Units 1 and 2;
and Docket No. B.10, BART Analysis for Coronado Generating Station
Units 1 and 2 (Feb. 2008) for SRP's analysis.
---------------------------------------------------------------------------

    ADEQ's Analysis: Because WFGD is the most effective control
technology available for controlling SO2 emissions, ADEQ did
not evaluate other control options. Table 14 summarizes Arizona's the
costs of compliance and improvement in visibility expected to result
from installation of WFGD at both units. Based on this information,
ADEQ determined SO2 BART for both units is the installation
of WFGDs and an emission rate of 0.08 lbs/MMBtu on 30-day rolling
average basis.

    Table 14--Coronado Units 1 and 2: Arizona's Bart Summary for SO2
------------------------------------------------------------------------
                                  Option 1, baseline    Option 2, WFGD
------------------------------------------------------------------------
Reduction in Emission (tpy).....  ..................              25,753
Annualized Cost.................  ..................         $44,353,330
Visibility Index (dv)...........                2.66                1.28
Improvement in Visibility Index   ..................                1.38
 (dv)...........................
Incremental Cost-effectiveness    ..................         $32,140,094
 ($ per dv).....................
------------------------------------------------------------------------

    EPA's Evaluation: We are proposing to approve ADEQ's SO2
BART determination for Coronado Units 1 and 2. Although we do not
necessarily agree with the underlying cost and visibility analyses
performed by SRP, we have no evidence that additional analysis would
have resulted in a lower emission limit. Therefore, we propose to
approve ADEQ's SO2 emission limit of 0.08 lb/MMBtu (30-day
rolling average) for Coronado Units 1 and 2. However, we are seeking
comment on whether a lower emission limit may be achievable when the
units are burning a lower-sulfur coal. If we receive comments
establishing that a lower limit is achievable, then we may disapprove
the SO2 emissions limit set by ADEQ and promulgate a revised
limit for one or both of these units.

 D. Enforceability of BART Limits

    Regional Haze SIPs must include requirements to ensure that BART
emission limits are enforceable. In particular, the RHR requires
inclusion of (1) A schedule for compliance with BART for each source
subject to BART; (2) a requirement for each BART source to maintain the
relevant control equipment; and (3) procedures to ensure control
equipment is properly operated and maintained.\76\ General SIP
requirements also mandate that the SIP include all regulatory
requirements related to monitoring, recordkeeping and reporting for the
BART emissions limitations.\77\ ADEQ did not include any of these
elements in its Regional Haze SIP.\78\ Therefore, we are proposing to
disapprove this aspect of the Regional Haze SIP for these three sources
and to promulgate a FIP to ensure the emission limits are enforceable.
---------------------------------------------------------------------------

    \76\ 40 CFR 51.308(e)(1).
    \77\ See, e.g. CAA section 110(a)(2) (F) and 40 CFR 51.212(c).
    \78\ As described above, ADEQ did specify a test method for
PM10 for each of the relevant sources (Method 201/202).
However, we are proposing to also allow the use of test methods that
do not capture condensable particulate matter, namely EPA Methods 1
through 4 and Method 5 or Method 5e.
---------------------------------------------------------------------------

VII. EPA's Proposed FIP Actions

A. EPA's BART Analyses and Determinations

    EPA conducted a new five-factor BART analysis of the three
facilities in order to evaluate Arizona's RH SIP, and to document the
technical basis for proposing BART determinations in our FIP. Because
EPA generally concurs with ADEQ's BART analyses in Steps 1 and 2
(Identify All Available Retrofit Control Technologies and Eliminate
Technically Infeasible Options), we focused our technical analysis on
Steps 3, 4 and 5 (Evaluate Control Effectiveness of Remaining Control
Technologies, Evaluate Impacts and Document Results, and Evaluate
Visibility Impacts). We relied on contractor assistance from the
University of North Carolina Institute for the Environment to evaluate
control effectiveness, perform cost calculations, and conduct new
visibility modeling for each of the units at the three facilities,
except Apache Generating Station Unit 1 for which this level of
analysis was unnecessary. Our approach to each of these factors is
explained below, followed by our BART determinations for the three
sources in the next section. Copies of the contractor's reports and the
details of our BART analyses are in our Technical Support Document
(TSD) available in the docket.
 1. Costs of Compliance
    Cost Estimates and Calculations: In estimating the costs of
compliance, we have relied on facility data from a number of sources
including ADEQ, the Energy Information Administration (EIA), and EPA's
Control Cost Manual. As discussed previously, ADEQ, in developing its
RH SIP, requested certain clarifying information from the facilities
regarding their control cost calculations, including greater detail
regarding the underlying assumptions. ADEQ received responses of
varying detail to these requests. Although in some cases the facilities
provided summaries of certain broad line item costs, in no case does
the supporting information that is available provide detail at a level
that allows for critical review. In the case of SRP Coronado Generating
Station, ADEQ received only a broad summary of control costs without
itemized breakdowns of specific costs.
    As a result, we have used EPA's Integrated Planning Model (IPM) to
calculate the capital costs and annual operating costs associated with
the various NOX control options. EPA's Clean Air Markets
Division (CAMD) uses IPM to evaluate the cost and emissions impacts of
proposed policies to limit emissions of SO2, NOX,
carbon dioxide (CO2), and mercury (Hg) from the electric
power sector. Developed by ICF Consulting, Inc. and used to support
public and private sector clients, IPM is a multi-regional, dynamic,
deterministic linear programming model of the U.S. electric power
sector. EPA has used IPM in rulemakings such as the Mercury and Air
Toxics Standard and the Cross-State Air Pollution Rule. For the
purposes of this BART determination, we specifically used only the
NOX emission control technology cost methodologies contained
in EPA's IPM Base Case v4.10 (August 2010).\79\ For Base Case v4.10,
EPA's Clean Air Markets Division contracted with engineering firm
Sargent and Lundy to perform a complete bottom-up engineering
reassessment of the cost and performance assumptions for SO2
and nitrogen oxides NOX emission controls. Summaries of our
control cost estimates for the various control technology options
considered for each unit are included below. Detailed cost

calculations, including our contractor's report and cost calculation
spreadsheets, are in the Technical Support Document.
---------------------------------------------------------------------------

    \79\ http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

    We used publicly available information to estimate that AEPCO is a
small utility. EPA requested information from AEPCO on the economics of
operating Apache Generating Station and what impact the installation of
SCR may have on the economics of operating Apache Generating Station.
Specifically, EPA is seeking information on the ability of AEPCO to
recover the cost of pollution control technology through rate increases
and the impact those rate increases may have on AEPCO's customers. If
we receive comments sufficiently documenting that installation of SCR
may have a severe impact on the economics of operating Apache
Generating Station, we may incorporate such considerations in our
selection of BART. Our impact analysis and request for comment is
discussed in more detail below, under EPA's BART Determinations for
Apache Units 2 and 3.
    Control Effectiveness: The evaluation of control effectiveness is
an important part of a five-factor analysis because it influences both
cost-effectiveness and visibility benefits. The BART Guidelines note
that for each technically feasible control option:

    ``It is important * * * that in analyzing the technology you
take into account the most stringent emission control level that the
technology is capable of achieving. You should consider recent
regulatory decisions and performance data (e.g., manufacturer's
data, engineering estimates and the experience of other sources)
when identifying an emissions performance level or levels to
evaluate.'' \80\
---------------------------------------------------------------------------

    \80\ 40 CFR part 51, appendix Y Sec.  IV.D.3.

In general, our estimates of LNB and SNCR control effectiveness differ
slightly from the control effectiveness levels considered by ADEQ. In
the case of LNB, for example, this is the result of the fact that
actual emissions data for LNB performance were available for certain
units at the time of our analysis. ADEQ's analysis was performed at an
earlier date when these emissions data were not available. More
detailed information regarding these differences is in our discussion
of individual facilities in the following sections of this notice, as
well as in our TSD.
    In particular, we find that ADEQ did not adequately support its
estimate of SCR control effectiveness. SCR, as an add-on control
technology, can be installed by itself as a standalone option or in
conjunction with burner upgrades. In cases where units can be upgraded
with combustion control technology such as low-NOx burners, SCR is
commonly installed as an add-on post-combustion control. When
evaluating control options with a range of emission performance levels,
the BART Guidelines indicate that ``in analyzing the technology you
take into account the most stringent emission control level that the
technology is capable of achieving.'' \81\ Existing vendor literature
and technical studies indicate that SCR systems are capable of
achieving a 0.05 lb/MMBtu emission rate (approximately 80-90% control
efficiency) and that this emission rate can be achieved on a retrofit
basis, particularly when combined with combustion control technology
such as LNB.\82\
---------------------------------------------------------------------------

    \81\ 70 FR 39166.
    \82\ See Docket Items G-04, ``Emissions Control: Cost-Effective
Layered Technology for Ultra-Low NOX Control'' (2007),
Docket Item G-05 ``What's New in SCRs'' (2006), and Docket Item G-06
``Nitrogen Oxides Emission Control Options for Coal-Fired Electric
Utility Boilers'' (2005).
---------------------------------------------------------------------------

    For control options involving the installation SCR in conjunction
with LNB, ADEQ considered the achievable emission rate to be between
0.07 lb/MMbtu (for Apache and Cholla) and 0.08 lb/MMbtu (for Coronado).
These emission rates are within a range of SCR performance that has
been considered by other western states in preparing RH SIPs, and may
possibly be an appropriate estimation of the site-specific level of SCR
performance for coal-fired units at Apache, Cholla, and Coronado. We
note that the BART Guidelines indicate that, ``In assessing the
capability of the control alternative, latitude exists to consider
special circumstances pertinent to the specific source under review [*
* *]. However, you should explain the basis for choosing the alternate
level (or range) of control in the BART analysis.'' \83\ Although the
alternate levels of emission control considered by ADEQ for SCR in
conjunction with LNB were stated in each respective facility's BART
analysis, these emission rates were not further supported by any
calculations, engineering analysis, or documentation. We do not believe
that AEPCO, APS, and SRP have provided adequate supporting analysis to
justify these emission rates. We are seeking comment on whether it is
appropriate to consider an emission rate less stringent than 0.05 lb/
MMBtu when evaluating the installation SCR in conjunction with LNB at
Apache, Cholla, and Coronado.
---------------------------------------------------------------------------

