Manual methodology if you ``include documentation for any additional
information you used for the cost calculations, including any
information supplied by vendors that affects your assumptions
regarding purchased equipment costs, equipment life, replacement of
major components, and any other element of the calculation that
differs from the Control Cost Manual.'' Id.
---------------------------------------------------------------------------

    The Control Cost Manual uses the overnight method of cost
estimation, widely used in the utility industry.\17\ The U.S. Energy
Information Administration (EIA) defines ``overnight cost'' as ``an
estimate of the cost at which a plant could be constructed assuming
that the entire process from planning through completion could be
accomplished in a single day. This concept is useful to avoid any
impact of financing issues and assumptions on estimated costs.'' \18\
EIA presents all of its projected plant costs in terms of overnight
costs. The overnight cost is the present value cost that would have to
be paid as a lump sum up front to completely pay for a construction
project.\19\ The overnight method is appropriate for BART
determinations because it allows different pollution control equipment
to be compared in a meaningful manner. Because ``different controls
have different expected useful lives and will result in different cash
flows, the first step in comparing alternatives is to normalize their
returns using the principle of the time value of money * * * . The
process through which future cash flows are translated into current
dollars is called present value analysis. When the cash flows involve
income and expenses, it is also commonly referred to as net present
value analysis. In either case, the calculation is the same: Adjust the
value of future money to values based on the same point in time
(generally year zero of the project), employing an appropriate interest
(discount) rate and then add them together.'' \20\ This is the
overnight method, in which costs are calculated based on current
dollars. Therefore, consistent with our proposal, we find that the
overnight method is appropriate for calculating costs for all six
units.
---------------------------------------------------------------------------

    \17\ See Control Cost Manual, Section 2.3 to 2.4.
    \18\ EIA, ``Updated Capital Cost Estimates for Electricity
Generation Plants,'' November 2010, footnote. 2, available at:
http://www.eia.gov/oiaf/beck_plantcosts/?src=email.
    \19\ Steven Stoft, Power Economics: Designing Markets for
Electricity, 2002.
    \20\ Id., page 2-18.
---------------------------------------------------------------------------

    OG&E and others incorrectly assume that BART cost effectiveness
should be based on the ``all-in'' cost method, which includes all of
the costs of a financial transaction, including interest, commissions,
and any other fees from a financial transaction up to the date that the
project goes into operation, as of the assumed commercial operating
dates of the scrubbers, 2014 and 2015. This is an entirely different
method than that prescribed in the Control Cost Manual. OG&E and others
conclude that dry scrubbers are not cost effective for the six units,
based on all-in costs reported in 2014 to 2015 dollars, compared to
costs estimated at other similar facilities based on overnight costs
and 2009 and earlier dollars. This comparison is an invalid because
OG&E's 2014 and 2015 all-in costs are much higher than the
corresponding overnight costs, as prescribed by the Control Cost
Manual. This makes the estimated cost of scrubbers at the six units
appear to be higher than scrubbers required at other similar facilities
costed using the overnight method. Many of the corrections we make to
ODEQ's cost estimates for the six OG&E and AEP/PSO units are due to the
fact that ODEQ did not follow this provision of the Control Cost Manual
in its SIP submittal. Please refer to our Supplemental RTC in the
docket for more information about how the overnight costing methodology
is employed by the Control Cost Manual.
2. Revised Cost Calculations for the OG&E Units
    OG&E's cost estimates deviate from the Control Cost Manual, which
is based on the overnight cost approach. In its cost estimates, OG&E
has improperly included allowances for excessive contingencies
allowances for funds during construction (AFUDC), double counted
certain expenses, and improperly relied on the Electric Power Research
Institute (EPRI) cost model, CUECost. These deviations from the Control
Cost Manual, occurring because of the reliance upon the all-in cost
methodology, artificially increase the cost of scrubbing at Sooner and
Muskogee, compared to the cost at other similar facilities using the
overnight cost methodology.
    OG&E's cost estimates relied on vendor quotes and site specific
estimates for certain additional costs. We support the use of vendor
quotes and site specific estimates but only as used within the
parameters of the overnight cost methodology. The Guidelines, cited in
this comment, are

clear that ``[y]ou should include documentation for any additional
information you used for the cost calculations, including any
information supplied by vendors that affects your assumptions regarding
purchased equipment costs, equipment life, replacement of major
components, and any other element of the calculation that differs from
the Control Cost Manual.'' \21\ However, much of the documentation OG&E
and others cite to support deviations from the Control Cost Manual was
not provided to us. Thus, we were unable to analyze their contents and
determine whether these deviations were appropriate. Also, although
OG&E provided two spreadsheets that listed its cost line items, these
spreadsheets, each over 600 lines in length, were stripped of all
formulas for cell calculations, preventing any meaningful review,
despite our request for that material.
---------------------------------------------------------------------------