    \83\ 40 CFR part 51, appendix Y Sec.  IV.D.3.
---------------------------------------------------------------------------

    In the absence of source-specific considerations warranting a less
stringent control level, we presume that an emissions limit of 0.05 lb/
MMBtu is achievable by these units through the use of SCR in addition
to advanced combustion controls. We have recently received information
from AEPCO and SRP regarding potential NOX controls at their
facilities. This information arrived too late to be fully evaluated for
this proposed rulemaking, and EPA will need additional documentation
from the utilities to support the information that they have provided
to date. We have put the utility information in the docket for public
review, and we will evaluate the information, and any additional
information that the utilities may want to provide prior to making our
final BART determinations.\84\ If we receive additional comments that
sufficiently document source-specific considerations justifying the use
of an emission rate less stringent than 0.05 lb/MMBtu, we may
incorporate such considerations in our selection of BART.
---------------------------------------------------------------------------

    \84\ Docket Items C-15 ``Letter from Kelly Barr (SRP) to Deborah
Jordan (EPA)'' and C-16 ``Letter from Michelle Freeark (AEPCO) to
Deborah Jordan (EPA).''
---------------------------------------------------------------------------

 2. Energy and Non-Air Environmental Impacts
    Energy Impacts: With respect to the potential energy impacts of the
BART control options, we note that SCR incurs a draft loss that will
increase parasitic loads, and that other emissions controls may also
have modest energy impacts. The costs for direct energy impacts, i.e.,
power consumption from the control equipment and additional draft
system fans from each control technology, are included in the cost
analyses and are not considered further in this section. Indirect
energy impacts, such as the energy to produce raw materials, are not
considered, consistent with the BART guidelines.
    Ammonia Adsorption: Ammonia adsorption (resulting from ammonia
injection from SCR or selective non-catalytic reduction--SNCR) to fly
ash is generally not desirable due to odor but does not impact the
integrity of the use of fly ash in concrete. However, other
NOX control technologies, including LNB, also have
undesirable impacts on fly ash. LNBs increase the amount of unburned
carbon in the fly ash, also known as Loss of Ignition (LOI), which does
affect the integrity of the concrete. Commercial scale technologies
exist to remove ammonia and LOI from fly ash. Moreover, the impact of
SCR on fly ash is smaller than the impact of LNB on fly ash, and in
both cases, the adverse effects can be mitigated.\85\ We conclude

that the ability of the relevant facilities to sell fly ash is unlikely
to be affected by the installation of SCR and SNCR technologies.
---------------------------------------------------------------------------

    \85\ ``Impact of Ammonia in Fly Ash on its Beneficial Use,''
Memorandum from Nancy Jones and Stephen Edgerton, EC/R Incorporated,
to Anita Lee, U.S. EPA/Region 9, August 31, 2010. Also see the TSD
for further discussion.
---------------------------------------------------------------------------

    Safety: SCR and SNCR may involve potential safety hazards
associated with the transportation and handling of anhydrous ammonia.
Since each of the relevant facilities is served by a nearby railroad
line, EPA concludes that the use of ammonia does not pose any
additional safety concern as long as established safety procedures are
followed.
    Thus, EPA proposes to find that potential energy and non-air
quality impacts do not warrant elimination of any of the otherwise
feasible control options for NOX at any of the sources.
3. Pollution Control Equipment in Use at the Source
    The presence of existing pollution control technology at each
source is reflected in our BART analysis in two ways: First, in the
consideration of available control technologies, and second, in the
development of baseline emission rates for use in cost calculations and
visibility modeling. As noted above, we largely agree with ADEQ's
consideration of available control technologies. However, because
several of the affected units have had new controls installed in the
last several years, we have adjusted the baseline emissions periods to
reflect current control technology at the sources, as described further
below in our proposed BART determinations.
 4. Remaining Useful Life of the Source
    We are considering each source's ``remaining useful life'' as one
element of the overall cost analysis as allowed by the BART Guidelines.
Since we are not aware of any federally- or State-enforceable shut-down
date for any of the affected sources, we have used the default 20-year
amortization period in the EPA Cost Control Manual as the remaining
useful life of the facilities considered in this proposed action.
 5. Degree of Improvement in Visibility
    EPA estimated the degree of visibility improvement expected from a
BART control based on the difference between baseline visibility
impacts prior to controls and visibility impacts with controls in
operation. EPA used the CALPUFF model version 5.8 \86\ to determine the
baseline and post-control visibility impacts for all three facilities.
EPA followed the modeling approach recommended in the BART Guidelines.
We developed a modeling protocol, used maximum daily emissions as a
baseline, applied estimated percent reductions for alternative control
technologies, and used the CALPUFF model to estimate visibility impacts
at Class I areas within 300 kilometers.
---------------------------------------------------------------------------

    \86\ EPA relied on version 5.8 of CALPUFF because it is the EPA-
approved version promulgated in the Guideline on Air Quality Models
(40 CFR part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15,
2003. It was also the approved version when EPA promulgated the BART
Guidelines (70 FR 39122, July 6, 2005). EPA updated the specific
version to be used for regulatory purposes on June 29, 2007,
including minor revisions as of that date; the approved CALPUFF
modeling system includes CALPUFF version 5.8, level 070623, and
CALMET version 5.8 level 070623. At this time, any other version of
the CALPUFF modeling system would be considered an ``alternative
model'', subject to the provisions of Guideline on Air Quality
Models section 3.2.2(b), requiring a full theoretical and
performance evaluation.
---------------------------------------------------------------------------

a. Modeling Protocol
    A modeling protocol was developed by our contractor \87\ at the
University of North Carolina that is based largely on the WRAP
protocol,\88\ although there are a few differences between our protocol
and that of the WRAP. Both protocols used meteorological inputs for
2001, 2002, and 2003 based on the Mesoscale Model version 5 (MM5). EPA
meteorological inputs differed from the WRAP's in that the WRAP
incorporated upper air data, as recommended by the Federal Land
Managers, and also values for some parameters that enabled smoother and
more realistic wind fields. These CALMET inputs were developed by the
ENSR corporation for modeling of emissions at the Navajo Generating
Station.\89\ Another key difference was EPA's use of the current
regulatory version of the CALPUFF modeling system, version 5.8.
Facility stack parameters, such as stack height and exit temperature,
were generally the same as those provided by WRAP member states to the
WRAP, except that in some cases updated parameters were provided by the
facilities at EPA's request.
---------------------------------------------------------------------------

    \87\ Technical Analysis for Arizona Regional Haze FIPs: Modeling
Protocol for Subject-to-BART and BART Control Options Analyses, EP-
D-07-102 WA5-12 Task 5, Institute for the Environment, University of
North Carolina at Chapel Hill, March 14, 2012
    \88\ CALMET/CALPUFF Protocol for BART Exemption Screening
Analysis for Class I Areas in the Western United States, Western
Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph
Morris, Abby Hoats and Yiqin Jia, August 15, 2006. Available on UCR
Regional Modeling Center web site, BART CALPUFF Modeling, http://pah.cert.ucr.edu/aqm/308/bart.shtml.
    \89\ Revised BART Analysis for the Navajo Generating Station
Units 1-3, ENSR Corporation, Document No. 05830-012-300, January
2009, Salt River Project--Navajo Generating Station, Tempe, AZ.
---------------------------------------------------------------------------

    We performed separate CALPUFF modeling runs using baseline
emissions, and using the emissions remaining after each candidate
control technology was applied to the baseline. For baseline PM
emissions, EPA used the WRAP's estimates. However, following procedures
developed by the National Park Service,\90\ EPA divided those emissions
into separate chemical species, and into separate coarse and fine
particle fractions, to reflect better their varying visibility impacts.
---------------------------------------------------------------------------

    \90\ ``Particulate Matter Speciation'', National Park Service,
2006. http://www.nature.nps.gov/air/Permits/ect/index.cfm.
---------------------------------------------------------------------------

    Although costs and emission reductions for each candidate BART
control technology must necessarily be calculated separately for each
emitting unit of a facility, emissions from all the units will be
emitted into the air simultaneously. EPA modeled all units (stacks) and
pollutants simultaneously. That is, even though only NOX
BART alternatives were evaluated, SO2 and PM10
emissions were also included in the modeling. Modeling all emissions
from all the units accounts for the chemical interaction between
multiple plumes, and between the plumes and the background
concentrations. This also accounts for the facts that deciview benefits
from individual units are not additive, and that each EPA BART proposal
is for the facility as a whole.
b. Baseline Emissions
    Baseline NOX and SO2 emissions for the
facilities were generally based on the maximum daily emissions from
recent data in EPA's CAMD database, with data examined for 2008 to
2011. The CAMD data derive from Continuous Emissions Monitoring in
place at the facilities, and give the actual emissions that occurred.
However, in cases where EPA is proposing to approve the BART emissions
limits submitted by ADEQ, EPA used emission rates based on those
limits, in lb/MMBtu, in combination with the maximum daily heat rate in
MMBtu/hour from the CAMD data. The baseline emissions used by EPA
reflect current fuels and control technologies in place at the
facilities, as well as regulatory requirements the facilities will be
required to meet independent of EPA's BART determination. This results
in a more realistic estimate of current visibility impacts, and of the
improvements that one would expect to result from implementation of
EPA's proposed BART controls.

c. Emission Reductions for Alternative Controls
    For the CALPUFF modeling to assess visibility after application of
a control technology, the percent control expected from the technology
was applied to the baseline maximum daily emissions just described, as
recommended in the BART Guidelines. As discussed elsewhere, LNB and
SNCR each were assumed to reduce NOX by 30 percent, and SCR
was assumed to reduce NOX by 90 percent. However, for SCR,
we used a lower bound of 0.05 lb/MMBtu NOX, an emission rate
that we have confidence is achievable, as discussed above under
``Control Effectiveness''. The percent reduction actually applied to
the maximum daily emissions was whatever was required to reduce the
CAMD annual average emission factor down to this 0.05 lb/MMBtu
NOX. For the various emitting units at the facilities, this
ranged from 80 to 89 percent, instead of a full 90 percent reduction.
Finally, in modeling the visibility impact of SCR, EPA accounted for
the increased sulfuric acid emissions that occur when the SCR catalyst
oxidizes SO2 present in the flue gas, using an estimation
procedure developed by the Electric Power Research Institute\91\.
(Estimating Total Sulfuric Acid Emissions from Stationary Power Plants,
Version 2010a, 1020636, Technical Update, Electric Power Research
Institute, April 2010) This side effect of SCR's NOX
reduction increases sulfate emissions and decreases the visibility
benefits of SCR by around 5 percent.
---------------------------------------------------------------------------

    \91\ Estimating Total Sulfuric Acid Emissions from Stationary
Power Plants, Version 2010a, 1020636, Technical Update, Electric
Power Research Institute, April 2010.
---------------------------------------------------------------------------

d. Visibility Impacts
    CALPUFF Modeling: EPA followed the BART Guidelines in assessing
visibility impacts. For each Class I area within 300 km of a facility,
the CALPUFF model is used to simulate the baseline visibility impact of
each facility and the impacts resulting after alternative controls are
applied. However, certain aspects of assessing visibility with CALPUFF
are not fully addressed in the Guidelines. These aspects include which
``98th percentile'' from the model to use, the visibility calculation
method (old vs. revised IMPROVE equation), and natural background
concentrations (annual average versus best 20 percent of days).
    As recommended in the BART Guidelines, the 98th percentile daily
impact in deciviews is used as the basic metric of visibility impact.
(For a given Class I area, and for each modeled day, the model finds
the maximum impact. From among the 365 maximum daily values, the 98th
percentile is chosen, that is, the 8th highest.) Since multiple years
of meteorology are modeled, there are at least three ways to use the
model results: The maximum from among the 98th percentiles for the
individual years 2001, 2002, and 2003 (``maximum''); the average of
these three (``average''), or a single 98th percentile computed from
all three years of data together (``merged'', the 22nd high among 1095
daily values). The average and merged values are both unbiased
estimates of the true 98th percentile; for this proposal EPA has used
the merged value. The more conservative maximum value would be
appropriate for a screening purpose, such as for determining whether a
source is subject to BART.
    Visibility Calculation Method: The visibility calculation method
relied on by EPA differed from that used by ADEQ. Visibility impacts
may be simulated with CALPUFF using either the old or the revised
IMPROVE equation for translating pollutant concentrations into
deciviews; these are respectively CALPUFF visibility methods 6 and 8
(implemented in the CALPOST post-processor). Many BART assessments were
performed before method 8 was incorporated into CALPUFF, so method 6
was generally for past assessments. However, in this proposal EPA is
primarily relying on method 8. Method 8 is currently preferred by the
Federal Land Managers; since the revised IMPROVE equation performs
better at estimating visibility.\92\ For the facilities examined in
this proposal, baseline impacts using method 6 would average about 10
percent higher than those using method 8 (with a range of 3 percent
lower to 22 percent higher depending on facility and Class I area; the
effect for areas showing the largest benefit from control was similar
to the average).
---------------------------------------------------------------------------

    \92\ Pitchford, Marc, 2006, ``New IMPROVE algorithm for
estimating light extinction approved for use'', The IMPROVE
Newsletter, Volume 14, Number 4, Air Resource Specialists, Inc.; Web
page: http://vista.cira.colostate.edu/improve/Publications/news_letters.htm.
---------------------------------------------------------------------------

    Another CALPUFF choice is whether to calculate visibility impacts
relative to annual average natural conditions, or relative to the best
20 percent of natural background days; these may be referred to as
``a'' and ``b''. For both ``a'' and ``b'', background concentrations
for each Class I area are available in a Federal Land Managers'
document.\93\ EPA Guidance allows for the use of either ``a'' or
``b.''94 95 Since the annual average has worse visibility
and higher deciviews than the best days do, a given facility impact
will be smaller relative to the average than it is relative to the best
days. That is, a facility's impact will stand out less under poorer
visibility conditions. Thus, modeled facility impacts and control
benefits appear smaller when ``a'' is used than when ``b'' is used. In
this proposal, EPA is relying on ``b'', best 20 percent, consistent
with initial EPA recommendations for BART assessments. For the
facilities examined in this proposal, baseline impacts would average
about 20 percent lower using background ``a'' than those using
background ``b'' (with a range of 18 percent to 28 percent lower
depending on facility and Class I area; the effect for areas showing
the largest benefit from control was similar to the average).
---------------------------------------------------------------------------

    \93\ Federal Land Managers' Air Quality Related Values Work
Group (FLAG) Phase I Report--Revised (2010), U.S. Forest Service,
National Park Service, U.S. Fish and Wildlife Service, October 2010.
Available on Web page http://www.nature.nps.gov/air/Permits/flag/.
    \94\ BART Guidelines, 70 FR 39125, July 6, 2005. ``Finally,
these final BART guidelines use the natural visibility baseline for
the 20 percent best visibility days for comparison to the `cause or
contribute' applicability thresholds.''
    \95\ ``Regional Haze Regulations and Guidelines for Best
Available Retrofit Technology (BART) Determinations'', memorandum
from Joseph W. Paisie, EPA OAQPS, July 19, 2006, p.2.
---------------------------------------------------------------------------

    Considering visibility method and choice of background together,
the BART visibility assessments relied on by ADEQ used method ``6a'',
the old IMPROVE equation, and impacts relative to annual average
natural conditions. This is a valid approach, and is consistent with
EPA guidance.\96\ However, for this proposal, EPA considered all four
combinations of IMPROVE equation version and natural background: 6a,
6b, 8a, and 8b. EPA primarily relied on method ``8b'', that is, the
revised IMPROVE equation, and impacts relative to the best 20 percent
of natural background days. This is most consistent with our current
understanding of how best to assess source specific visibility impacts.
Combining the differences in visibility method and chosen background,
for the facilities examined in this proposal, baseline impacts would
average about 15 percent lower using method ``6a'' than those using
method ``8b'' (with a range of 3 percent to 37 percent lower depending
on facility and Class I area; the effect for areas showing the largest
benefit from control was similar to the average). Results for all the
various

visibility methods are available in the TSD.
---------------------------------------------------------------------------

    \96\ Additional Regional Haze Questions'', September 27, 2006
Revision, EPA OAQPS.
---------------------------------------------------------------------------

 B. EPA's FIP BART Determinations

 1. Apache Units 2 and 3
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is
described in VII.A.1., while issues unique to Apache Units 2 and 3 are
described herein. In particular, we highlight below certain aspects of
our analysis of this factor that differ from ADEQ's and AEPCO's
analysis.
i. Selection of Baseline Period
    AEPCO's BART analysis used a 2002 to 2007 time period in order to
establish its baseline NOX emissions. In our analysis, we
decided to make use of the most recent Acid Rain Program emission data
reported to CAMD, which, at the time that we began our analysis in
2011, was the three-year period from 2008 to 2010. Based on CAMD
documentation, no new control technology beyond the existing OFA system
has been installed on either Apache Unit 2 or 3. We consider the use of
this more recent baseline period to be a realistic depiction of
anticipated future emissions.\97\
---------------------------------------------------------------------------

    \97\ BART Guidelines, 40 CFR part 51, appendix P, Section
IV.D.4.d.
---------------------------------------------------------------------------

ii. SCR Control Efficiency
    In determining the control efficiency of SCR, we have relied upon
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent
than the level of performance used by ADEQ in its SIP. In the Apache
BART analyses submitted to ADEQ, AEPCO indicated an SCR level of
performance of 0.07 lb/MMBtu, but did not provide site-specific
information describing how this emission rate was developed or
discussing why a more stringent 0.05 lb/MMBtu level of performance
could not be attained. Our control cost calculations for the SCR and
LNB with OFA control options are based upon the control efficiency of
SCR (combined with LNB) summarized in Table 15.

                   Table 15--Apache 2 and 3: EPA's SCR (Combined With LNB) Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                Baseline                           SCR control
                           Unit                               emission rate     SCR emission       efficiency
                                                             \1\  (lb/MMBtu)        rate          (percentage)
----------------------------------------------------------------------------------------------------------------
Apache 2..................................................             0.371              0.05                87
Apache 3..................................................             0.438              0.05                89
----------------------------------------------------------------------------------------------------------------
\1\ This baseline emission rate represents operation of OFA only.

iii. Capacity Factor
    As noted previously, AEPCO calculated annual emission estimates for
its control scenarios, in tons per year, using annual capacity factors
developed internally over an unspecified time frame.\98\ The annual
capacity factors AEPCO used for each unit were 92 percent (Apache 2),
and 87 percent (Apache 3). We have also calculated annual emission
estimates for our control scenarios using capacity factors, but have
used information developed from CAMD information, and over a more
recent 2008 to 2011 time frame. The annual capacity factors we have
used for each unit are 62 percent (Apache 2), and 71 percent (Apache
3). We recognize that these capacity factors are lower than those used
by AEPCO, and that by using these lower capacity factors, our estimates
of total annual emissions (and correspondingly, the annual emission
reductions) for each control scenario are lower than AEPCO's
estimates.\99\ Since cost-effectiveness ($/ton) is calculated by
dividing annual control costs ($/year) by annual emission reductions
(tons/year), the use of emission reductions based on lower capacity
factors will increase the cost per ton of pollutant reduced.
---------------------------------------------------------------------------

    \98\ As listed in Table 2-1 in Docket Items B-03 and B-04,
Apache BART Analyses.
    \99\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than AEPCO's and ADEQ's estimates. We are not implying that the use
of capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Apache and
the other power plants that are the subject of today's proposed action.
iv. Summary of Control Cost Estimates
    A summary of our control cost estimates for the various control
technology options considered for Apache Units 2 and 3 is in Table 16.
Detailed cost calculations, including our contractor's report and cost
calculation spreadsheets, are available in our Technical Support
Document.