    \21\ 70 FR 39104, at 39166, footnote 15.
---------------------------------------------------------------------------

Capital Recovery Factor
    We are changing one input to the cost calculations for the four
OG&E units based on a comment we received from OG&E concerning the
Capital Recovery Factor (CRF). OG&E states that, while the Control Cost
Manual includes a default rate of 7% for the social discount interest
rate, we should use a site-specific social discount interest rate for
the four OG&E units. This rate includes several site-specific
variables, including income tax. The commenter states that the CRF
includes not only recovery of principal but also a return on the
principal, with the rate of return equal to the discount rate. OG&E
states that for an investor owned utility, such as itself, which is
financed by a mix of debt and equity, the discount rate is equal to the
weighted average of the equity return and debt return.
    We agree that a site-specific social discount interest rate is
appropriate based on the documentation provided by the commenter.
However, we disagree that such a rate can include income tax. The
Control Cost Manual states ``this Manual methodology does not consider
income taxes.'' Control Cost Manual, page 2-9. The site-specific social
discount interest rate, excluding income tax, is 6.01%, which is less
than the default rate of 7%. Thus, we have revised our cost
effectiveness analysis in Exhibits 1 and 2 for Options 1 and 2, to use
the levelized interest rate of 6.01%, as reported by OG&E, adjusted to
remove income taxes. This rate is consistent with OG&E's real average
cost of capital and falls within the range of 3% to 7% recommended by
OMB for regulatory cost analyses. This correction moderately improved
the cost effectiveness, thus lowering the calculation of $/ton
SO2 removed. For detailed information on our calculation,
please see the Supplemental RTC.
Construction Management
    In our proposal, we revised the cost estimate to remove what we
took to be double counting of the Balance of Plant (BOP) construction
management costs. OG&E explained in a comment that crew wage rates do
not include contractor general and administrative (G&A) costs and that
construction management is the cost of third-party construction
management, different from the BOP profits contractor and different
from the owner. Based on this explanation, we have restored the
construction management costs in our revised Options 1 and 2 cost
estimates in Exhibits 1 and 2. This correction slightly diminished the
cost effectiveness, thus raising the calculation of $/ton
SO2 removed.
Scrubber Design and Emission Baseline Mismatch
    We retain both our Option 1 and Option 2 cost effectiveness
approaches to the mismatch between the design of OG&E's SO2
scrubbers and the coal they currently burn. OG&E specified to its
vendors that they provide cost estimates for SO2 scrubber
systems designed to treat the exhaust gases from a coal that contains
much higher amounts of sulfur than coals that were typically burned in
the baseline period (2004-2006). However, in calculating the cost
effectiveness, OG&E used its historical baseline emissions, which
resulted from the burning of those lower sulfur coals. Thus, OG&E
costed scrubbers that were overdesigned based on the coal that was, and
is, typically burned. This resulted in two errors that both combined to
make the control technology appear less cost effective.
    First, the BART Guidelines require that we calculate cost
effectiveness on the basis of annualized cost divided by tons of
pollutant removed from the emissions baseline ($/ton). Therefore, use
of a baseline that is lower than would result from burning the higher
sulfur coal the scrubber was designed to treat, lowers the denominator
in the $/ton equation, and skews the cost effectiveness calculation to
appear less cost effective. We account for this mismatch in Option 1 by
raising the baseline to match the higher sulfur coal the scrubber
system was designed to treat.
    Second, although we have adjusted our calculation in response to
OG&E's comments, we conclude that the over designed scrubber system was
more expensive than necessary to treat the coal OG&E historically
burned and continues to burn. We account for this mismatch in Option 2
by slightly decreasing the capital costs to reflect a scrubber designed
to treat the exhaust gases from the coal OG&E has historically burned,
while retaining the historical emission baseline.
    We find that, whether OG&E chooses to burn its current coal, or
burn a coal that its scrubber system was designed to treat, the
resulting cost effectiveness lies in the range defined by Options 1 and
2 (below). We find that both options are cost effective in light of the
five-step BART analysis.
Cost Adjustment of Scrubber in Option 2
    As we describe above, in calculating cost effectiveness under
Option 2 in our proposal, we also analyzed the cost of a dry scrubber
for the OG&E units, assuming the scrubber would be re-sized to scrub
the coal being currently burned. We did this using a cost scaling
equation based on the differences between the sulfur content of the
coal OG&E typically burns versus the coal their scrubber system was
designed to treat. OG&E responded in a comment to us that the exhaust
gas flow rate, rather than the sulfur content, is the primary variable
that affects scrubber sizing. Thus, the use of a higher sulfur coal
would not significantly affect the size, and hence the cost of a
scrubber. Based on the information OG&E supplied, we re-adjusted the
cost of Option 2 based on certain design algorithms in the dry scrubber
absorber (SDA) cost model developed by OG&E's contractor, Sargent &
Lundy for EPA.\22\ The results of this analysis indicate that the use
of the lower sulfur coal alone would reduce the capital cost of the
scrubber by about $7 million or 3%.
---------------------------------------------------------------------------