                                               Table 16--Apache Units 2 and 3: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Emission rate                                 Cost-effectiveness  ($/ton)
                                                             Emission   --------------------------  Emissions               ----------------------------
                      Control option                        factor (lb/                              removed    Annual cost                 Incremental
                                                              MMBtu)       (lb/hr)       (tpy)        (tpy)        ($/yr)        Ave           (from
                                                                                previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Apache 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)...........................................         0.371          859        2,333  ...........  ...........  ...........  ..............
LNB+OFA..................................................         0.26           601        1,633          700    1,142,120        1,632  ..............
SNCR+LNB+OFA.............................................         0.18           421        1,143        1,190    2,652,841        2,230           3,084
SCR+LNB+OFA..............................................         0.05           116          314        2,019    5,869,299        2,908           3,881
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                                        Apache 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA (baseline)...........................................         0.438          974        3,028  ...........  ...........  ...........  ..............
LNB+OFA..................................................         0.31           682        2,120          908    1,153,378        1,270  ..............
SNCR+LNB+OFA.............................................         0.22           477        1,484        1,544    2,968,611        1,922           2,854
SCR+LNB+OFA..............................................         0.05           111          346        2,683    6,103,078        2,275           2,754
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As seen in Table 16, our calculations indicate that the SCR-based
control options have average cost-effectiveness values of $2,275/ton to
$2,908/ton, which falls in a range that we consider cost-effective. In
addition, our calculations indicate that the SCR-based control options
have an incremental cost-effectiveness of $2,754/ton to $3,881/ton,
which is also in a range that we would consider cost-effective. As a
result, our analysis of this factor indicates that the costs of
compliance (average or incremental) are not sufficiently large to
warrant eliminating any of the control options from consideration.
b. Visibility Improvement
    The overall visibility modeling approach was described above;
aspects of the modeling specific to Apache are described here. EPA is
proposing a NOX BART determination only for Apache units 2
and 3, but Unit 1 was also included in the modeling runs for greater
realism in assessing the full facility's visibility impacts.\100\ For
Unit 1's NOX emissions, ADEQ's emission factor of 0.56 lb/
MMBtu was combined with the maximum MMBtu/hr heat rate from EPA's CAMD
database for 2008 to 2010. The baseline emissions used for these units
were the maximum daily emissions in lb/hr from 2008 to 2010; the maxima
occurred in early 2008. The base case reflects only OFA as the control
in place.
---------------------------------------------------------------------------

    \100\ Apache Unit 4, which consists of four simple-cycle gas
turbines, was not included in the modeling because its
NOX emissions are less than 1 percent of the emissions of
units 2 and 3, and are therefore expected to have a de minimis
effect on modeled visibility impacts.
---------------------------------------------------------------------------

    EPA evaluated LNB, SNCR (including LNB), and SCR (including LNB)
applied to both Units 2 and 3; as mentioned above the SCR simulation
accounted for the increase in sulfuric acid emissions due to catalyst
oxidation of SO2. SCR was assumed to give a control
effectiveness of 87 percent and 89 percent for Units 2 and 3,
respectively (less than 90 percent due to the 0.05 lb/MMBtu
NOX lower limit assumed for SCR). The nine Class I areas
within 300 km of Apache were modeled; they are in the states of Arizona
and New Mexico. The 98th percentile of delta deciviews over all three
years of data was computed for each area and emission scenario.
    Table 17 shows the impact for the base case, and the improvement
from that baseline impact when controls are applied, all in deciviews,
for each area. The Class I area types are National Monument (NM),
Wilderness Area (WA), and National Park (NP). Also shown are the
cumulative deciviews, the simple sum of impacts or improvements over
all the Class I areas, and the number of areas with a baseline impact
or improvement of at least 0.5 dv. Finally, the table includes two
``dollars per deciview'' measures of cost-effectiveness, both of which
take the annual cost of the control in millions of dollars per year,
and divide by an improvement in deciviews. For the first metric, ``$/
max dv'', cost is divided by the deciview improvement at the Class I
area with the greatest improvement. The second metric, ``$/cumulative
dv'', divides cost by the cumulative deciview improvement. In assessing
the degree of visibility improvement from controls, EPA relied heavily
on the maximum dv improvement and the number of areas showing
improvement, with cumulative improvement providing a supplemental
measure that combines information on the number of areas and on
individual area improvement. The dollars per deciview metrics provided
information supplemental to the dollars per ton that was considered in
the cost factor.
    In its comments on Arizona's proposed Regional Haze SIP, the
National Park Service noted that:

    Compared to the typical control cost analysis in which estimates
fall into the range of $2,000-$10,000 per ton of pollutant removed,
spending millions of dollars per deciview (dv) to improve visibility
may appear extraordinarily expensive. However, our compilation of
BART analyses across the U.S. reveals that the average cost per dv
proposed by either a state or a BART source is $14-$18 million.\101\

    \101\ Arizona Regional Haze SIP, Appendix E, Public Process, NPS
General BART Comments on ADEQ BART Analyses (November 29, 2010), p.
4.
---------------------------------------------------------------------------

While we do not necessarily consider $14 to $18 million/dv as being a
reasonable range in all cases, we note that for all of the
NOX control options, including SCR, both the $/max dv and
the $/cumulative dv are well below this range.
    The area with the greatest dv improvement was the Chiricahua
Wilderness Area; the improvement from LNB was 0.5 dv, from SNCR was 1
dv, and from SCR was 1.6 dv. Any of these improvements would contribute
to improved visibility, with SCR being the superior option for
visibility. The corresponding cumulative improvements are 2.1, 3.8, and
6.5. Both SNCR and SCR give improvements exceeding 0.5 dv at four
areas, but for SCR the improvements at those areas also exceed a full 1
dv. The improvements from SCR are substantially greater than for the
other candidate controls. The modeled degree of visibility improvement
supports SCR as BART for Apache.

                 Table 17--Apache Units 2 and 3: EPA'S Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                     Baseline       Improvement     Improvement     Improvement
                  Class I Area                      impact (dv)    from LNB (dv)  from SNCR (dv)   from SCR (dv)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM...................................            3.41            0.44            0.82            1.51
Chiricahua WA...................................            3.46            0.53            1.00            1.59
Galiuro WA......................................            2.22            0.39            0.65            1.10
Gila WA.........................................            0.63            0.14            0.22            0.37
Mazatzal WA.....................................            0.28            0.05            0.09            0.14
Mount Baldy WA..................................            0.28            0.07            0.11            0.18
Saguaro NP......................................            2.49            0.38            0.66            1.16
Sierra Ancha WA.................................            0.29            0.06            0.10            0.14
Superstition WA.................................            0.61            0.10            0.19            0.31
Cumulative dv...................................           13.67            2.14            3.83            6.51
 areas >=0.5...........................               6            1               4               4
$/max dv, millions..............................  ..............           $4.8            $6.0            $8.7
$/cumulative dv, millions.......................  ..............           $1.2            $1.6            $2.1
----------------------------------------------------------------------------------------------------------------

c. EPA's BART Determination
    In considering the results of the five-factor analysis, we note
that the remaining useful life of the source, as indicated previously
by the plant economic life of Apache Units 2 and 3, is incorporated
into control cost calculations as a 20-year amortization period. In
addition, the presence of existing pollution control technology is
reflected in the cost and visibility factors as a result of selection
of the baseline period for cost calculations and visibility modeling.
For Apache Units 2 and 3, a baseline period (2008 to 2010) was selected
that reflects the currently existing pollution control technology
(OFA). In examining energy and non-air quality impacts, we note certain
potential impacts resulting from the use of ammonia injection
associated with the SNCR and SCR control options, but do not consider
these impacts sufficient enough to warrant eliminating any of the
available control technologies.
    Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial. Our consideration of cost of compliance focuses
primarily on the cost-effectiveness of each control option, as measured
in cost per ton and incremental cost per ton of each control option.
Despite the fact that the most stringent option, SCR with LNB and OFA,
is the most expensive of the available control options, we consider it
cost-effective on an average basis as well as on an incremental basis
when compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be both cost-effective and to result
in substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, the results of our five-factor analysis
indicate that NOX BART for Apache Units 2 and 3 is SCR with
LNB and OFA.
    However, we note that the BART guidelines state that:

    Even if the control technology is cost-effective, there may be
cases where the installation of controls would affect the viability
of continued plant operations. [[hellip]]You may take into
consideration the conditions of the plant and the economic effects
of requiring the use of a control technology. Where these effects
are judged to have a severe impact on plant operations you may
consider them in the selection process, but you may wish to provide
an economic analysis that demonstrates, in sufficient detail for
public review, the specific economic effects, parameters, and
reasoning.'' \102\
---------------------------------------------------------------------------

    \102\ 70 FR 39171.

As explained in Section IX.C below, because AEPCO is a ``small
entity'', as defined under the Regulatory Flexibility Act, we have
conducted an initial assessment of the potential adverse impacts on
AEPCO of requiring SCR with LNB and OFA. Using publicly available
information, EPA estimates that the annualized cost of requiring SCR in
Units 1 and 2 would likely be in the range of 3 percent of AEPCO's
assets and between 6 and 7 percent of AEPCO's annual sales. The
projected costs of SCR with LNB and OFA are approximately $12 million
per year. This exceeds AEPCO's net margins of $9.5 million in 2010 and
$1.9 million in 2011.\103\
---------------------------------------------------------------------------

    \103\ See Docket Item H-1Arizona Electric Power Cooperative,
Inc. Annual Report Electric for Year Ending December 31, 2011
submitted to Arizona Corporation Commission Utilities Division,
available at http://www.azcc.gov/Divisions/Utilities/Annual%20Reports/2011/Electric/Arizona_Electric_Power_Cooperative_Inc.pdf.
---------------------------------------------------------------------------

    In addition to conducting this initial economic impact assessment,
we requested information from AEPCO on the economics of operating
Apache Generating Station and what impact the installation of SCR may
have on the economics of operating Apache Generating Station. We have
just received a description of plant conditions and potential economic
effects and are placing this information in the docket for this
action.\104\ We will consider this information and any additional
information received during the comment period as part of our final
action. If our analysis of this information indicates that installation
of SCR will have a severe impact on the economics of operating Apache
Generating Station, we will incorporate such considerations in our
selection of BART.
---------------------------------------------------------------------------

    \104\ Docket Item C-16, Letter from Michelle Freeark (AEPCO) to
Deborah Jordan (EPA), AEPCO's Comments on BART for Apache Generating
Station, June 29, 2012.
---------------------------------------------------------------------------

    Nonetheless, based on the available control technologies and the
five factors discussed above, EPA is proposing to require Apache
Generating Station to meet an emission limit for NOX on
Units 2 and 3 of 0.050 lb/MMBtu. Each of these emission limits is based
on a rolling 30-boiler-operating-day average.
2. Cholla Units 2, 3 and 4
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is
described in section VII.A.1 above. Issues unique to Cholla Units 2, 3
and 4 are explained

herein. There are several aspects of our analysis of this factor that
differ from ADEQ's and APS' analysis and we discuss the most important
of these below.
i. Selection of Baseline Period
    APS' BART analysis used a 2001-03 time period in order to establish
its baseline NOX emissions. As noted previously, the
NOX control technology present on Cholla Units 2 through 4
during that time period was close-coupled over fire air (COFA). APS has
since installed low-NOX burners with separated over fire air
(SOFA) on Cholla Units 2 through 4. In order to properly consider the
second BART factor (pollution control equipment in use at the source)
and to ensure that actual conditions at the plant were reflected in our
baseline NOX emissions, we decided to make use of the most
recent Acid Rain Program emission data reported to CAMD, which, at the
time that we began our analysis in 2011, was the three-year period from
2008 to 2010. Based on CAMD documentation, the low-NOX
burners were installed on the Cholla units at different times during
2008 and 2009, making it necessary for us to clearly distinguish
between the pre-LNB and post-LNB periods of emission data for each
unit.
    The use of a 2008 to 2010 baseline was, however, complicated by the
fact that the Cholla plant operates under a new coal contract for Lee
Ranch/El Segundo coal, which is a higher NOX-emitting coal
than what was previously used.\105\ This coal contract indicates that
steadily increasing minimum quantities of coal shall be delivered,
starting with 325,000 tons in 2006 and up to 3,700,000 tons in 2010.
This gradual transition to the newer, higher-NOX emitting
coal source made it difficult to determine the extent to which a
particular year's emissions were representative of anticipated annual
emissions. In the absence of more detailed fuel usage records on a per-
unit basis, it was not possible for us to identify which units may have
operated using the newer coal during the 2006 to 2010 transition period
to the newer coal type. We note, however, that the coal contract
specifically states that, for 2010 to 2024, no later than July 1 of
each year, the buyer shall indicate the annual tonnage for the
following calendar year, and that in no case shall the annual tonnage
be less than 3,700,000 tons. As a result, 2011 represents the first
complete calendar year at which we can be certain that the Cholla plant
operated at the new coal contract's ``full'' minimum purchase quantity
of 3,700,000 tons per year.
---------------------------------------------------------------------------

    \105\ A copy of the coal contract, including obligation amounts
and coal quality, can be found in Docket Item B-09, ``Additional APS
Cholla BART response'', Appendix B.
---------------------------------------------------------------------------

    Since 2011 Acid Rain Program emission data became available during
the intervening time between the start of our analysis and our proposed
action today, we have selected 2011 as the time period for establishing
baseline annual NOX emissions. Although this represents only
a single year of data, we believe the use of this more recent baseline
period represents the most realistic depiction of anticipated annual
emissions, as it is the only time period that ensures each of the
Cholla units is operating using the new coal and LNB with SOFA.
ii. SCR Control Efficiency
    In determining the control efficiency of SCR, we have relied upon
an SCR level of performance of 0.05 lb/MMBtu, which is more stringent
than the level of performance used by ADEQ in its SIP. In the Cholla
BART analysis submitted to ADEQ, APS indicated an SCR level of
performance of 0.07 lb/MMBtu, but did not provide site-specific
information describing how this emission rate was developed or
discussing why a more stringent 0.05 lb/MMBtu level of performance
could not be attained. Our control cost calculations for the SCR and
LNB with OFA control options are based upon the SCR control
efficiencies summarized below. These control efficiencies reflect the
emission reductions associated with controlling from an annual average
baseline emission rate that represents LNB with OFA (as described
previously) down to an SCR emission rate of 0.05 lb/MMBtu.

                         Table 18--Cholla Units 2, 3 and 4: EPA's Scr Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                                Baseline                           SCR control
                           Unit                              emission rate 1    SCR emission       efficiency
                                                               (lb/MMBtu)           rate          (percentage)
----------------------------------------------------------------------------------------------------------------
Cholla 2..................................................             0.295              0.05                83
Cholla 3..................................................             0.254              0.05                80
Cholla 4..................................................             0.260              0.05                81
----------------------------------------------------------------------------------------------------------------
1 As noted previously, this baseline emission rate reflects the installation of LNB+OFA

iii. Capacity Factor
    As noted previously, APS calculated annual emission estimates for
its control scenarios, in tons per year, using annual capacity factors
based on Acid Rain Program data from CAMD over a 2001 to 2006 time
frame.\106\ The annual capacity factors APS used for each unit were 91
percent (Cholla 2), 86 percent (Cholla 3), and 93 percent (Cholla 4).
We have also calculated annual emission estimates for our control
scenarios using capacity factors developed from CAMD information, but
have instead used a more recent 2008 to 2011 time frame. The annual
capacity factors we have used for each unit are 74 percent (Cholla 2),
75 percent (Cholla 3), and 71 percent (Cholla 4). We recognize that
these capacity factors are lower than those used by APS, and that by
using these lower capacity factors, our estimates of total annual
emissions (and correspondingly, the annual emission reductions) for
each control scenario are lower than APS' estimates.\107\ Since cost-
effectiveness ($/ton) is calculated by dividing annual control costs
($/year) by annual emission reductions (tons/year), the use of emission
reductions based on lower capacity factors will increase the cost per
ton of pollutant reduced.
---------------------------------------------------------------------------

    \106\ As listed in Table 2-1 in Docket Items B-06 through B-08,
Cholla BART Analyses.
    \107\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than APS' and ADEQ's estimates. We are not implying that the use of
capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Cholla and
the other

power plants that are the subject of today's proposed action.\108\
---------------------------------------------------------------------------

    \108\ We recognize that there are more aggressive approaches we
could adopt that could justify the use of higher capacity factors,
which would thereby lower the cost per ton of pollutant reduced. For
example, instead of using historical data to develop a capacity
factor value for each unit, we could use a single capacity factor
value for each unit, one that represented a reasonable depiction of
anticipated annual baseload operations. Alternately, we could also
use the capacity factor estimates from APS' Cholla BART analyses, as
based on a 2001-06 time frame, or develop new capacity factors based
on a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------

iv. Summary of Control Costs
    A summary of our control cost estimates for the various control
technology options considered for is included below. Detailed cost
calculations, including our contractor's report and cost calculation
spreadsheets, can be found in our TSD.