    \22\ Sargent & Lundy, IPM Model--Revisions to Cost and
Performance for APC Technologies, SDA FGD Cost Development
Methodology, Final, August 2010, Table 1.
---------------------------------------------------------------------------

Other Issues Concerning Site-Specific Costs
    In addition to those comments that resulted in a modification to
our cost basis, two others merit particular emphasis. These comments
led us to investigate two other line item costs to determine whether we
underestimated the costs of the scrubbers for the four OG&E units by
not using site-specific values. We determined that, even if we made
changes to the cost calculations to account for these site-specific
cost line items, the cost of controls would be

even more cost-effective than our proposed range. These line items
costs are: (1) Auxiliary power; and (2) capacity factor for Option 2.
These issues were uncovered during the course of preparing our response
to comments, but did not directly follow from information provided by
the comments. Thus, we did not further modify our cost basis, but
discuss these issues as they serve to further illustrate why we believe
our cost basis likely overestimates the costs of control and that our
conclusions that dry scrubbers for the six OG&E and AEP/PSO units are
cost effective and are reasonable.
a. Auxiliary Power
    We received a comment that EPA incorrectly lowered OG&E's auxiliary
power costs for the DFGD/FF control systems on the premise that the
unit cost of electricity used in the cost estimate was higher than the
cost to OG&E to produce electricity. Auxiliary power is the sum of the
demand by the scrubber, baghouse, and booster fans (the latter required
to overcome the increase in backpressure from adding these controls)
and is accounted for in a BART cost effectiveness analysis. OG&E used
average year-round market retail rates of $85.93/MWh (2015 dollars) for
Sooner and $83.83/MWh (2014 dollars) for Muskogee as the best long-run
measure of auxiliary power costs. The cost of auxiliary power affects
the cost effectiveness calculation in both Option 1 and Option 2.
    We have concluded that our proposed cost of $50/MWh is an
appropriate estimate of the cost of auxiliary power for the four OG&E
units. We arrived at this number because OG&E's summary of auxiliary
power costs indicates the range used for other similar facilities is
$30/MWh to $50/MWh.\23\ We took the most conservative view based on
this report and adopted the highest value in this range. However, even
if we were to take OG&E's view that a site-specific auxiliary power
cost is more appropriate, we disagree that we could use the market-
value of power for purposes of the BART determination because the
utility would not pay market price. We estimate that the actual site-
specific cost of auxiliary power for the four OG&E units is no more
than $36/MWh. However, because we arrived at this figure due to
independent research that we do not view as being a logical outgrowth
of the comment we received, we have not revised our cost effectiveness
analysis to use $36/MWh. Instead, we retain the $50/MWh figure we
proposed. We view this example as further evidence that OG&E's scrubber
costs are artificially inflated, and that the cost of controls under
both options in our FIP is reasonable.
---------------------------------------------------------------------------