                                              Table 19--Cholla Units 2, 3 And 4: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Emission rate                                  Cost-effectiveness ($/ton)
                                                             Emission   --------------------------  Emissions               ----------------------------
                      Control option                        factor (lb/                              removed    Annual cost                 Incremental
                                                              MMBtu)       (lb/hr)       (tpy)        (tpy)        ($/yr)        Ave           (from
                                                                                previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.295          892        2,890  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.21           624        2,023          867    2,482,318        2,863  ..............
SCR+LNB+OFA..............................................         0.05           151          490        2,400    7,475,028        3,114           3,257
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.254          885        2,908  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.18           620        2,036          872    2,533,432        2,904  ..............
SCR+LNB+OFA..............................................         0.05           174          572        2,337    8,113,131        3,472           3,811
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Cholla 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA......................................................                        NA; LNB+OFA is the currently installed technology
                                                          ----------------------------------------------------------------------------------------------
LNB+OFA (baseline).......................................         0.260         1144        3,609  ...........  ...........  ...........  ..............
SNCR+LNB+OFA.............................................         0.18           801        2,526        1,083    3,185,822        2,943  ..............
SCR+LNB+OFA..............................................         0.05           220          694        2,915    9,894,796        3,395           3,661
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As indicated in Table 19, our calculations indicate that the SCR-
based control options have average cost-effectiveness values of $3,114/
ton to $3,472/ton, which falls in a range that we would consider cost-
effective. In addition, our calculations indicate that the SCR-based
control options have an incremental cost-effectiveness of $3,257/ton to
$3,811/ton, which is also in a range that we would consider cost-
effective. As a result, our analysis of this factor indicates that the
costs of compliance (average or incremental) are not sufficiently large
to warrant eliminating any of the control options from consideration.
b. Visibility Improvement
    The overall visibility modeling approach was described above;
aspects of the modeling specific to Cholla are described here. EPA made
a NOX BART determination for Cholla Units 2, 3 and 4, but
Unit 1 (which is not BART-eligible) was also included in the modeling
runs for greater realism in assessing the full facility's visibility
impacts. For Unit 1's NOX emissions, the maximum daily
emissions from EPA's CAMD database for 2008 to 2010 were used; the
maximum occurred in early 2008. LNB was installed on Units 2 and 4
early in 2008, and on Unit 3 in mid-2009; for a realistic base case,
the baseline emissions used for these units were the maximum daily
emissions in lb/hr from 2008-2010 occurring after the respective LNB
installation dates. The maximum for unit 2 occurred in mid-2009, and
the maxima for Units 2 and 3 occurred in late 2010. The base case
reflects LNB as the control in place.
    EPA evaluated SNCR (including LNB) and SCR (including LNB) applied
to Units 2, 3 and 4. SCR was assumed to give a control effectiveness of
83 percent, 80 percent, and 81 percent for units 2, 3 and 4,
respectively (less than 90 percent due to the 0.05 lb/MMBtu
NOX lower limit assumed for SCR). For Cholla, the increase
in sulfuric acid due to SCR was not simulated, because the baghouse
(fabric filter) installed for particulate matter control would reduce
this increased sulfate by 99 percent, resulting in a negligible effect
on the visibility estimate. The 13 Class I areas within 300 km of
Cholla were modeled; they are in the states of Arizona, Colorado, New
Mexico, and Utah. The 98th percentile delta deciview using all three
years of data together was computed for each area and emission
scenario.
    Table 20 shows baseline visibility impacts and the visibility
improvement when controls are applied; the various table entries are
described above in the discussion of the comparable table for Apache.
The area with the greatest dv improvement was the Petrified Forest
National Park; the improvement from SNCR was just under 0.5 dv and from
SCR was 1.3 dv. Either of these improvements would contribute to
improved visibility, with SCR being the superior option for visibility.
The corresponding cumulative improvements are 2.7 and 7.2. Only SCR
gives improvements exceeding 0.5 dv, and it does so at eight areas, two
of which have improvements above a full 1 dv. The modeled degree of
visibility

improvements supports SCR as BART for Cholla.

                Table 20--Cholla Units 2, 3 and 4: EPA's Visibility Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                           Baseline impact   Improvement from   Improvement from
                      Class I area                              (dv)            SNCR (dv)           SCR (dv)
----------------------------------------------------------------------------------------------------------------
Capitol Reef NP.........................................              1.46               0.27               0.76
Galiuro WA..............................................              0.45               0.05               0.14
Gila WA.................................................              0.70               0.09               0.22
Grand Canyon NP.........................................              2.22               0.37               1.06
Mazatzal WA.............................................              1.19               0.16               0.43
Mesa Verde NP...........................................              1.34               0.26               0.70
Mount Baldy WA..........................................              1.21               0.27               0.52
Petrified Forest NP.....................................              4.53               0.47               1.34
Pine Mountain WA........................................              0.85               0.12               0.31
Saguaro NP..............................................              0.30               0.02               0.05
Sierra Ancha WA.........................................              1.36               0.20               0.51
Superstition WA.........................................              1.27               0.17               0.51
Sycamore Canyon WA......................................              1.42               0.27               0.68
Cumulative dv...........................................             18.30               2.71               7.21
 areas >=0.5...................................                11               0                  8
$/max dv, millions......................................  ................             $17.8              $20.8
$/cumulative dv, millions...............................  ................              $3.1               $3.8
----------------------------------------------------------------------------------------------------------------

c. EPA's BART Determination
    As noted above, the remaining useful life of the source is
incorporated into control cost calculations as a 20-year amortization
period. In addition, the presence of existing pollution control
technology is reflected in the cost and visibility factors as a result
of selection of the baseline period for cost calculations and
visibility modeling. For Cholla Units 2, 3, and 4, a baseline period
(2011) was selected that reflects the currently existing pollution
control technology (LNB with OFA). In examining energy and non-air
quality impacts, we note certain potential impacts resulting from the
use of ammonia injection associated with the SNCR and SCR control
options, but do not consider these impacts sufficient enough to warrant
eliminating any of the available control technologies.
    Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial.
    Our consideration of cost of compliance focuses primarily on the
cost-effectiveness of each control option, as measured in cost per ton
and incremental cost per ton of each control option. Despite the fact
that the most stringent option, SCR with LNB and OFA, is the most
expensive of the available control options, we consider it cost-
effective on average basis as well as on an incremental basis when
compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be both cost-effective and to result
in substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, we propose to determine that NOX
BART for Cholla Units 2, 3, and 4 is SCR with LNB and OFA, with an
associated emission limit for NOX on each of Units 2, 3, and
4 of 0.050 pounds per million British thermal units (lb/MMBtu), based
on a rolling 30-boiler-operating-day average.
3. Coronado Units 1 and 2
a. Costs of Compliance
    Our general approach to calculating the costs of compliance is
described in section VII.A.2 above, while considerations unique to
Coronado Units 1 and 2 are explained herein. There are several aspects
of our analysis of this factor that differ from ADEQ's and SRP's
analysis and we describe the most important elements below.
i. Selection of Baseline Period and Baseline Control Technology
    SRP's BART analysis used a 2001-03 time period in order to
establish its baseline NOX emissions. Since that time
period, SRP has since installed LNB with OFA on Coronado Units 1 and 2.
In order to ensure that actual conditions at the plant are reflected in
our baseline NOX emissions, we decided to make use of the
most recent Acid Rain Program emission data reported to CAMD, which, at
the time that we began our analysis in 2011, was the three-year period
from CY2008-10. Based on CAMD documentation, the low-NOX
burners were installed on Coronado Unit 1 on May 16, 2009, making it
necessary for us to clearly distinguish between the pre-LNB and post-
LNB periods of emission data for Coronado Unit 1. In our analysis, we
have decided to make use of CAMD emission data corresponding to the
post-LNB period extending from May 16, 2009 to December 31, 2010. We
believe the use of this more recent baseline period represents the most
realistic depiction of anticipated annual emissions, as it reflects
operation of Coronado Unit 1 with LNB and OFA.
    For Coronado Unit 2, we note that a consent decree between SRP and
EPA requires the installation of SCR and compliance with an emission
limit of 0.080 lb/MMBtu (30-day rolling average) by June 1, 2014.\109\
Although we realize this SCR system has not yet been installed on
Coronado Unit 2, this limit is federally enforceable and represents a
realistic depiction of anticipated future emissions.\110\ As a result,
we consider 0.080 lb/MMBtu to be the baseline emission rate in our BART
analysis and are examining only one control scenario

in our analysis for Unit 2, SCR at a more stringent emission rate of
0.050 lb/MMBtu.\111\
---------------------------------------------------------------------------

    \109\ See Docket Item G-01, ``Consent Decree Between U.S. and
SRP (final as entered).'' See also ADEQ Title V Permit Renewal
Number 52639, SRP--Coronado Generating Station, section II.E.1.a.iii
(December 06, 2011).
    \110\ See 40 CFR part 51, appendix Y, Section IV.D.4.d.
    \111\ A discussion of our rationale for considering SCR at an
emission rate of 0.05 lb/MMBtu can be found in Section VII.A.2
(Control Effectiveness) of this notice.
---------------------------------------------------------------------------

ii. SCR Control Efficiency
    In determining the control efficiency of SCR in our BART analysis,
we have relied upon an SCR level of performance of 0.05 lb/MMBtu, which
is more stringent than the level of performance used by ADEQ in its
SIP, or by SRP in its Coronado BART analysis. In the Coronado BART
analysis submitted to ADEQ, SRP indicated an SCR level of performance
of 0.08 lb/MMBtu, and noted that ``If inlet NOX
concentrations are less than 250 ppmvd, SCR can achieve NOX
control efficiencies ranging only from 70 to 80 percent.'' \112\ SRP
suggests that the 75 percent reduction (and associated 0.08 lb/MMBtu
emission rate) it estimates for SCR is the result of low inlet
NOX concentration, but does not provide specific information
regarding inlet NOX concentration at Coronado, or how a 75
percent reduction was determined. Our control cost calculations for the
SCR control option at Coronado Unit 1 are based upon the SCR control
efficiency summarized below. This control efficiency reflects the
emission reductions associated with controlling from an annual average
baseline emission rate that represents LNB+OFA (as described
previously) down to an SCR emission rate of 0.05 lb/MMBtu.
---------------------------------------------------------------------------

    \112\ See Docket Item B-10, SRP Coronado BART Analysis, page 4-5

                             Table 21--Coronado Unit 1: EPA's SCR Control Efficiency
----------------------------------------------------------------------------------------------------------------
                                                              Baseline                            SCR control
                        Unit No.                         emission rate (lb/ SCR emission rate      efficiency
                                                               MMBtu)                             (percentage)
----------------------------------------------------------------------------------------------------------------
Coronado 1.............................................             0.303               0.05               83.5
----------------------------------------------------------------------------------------------------------------

iii. Capacity Factor
    SRP did not calculate annual emission estimates for its control
scenarios, in tons per year, in its BART analysis submitted to ADEQ. In
developing its RH SIP, ADEQ estimated annual emission reductions based
upon 8,760 hours/year of operation (i.e., 100 percent capacity factor).
We have calculated annual emission estimates for our control scenarios
using capacity factors developed over a CY2008-11 time frame. The
annual capacity factors we have used for each unit are 81 percent
(Coronado 1), and 89 percent (Coronado 2). We recognize that these
capacity factors are lower than those used by ADEQ, and that by using
these lower capacity factors, our estimates of total annual emissions
(and correspondingly, the annual emission reductions) for each control
scenario are lower than ADEQ's estimates.\113\ Since cost-effectiveness
($/ton) is calculated by dividing annual control costs ($/year) by
annual emission reductions (tons/year), the use of emission reductions
based on lower capacity factors will increase the cost per ton of
pollutant reduced.
---------------------------------------------------------------------------

    \113\ We note that there are multiple reasons why our annual
emission estimates (and estimates of emission removal) are lower
than AEPCO's and ADEQ's estimates. We are not implying that the use
of capacity factor is the sole, or even dominant, reason for this
difference, simply that the use of lower capacity factors will
result in lower annual emission estimates.
---------------------------------------------------------------------------

    We have elected to use the capacity factors specified above, as
based on a 2008 to 2011 time frame, in order to remain consistent with
the time frame used to develop baseline annual emissions for Coronado
and the other power plants that are the subject of today's proposed
action.\114\
---------------------------------------------------------------------------

    \114\ We recognize that there are more aggressive approaches we
could adopt that could justify the use of higher capacity factors,
which would thereby lower the cost per ton of pollutant reduced. For
example, instead of using historical data to develop a capacity
factor value for each unit, we could use a single capacity factor
value for each unit, one that represented a reasonable depiction of
anticipated annual baseload operations. Alternately, we could also
use a 100% capacity factor, or develop new capacity factors based on
a longer 2001 to 2011 time frame.
---------------------------------------------------------------------------

iv. Summary and Conclusions Regarding Costs of Control
    A summary of our control cost estimates for the various control
technology options considered for Coronado Units 1 and 2 is in Table
22. Detailed cost calculations, including our contractor's report and
cost calculation spreadsheets, are in our TSD.

                                              Table 22--Coronado Units 1 and 2: EPA's Control Cost Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Emission rate                                  Cost-effectiveness  ($/ton)
                                                           Emission   --------------------------  Emissions   Annual cost ------------------------------
                     Control option                       factor (lb/                              removed       ($/yr)                    Incremental
                                                            MMBtu)       (lb/hr)       (tpy)        (tpy)                    Average     (from previous)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Coronado 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
OFA....................................................                         NA; LNB+OFA is the currently installed technology
                                                        ------------------------------------------------------------------------------------------------
LNB+OFA (baseline).....................................         0.303        1,308        4,639  ...........  ...........  ...........  ................
SNCR+LNB+OFA...........................................         0.21           915        3,248        1,392    3,825,556        2,749  ................
SCR+LNB+OFA............................................         0.05           216          766        3,874    9,315,313        2,405             2,212
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Coronado 2
____________________________________________________________________________
<EMAIL_ADDRESS>lb/MMBtu......................................         0.08           319        1,242  ...........          \1\  ...........  ................
(baseline).............................................                                                         8,721,636
<EMAIL_ADDRESS>lb/MMBtu......................................         0.05           199          776          466    8,993,116  ...........               583
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Annual cost for the baseline scenario is provided here only to allow calculation of the incremental cost associated with a control option of
<EMAIL_ADDRESS>lb/MMBtu.

    For Coronado 1, our calculations indicate that the SCR-based
control option has an average cost-effectiveness value of $2,405/ton
and an incremental cost-effectiveness of $2,212/ton, both of which we
consider cost-effective. As described further below, our analysis for
Coronado 2 relied upon SCR at an emission rate of 0.08 lb/MMBtu as a
baseline scenario. As a result, the only control option we examined for
Coronado 2 was an SCR-based option at a more stringent level of
performance, 0.05 lb/MMBtu. Our initial analysis indicates that the
incremental cost-effectiveness of such an option is $583/ton, making it
a control option that we would consider cost-effective. However, we
received information from SRP indicating that design and construction
of the SCR system for this unit are well under way. In its letter, SRP
states that ``if SRP were required to abandon the current design, incur
procurement losses, possibly remove foundations, and undertake new
design and procurement, such steps would vastly increase the cost of
the SCR retrofit.'' Since these types of additional costs were not
factored into our original analysis, the average and incremental cost-
effectiveness of requiring Coronado Unit 2 to meet an emissions limit
of 0.050 lb/MMBtu may in fact be greater than indicated by our
analysis. However, we intend to request further documentation in order
to determine the extent of these costs and how they would affect our
cost-effectiveness calculations. We will include all non-CBI material
received in the docket for this action and will consider it as part of
our final action. We are specifically interested in information from
SRP concerning the number of layers of catalyst for the SCR at Unit 2,
how they plan to manage replacement of the catalyst, and whether the
catalyst could be installed and managed to allow Unit 2 to meet a lower
emission limit than 0.08 lb/MMBtu.
    Thus, our initial analysis of this factor indicates that the costs
of compliance (average or incremental) are not sufficiently large to
warrant eliminating any of the control options from consideration.
However, we note that, based on preliminary information received from
SRP, the average and incremental costs of achieving an emission rate of
0.050 lb/MMBtu at Unit 2 may be much greater than our initial analysis
suggests.
b. Visibility Improvement
    The overall modeling approach was described above; aspects of the
modeling specific to Coronado are described here. LNB was installed on
Unit 1 in mid-2009, and on Unit 2 in mid-2011. For Unit 1's
NOX emissions, the maximum daily emissions in EPA's CAMD
database for 2008 to 2010 was used; the maximum post-LNB installation
emissions occurred in late 2010. For unit 2 emissions, the consent
decree-mandated NOX emission limit of 0.08 lb/MMBtu was
combined with the maximum heat rate from 2008-2010 CAMD data, which
occurred in late 2008. Since this limit has a 30-day averaging time,
daily emissions may be larger than the emissions EPA modeled; the
emission and visibility benefit would also be larger. Thus, visibility
benefits from control applied to the base case may actually be larger
than presented here. The base case reflects LNB as the control in place
on Unit 1, and SCR at 0.08 lb/MMBtu NOX on Unit 2.
    EPA evaluated SNCR applied to Unit 1, and SCR at 0.05 lb/MMBtu
applied to both Units 1 and 2. SCR was assumed to give a control
effectiveness of 83.5 percent for unit 1 (less than 90 percent due to
the 0.05 lb/MMBtu NOX lower limit assumed for SCR). SCR at
0.05 lb/MMBtu NOX was assumed to give a control
effectiveness of 37.5 percent over the base case 0.08 lb/MMBtu. As
mentioned above, the SCR simulation accounted for the increase in
sulfuric acid emissions due to catalyst oxidation of SO2.
However, the simulation with SNCR applied to unit 1 did not account for
this effect. If this additional Unit 2 sulfate were accounted for, it
could make some background ammonia unavailable to form visibility-
affecting particulate from Unit 1's NOX emissions, thus
reducing the visibility impact and also the visibility benefit from
SNCR. We expect this to have very little effect on the estimated SNCR
visibility benefit, since it was computed relative to an alternative
base case that likewise did not include the catalyst oxidation effect,
but the visibility benefits from SNCR may thus be slightly less than
reported here, weakening the case for SNCR.
    Sixteen Class I areas within 300 km of Coronado were modeled; they
are in the states of Arizona, Colorado, and New Mexico. A 17th area,
the Bosque del Apache Wilderness Area in New Mexico, was inadvertently
omitted. Since it is in the same general direction from Coronado as the
Gila Wilderness Area, but farther way, visibility impacts and control
benefits at Bosque del Apache are likely to be lower than for Gila, so
the maximum dv benefit would not be affected by this omission. However,
the cumulative impacts and benefits would be higher than reported here
since Bosque del Apache is omitted from the sum. The 98th percentile
delta deciviews over all three years of data were computed for each
area and emission scenario.
    Table 23 shows baseline visibility impacts and the visibility
improvement when controls are applied; the various table entries are
described above in the discussion of the comparable table for Apache.
The area with the greatest dv improvement was the Gila Wilderness Area;
there is an improvement of 0.3 dv from SNCR, 0.6 dv from SCR on unit 1,
and 0.7 dv from SCR at 0.05 lb/MMBtu on both units. These improvements
are smaller than for the other facilities because the benefit from SCR
at 0.08 lb/MMBtu on unit 2 is subsumed in the baseline. Any of these
improvements would contribute to improved visibility, though SNCR on
unit 2 only marginally so. SCR is the superior option for visibility,
with the more stringent SCR at 0.05 lb/MMBtu on unit 2 giving a
slightly greater benefit than when that limit is applied only to unit
1. The cumulative improvements corresponding to the three control
scenarios are 1.3 dv, 2.8 dv, and 3.1 dv. Only the SCR scenarios give
improvements exceeding 0.5 dv. The modeled degree of visibility
improvements supports either SCR scenario as BART for Coronado.

                Table 23--Coronado Units 1 and 2: EPA's Visibility Improvements From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                    Improvement     Improvement     Improvement
                  Class I area                       Baseline      from SNCR on    from SCR .05   from SCR, 0.05
                                                    impact (dv)     unit 1 (dv)   on unit 1 (dv)   lb/MMBtu (dv)
----------------------------------------------------------------------------------------------------------------
Bandelier NM....................................            0.37            0.07            0.19            0.20
Chiricahua NM...................................            0.20            0.03            0.07            0.08
Chiricahua WA...................................            0.21            0.04            0.08            0.09
Galiuro WA......................................            0.20            0.03            0.08            0.09
Gila WA.........................................            1.23            0.33            0.60            0.66

Grand Canyon NP.................................            0.24            0.03            0.10            0.11
Mazatzal WA.....................................            0.20            0.03            0.06            0.07
Mesa Verde NP...................................            0.40            0.10            0.19            0.20
Mount Baldy WA..................................            0.87            0.16            0.42            0.44
Petrified Forest NP.............................            1.22            0.22            0.47            0.56
Pine Mountain WA................................            0.14            0.02            0.04            0.05
Saguaro NP......................................            0.12            0.01            0.03            0.04
San Pedro Parks WA..............................            0.54            0.11            0.28            0.30
Sierra Ancha WA.................................            0.24            0.04            0.06            0.07
Superstition WA.................................            0.21            0.02            0.06            0.06
Sycamore Canyon WA..............................            0.16            0.02            0.06            0.06
Cumulative dv...................................            6.54            1.25            2.78            3.07
 areas >=0.5...........................               4            0               1               2
$/max dv, millions..............................  ..............          $11.9           $16.2           $15.0
$/cumulative dv, millions.......................  ..............           $3.1            $3.5            $3.2
----------------------------------------------------------------------------------------------------------------
Note: Costs of implementing SCR at 0.08 lb/MMBtu on unit 2 are not included.