    \23\ December 28, 2009 S&L FollowUp Report, Attach. C, pdf 109
(Gerald Gentleman--$45.65/MWh; White Bluff--$47/MWh; Boardman/
Northeastern/Naughton--$50/MWh; Nebraska City--$30/MWh).
---------------------------------------------------------------------------

b. Capacity Factor in Option 2
    ODEQ calculated future annual emissions assuming a 90% capacity
factor. In comparison, during the years that established the emission
baseline (2004-2006), the units operated only 78.5% of the time, on
average. Thus, ODEQ's calculation of emission reductions from scrubbers
compares uncontrolled 2004-2006 baseline emissions, when the units
operated at 78.5% of capacity, to controlled emissions when burning a
higher sulfur coal, with the units operating at 90% capacity. This
mismatch results in two errors in estimating the cost of Option 2: The
future emissions were overestimated, but certain operating costs were
underestimated. Correcting these errors in the cost calculations would
make Option 2 even more cost effective than our proposed calculations,
as the resulting decrease in the operating costs would offset the
increase in the capacity factor in the $/ton calculation. However,
because we arrived at these errors due to independent research that we
do not view as being a logical outgrowth of the comment we received, we
have not revised our cost effectiveness analysis in Option 2. We view
this example as further evidence that OG&E's scrubber costs are
artificially inflated, and that the cost of controls under both options
in our FIP is reasonable.
    We made no additional changes to our cost evaluation as a result of
the comments we received. As summary of our final $/ton cost
effectiveness calculations are provided below:

------------------------------------------------------------------------
                                   Proposal (Sooner/    Final (Sooner/
                                       Muskogee)           Muskogee)
------------------------------------------------------------------------
Option 1........................       $1,291/$1,317       $1,239/$1,276
Option 2........................       $2,048/$2,366       $2,747/$3,032
------------------------------------------------------------------------

3. Cost Calculations for the AEP/PSO Units
    We received a number of comments from AEP/PSO concerning our
SO2 BART cost estimate for the two Northeastern units. Some
of these comments objected to our incorporation of OG&E's site specific
information in AEP/PSO's scrubber cost estimate. Other comments
objected to specific line item costs in our cost estimates for both wet
and dry scrubbers. We proposed the cost effectiveness of dry scrubbing
to be $1,544/ton, and the cost effectiveness of wet scrubbers to be
approximately 9% more. As we note in more detail in our separate
Supplemental RTC, the ODEQ SO2 BART evaluation of AEP/PSO
Northeastern units 3 and 4 does not provide any support for its
assumption that the cost of dry scrubbers is $555/kW to $582/kW,
figures we consider to be high in comparison to other BART scrubber
determinations. However, the Northeastern units are very similar to the
Sooner and Muskogee units, for which vendor quotes were available for
dry scrubbers. We used these vendor quotes to support our cost analysis
for the Northeastern units. After having reviewed all comments
concerning our SO2 BART cost estimates for the AEP/PSO
units, we have determined that no changes were warranted to our
proposed cost estimates. Thus, absent any supporting information from
AEP/PSO for any of the capital costs it presents, we find our BART
SO2 cost evaluation to be well founded, representative of
the AEP/PSO units in question, and based on the best information
available to us.
4. Conclusion
    We find that under Option 1, the costs to comply with the FIP will
be $1,239/ton for Units 1 and 2 of the OG&E Sooner plant and $1,276/ton
for Units 4 and 5 of the OG&E Muskogee plant. Under Option 2, the cost
to comply with the FIP will be $2,747/ton for Units 1 and 2 of the OG&E
Sooner plant and $3,032/ton for Units 4 and 5 of the OG&E Muskogee
plant. For Units 3 and 4 of the AEP/PSO Northeastern plant, we find
that the costs to comply with the FIP remain at $1,544/ton, as we

proposed. We find these ranges to be cost effective for these six units
under the five-step analysis for BART under the RHR. As previously
stated, our complete, technical responses to comments received on the
issue of costs are in the Supplemental RTC in the docket.