c. EPA's BART Determinations
    As noted above, we have considered the remaining useful life of the
source by incorporating a 20-year amortization period into our control
cost calculations. The presence of existing pollution control
technology is reflected in the cost and visibility factors as a result
of selection of the baseline period for cost calculations and
visibility modeling. For Coronado Unit 1, a baseline period (May 2009
to December 2010) was selected that reflects the currently existing
pollution control technology (LNB with OFA). For Coronado Unit 2, a
baseline of 0.080 lb/MMBtu was selected to reflect the requirements of
the consent decree decribed above. In addition, as noted above, we have
received information from SRP indicating that the design and
construction of SCR at Unit 2 have aleady progressed significantly. To
the extent that we receive additional documentation establishing the
status of this effort, we will take this information into consideration
under the factors of ``costs of compliance'' and ``existing controls.''
    In examining energy and non-air quality impacts, we note certain
potential impacts resulting from the use of ammonia injection
associated with the SNCR and SCR control options, but do not consider
these impacts sufficient enough to warrant eliminating any of the
available control technologies.
    Our consideration of degree of visibility improvement focuses
primarily on the improvement from base case impacts associated with
each control option. While each of the available NOX control
options achieves some degree of visibility improvement, we consider the
improvement associated with the most stringent option, SCR with LNB and
OFA, to be substantial. Our consideration of cost of compliance focuses
primarily on the cost-effectiveness of each control option, as measured
in cost per ton and incremental cost per ton of each control option.
Despite the fact that the most stringent option, SCR with LNB and OFA,
is the most expensive of the available control options, we consider it
cost-effective on average basis as well as on an incremental basis when
compared to the next most stringent option, SNCR with LNB and OFA.
    As a result, we consider the most stringent available control
option, SCR with LNB and OFA, to be cost-effective and to result in
substantial visibility improvement, and that the energy and non-air
quality impacts are not sufficient to warrant eliminating it from
consideration. Therefore, we propose to determine that NOX
BART for Coronado Units 1 and 2 is SCR with LNB and OFA. At Unit1 we
propose an emission limit for NOX of 0.050 lb/MMBtu, based
on a rolling 30-boiler-operating-day average.
    At Unit 2, we propose an emission limit of 0.080 lb/MMBtu, which is
consistent with the emission limit in the consent decree. We
acknowledge that the emission limit of 0.080 lb/MMBtu established in
the consent decree was not the result of a BART five-factor analysis,
nor does the consent decree indicate that SCR at 0.080 lb/MMBtu
represents BART. Nonetheless, given the compliance schedule established
in the consent decree and the preliminary information received from SRP
regarding the status of design and construction of the SCR system, it
appears that achieving a 0.050 lb/MMBtu emission rate may not be
technically feasible. Even if it is feasible, achievement of this
emission rate may not be cost-effective. Therefore, we are proposing an
emission limit of 0.080 lb/MMBtu as BART for NOX at Unit 2.
However, if we do not receive sufficient documentation establishing
that achievement of a more stringent limit is infeasible or not cost-
effective, then we may determine that a more stringent limit for this
unit is required in our final action.
    For Coronado Unit 2, we are proposing a compliance date of June 1,
2014 for the NOX limit, consistent with the consent decree
described above.
    Finally, at Coronado Unit 1, we are proposing to require compliance
with the NOX limit within five years of final promulgation
of this FIP consistent with the compliance times for the NOX
limits at the other units. However, we are seeking comment on whether a
shorter compliance schedule may be practicable for this unit.

C. Enforceability Requirements

    In order to meet the requirements of the RHR and the CAA and to
ensure that the BART limits are practically enforeceable, we propose to
include the following elements in the FIP:
    1. Requirements for use of continuous emission monitoring systems
(CEMS) (and associated quality assurance procedures) to determine
compliance with NOX and SO2 limits.
    2. Use of 30-day rolling averaging period and definition of boiler
operating day, consistent with the BART Guidelines.
    3. Requirements for annual performance stack tests and
implementation of Compliance Assurance Monitoring (CAM) plan to
establish compliance with PM emission limits.

    4. Recordkeeping and reporting requirements.
    5. Requirement to maintain and operate the unit including
associated air pollution control equipment in a manner consistent with
good air pollution control practices for minimizing emissions.

The foregoing requirements would apply to all units.
    In addition, we are proposing specific compliance deadlines for
each of ADEQ's BART emissions limits that we are proposing to approve.
In most instances, the control technologies required to meet these
limits have already been installed. See Table 3. Therefore, we are
proposing to require compliance with the applicable emissions limits
for PM and SO2 within 180 days of final promulgation of this
FIP, except that at Cholla Unit 2, we propose to require compliance
with the PM limit by January 1, 2015, consistent with ADEQ's BART
determination.
    Regarding NOX, we propose to allow up to five years from
final promulgation of this FIP for each unit subject to an emission
limit consistent with SCR, with the exception of Coronado Unit 2. This
proposal is based on the results of two analyses of SCR installation
times, as summarized in EPA Region 6's Complete Response to Comments
for NM Regional Haze/Visibility Transport FIP.\115\ An analysis
performed by EPA Region 6, based on a review of a number of sources,
found that the design and installation of SCR took between 18 and 69
months. A separate analysis performed for the Utility Air Regulatory
Group (UARG) found that it took 28 to 62 months to design and install
the 14 SCRs in its sample.\116\ In the case of the BART FIP for San
Juan Generating Station, EPA Region 6 initially proposed to allow a
three-year compliance time frame for design and installation of SCR,
but ultimately allowed for a five-year compliance schedule.\117\ We
also note that SCR installations often trigger Prevention of
Significant of Deterioration permitting requirements because they
constitute physical changes to an existing emission unit that may
result in increased emissions of sulfuric acid mist. Therefore, we are
proposing a five-year compliance time frame, which would provide
adequate time for SCR design and installation based on the high-end of
the range of dates in the analyses cited above. However, we are seeking
comment on whether these compliance dates are reasonable and consistent
with the requirement of the CAA and the RHR that BART be installed ``as
expeditiously as practicable.'' We are specifically seeking comment on
whether the outage schedule for any of these units may warrant a
shorter compliance schedule (up to five years). If we receive
information during the comment period that establishes that a shorter
compliance timeframe is appropriate for one or more of these units, we
may finalize a different compliance date.
---------------------------------------------------------------------------

    \115\ Available on regulations.gov, docket no. EPA-R06-OAR-2010-
0846, pp. 70-72. See also 76 FR at 52408-09.
    \116\ J. Edward Cichanowicz, Implementation Schedule for
Selective Catalytic Reduction (SCR) and Flue Gas Desulfurization
(FGD) Process Equipment (Oct. 10, 2010).
    \117\ 76 FR at 52408-09.
---------------------------------------------------------------------------

VIII. Summary of EPA's Proposed Action

    Based on the available control technologies and the five factors
discussed in more detail below, EPA is proposing to require these
facilities to meet NOX, PM10 and SO2
emission limits as listed in Table 24. With the exception of Apache
Unit 1, the NOX emission limits in Table 24 are proposed as
part of EPA's FIP, based on the five factor analyses summarized in
Section VII. The PM10 and SO2 emission limits in
Table 24 are taken from ADEQ's BART determinations for these
facilities, proposed for EPA approval in this action. EPA is seeking
comment on alternative PM10 and SO2 emissions
limits for Apache Generating Station Units 2 and 3; Cholla Power Plant
Units 2, 3 and 4; and Coronado Units 1 and 2 as described in Section
VI.B. We are also seeking comment on whether a test method other than
EPA Method 201/202 should be allowed or required for establishing
compliance with the PM10 limits that we are proposing to
approve. Finally, we are proposing compliance dates and specific
requirements for monitoring, recordkeeping, reporting and equipment
operation and maintenance for all of the units covered by this action.
Our proposed compliance dates are summarized in Table 25. We are
seeking comment on whether these compliance dates are reasonable and
consistent with the requirement of the CAA and the RHR that BART be
installed ``as expeditiously as practicable.'' We are also taking
comment on whether it would be technically feasible and cost-effective
for Coronado Unit 2 to meet an emissions limit of 0.050 lb/MMBtu for
NOX.
    EPA takes very seriously a decision to disapprove a state plan. In
this instance, we believe that Arizona's SIP meets the CAA requirements
with respect to its SO2 and PM10 limits, but the
NOX BART determinations for the coal-fired units are neither
consistent with the requirements of the Act nor with BART decisions
that other states have made. As a result, EPA considers that this
proposed disapproval is the only path that is consistent with the Act
at this time.

                                    Table 24--Summary of BART Emission Limits
----------------------------------------------------------------------------------------------------------------
                                                             Emission limitation (lb/MMBtu) (rolling 30-boiler-
                                                                           operating-day average)
                           Unit                            -----------------------------------------------------
                                                                   NOX              PM10               SO2
----------------------------------------------------------------------------------------------------------------
Apache Generating Station Unit 1..........................             0.056            0.0075           0.00064
Apache Generating Station Unit 2..........................             0.050              0.03              0.15
Apache Generating Station Unit 3..........................             0.050              0.03              0.15
Cholla Power Plant Unit 2.................................             0.050             0.015              0.15
Cholla Power Plant Unit 3.................................             0.050             0.015              0.15
Cholla Power Plant Unit 4.................................             0.050             0.015              0.15
Coronado Generating Station Unit 1........................             0.050              0.03              0.08
Coronado Generating Station Unit 2........................             0.080              0.03              0.08