F. Summary of Responses to Visibility Improvement Analysis Comments

    We received comments on Step 5 of BART: Degree of improvement in
visibility which may reasonably be anticipated to result from the use
of scrubber technology. Commenters contested our determination that
OG&E and AEP/PSO's facilities significantly contribute to visibility
impairment. We explain that we find that dry scrubbers are cost
effective for the six OG&E and AEP/PSO units, in light of the
visibility improvement these controls are predicted to achieve.
Commenters also disputed our determination not to use the $/deciview
metric in the Step 5 BART analysis when this approach was used by ODEQ.
OG&E provided a $/deciview analysis for its units and comparable BART
determination performed by us. In our analysis for our BART FIP for
OG&E and AEP/PSO, we did not evaluate $/deciview. We explain that the
BART Guidelines list the $/deciview metric as an optional cost
effectiveness measure that can be employed along with the required $/
ton metric for use in a BART evaluation. The metric can be useful in
comparing control strategies or as additional information in the BART
determination process; however, due to the complexity of the technical
issues surrounding regional haze, we have never recommended the use of
this metric as a cutpoint in making BART determinations. We note that
to use the $/deciview metric as the main determining factor would most
likely require the development of thresholds of acceptable costs per
deciview of improvement for BART determinations for both single and
multiple Class I analyses. We have not developed such thresholds for
use in BART determination made by us. As OG&E acknowledges, EPA did not
use this metric as part of its proposed BART determinations for either
the Four Corners Power Plant FIP in AZ, or the San Juan Generating
Station FIP in NM. Generally speaking, while the metric can be useful
if thoughtfully applied, we view the use of the $/deciview metric as
suggesting a level of precision in the calculation of visibility
impacts that is not justified in many cases. While we did not use a $/
deciview metric, we did, however, consider the visibility benefits and
costs of control together, as noted above by weighing the costs in
light of the predicted visibility improvement.

G. Summary of Responses to Comments Received on the SO2 BART
Emission Limit

    We received comments stating we did not adequately support our
SO2 BART emission limit of 0.06 lbs/MMBtu for the six OG&E
and AEP/PSO units. In analyzing the control technology, the RHR
mandates that we take into account the most stringent emission control
level that the technology is capable of achieving. 70 FR 39104, at
39166. In accordance with the RHR, when identifying an emissions
performance level to evaluate under BART, consideration of recent
regulatory decisions and performance data (e.g. manufacturer's data,
engineering estimates, and the experience of other sources) is
required. Id. In determining our SO2 BART emission limit of
0.06 lbs/MMBtu, we drew on a number of sources of information. These
include industry reports, vendor quotes, the engineering analysis
contained in the TSD, and the historical emissions data for other
similar coal fired power plants. As we state in the TSD and affirm, a
dry scrubber at Sooner or Muskogee, designed as costed, could meet an
SO2 emission limit of 0.06 lb/MMBtu based on 30-day BOD
average, when burning coal containing 0.51 to 1.18 lb/MMBtu
SO2. We conclude the same is true for the AEP/PSO
Northeastern units because they have historically burned coal with a
sulfur content within this range.\24\
---------------------------------------------------------------------------

    \24\ TSD, Appendix C, page 43.
---------------------------------------------------------------------------

    Among other objections, OG&E states we cannot rely on the
SO2 emission performance of new facilities as an indicator
of the performance potential of retrofit scrubbers. OG&E presents data
on what it states are the best performing scrubber installations in the
United States, and contends that the lowest emission rate achieved by a
retrofit on an annual basis is 0.088 lbs/MMBtu. We explain that a
scrubber, regardless of type, is not influenced by whether the flue gas
comes from a new boiler or an old boiler located in an existing plant.
The scrubber merely reacts to physical and chemical characteristics of
the gas stream. Therefore, although we use other sources of information
to justify our SO2 BART emission limit, we find that
considering emission data from new scrubber installations to support
our decision is appropriate. In so doing, we analyzed the historical
emissions data of several units that we discuss above in response to
another comment, which OG&E included in its comment. We reviewed the
performance of three units that are of similar size and burn similar
coal. One unit, TS Power Plant, has an emission limit that requires
emissions to be significantly controlled and has been able to maintain
its emissions below 0.06 lbs/MMBtu on a 30 day BOD basis continuously.
We also reviewed the performance of two other units that demonstrate
the ability to maintain emissions below the 0.06 lbs/MMBtu limit for
long periods of time. We note that these units do not have as
constraining emission limits so they do not have to control their
emissions as closely. This and other sources of information we outline
above and in our Supplemental RTC cause us to conclude our proposed
SO2 BART emission limit of 0.06 lbs/MMBtu, calculated on the
basis of a 30 day BOD, for the six OG&E and AEP/PSO units is
technically feasible and therefore the correct SO2 limit for
BART.
    OG&E also states that we should include in our proposed
SO2 BART emission limit a compliance margin. OG&E suggests
that a SO2 emission of 0.10 is required to provide a
``reasonable margin for operating fluctuations and compliance.'' We
reply that we are modifying the compliance averaging period from a 30
calendar period to a 30 day Boiler Operating Day (BOD) period. As the
BART Guidelines direct, ``[y]ou should consider a boiler operating day
to be any 24-hour period between 12:00 midnight and the following
midnight during which any fuel is combusted at any time at the steam
generating unit.'' \25\ To calculate a 30 day rolling average based on
boiler operating day, the average of the last 30 ``boiler operating
days'' is used. In other words, days are skipped when the unit is down,
as for maintenance. This, in effect, provides a margin by eliminating
spikes that occur at the beginning and end of outages, and is
consistent with the BART Guidelines.
---------------------------------------------------------------------------

    \25\ 70 FR 39104, at 39172.
---------------------------------------------------------------------------

    In our separate Supplemental RTC, we also discuss several other
objections OG&E raises in its comments. These include objections to our
reliance on a National Lime Association scrubber performance chart,
OG&E's contention that our proposed SO2 BART emission is
more representative of a LAER limit, and the technical capability of
dry scrubbing. After addressing these issues, we find that our proposed
SO2 BART emission for the six OG&E and AEP/PSO units remains
at rate of 0.06 lbs/MMBtu.

H. Summary of Responses to Comments Received on the SO2 BART
Compliance Timeframe

    We proposed that compliance with our SO2 BART emission
limits be within three years of the effective date of our final rule.
We solicited comments on alternative timeframes, from as few as two (2)
years to up to five (5) years from the effective date of our final
rule. We received comments that retrofitting of scrubbers is now
routine in the United States and that approximately 290 coal-fired
units totaling about 116,000 MW nationwide have been retrofit with
scrubbers since 1990. The commenter cites to many examples of
SO2 scrubbers being installed at coal-fired power plants
within a three year timeframe. OG&E and others state that our proposed
three year schedule focuses on actual construction timelines, but fails
to acknowledge or allow sufficient time for the engineering, design,
and permit processes that must be completed prior to the commencement
of construction. They state a compliance schedule of from 52-54 months
would be required.
    Although we do not specify what technology the six OG&E and AEP/PSO
units must use to satisfy the SO2 BART emission limit, we
expect that either dry or wet SO2 scrubbers will be used, or
that the SO2 limit will be met by switching one or more of
the units to natural gas. We agree that SO2 scrubbers have
been installed at other facilities with construction timeframes of
three years or less. However, we also agree with OG&E and AEP/PSO that
there may be issues such as PSD permitting, and the construction/
expansion of a landfill that may not be reflected in the example
compliance times reported by the commenter. Therefore, we find that
compliance with the emission limits be within five years of the
effective date of our final rule.

I. Comments Supporting Conversion to Natural Gas and/or Renewable
Energy Sources

    Comment: Several parties submitted comments noting that switching
to natural gas-fired electricity is feasible and demonstrated in
practice. One of the commenters points out that, of the three subject
sites, two have existing major natural gas supplies (OG&E Muskogee and
AEP/PSO Northeastern) and that fuel switching will require construction
of new or expanded natural gas supply and electric interconnection
facilities. The commenter states that expanding along existing gas
supply lines would cost less and take less time than constructing a new
line. The commenters have stressed that natural gas produces
comparatively low emissions of many pollutants, including haze-causing
pollutants, air toxics, and greenhouse gases. Commenters also noted use
of natural gas as a fuel source would eliminate the need to manage coal
combustion waste and scrubber waste. Several commenters who support the
switch from coal combustion to natural gas combustion cited the
availability and abundance of natural gas as a natural resource,
particularly in Oklahoma.
    Response: We agree that switching of existing coal-fired power
generating units to natural gas, either through conversion of existing
boilers or installation of new power generating units, is technically
feasible and demonstrated in practice. As stated in our proposal, the
owners of the units subject to the FIP may elect to reconfigure the
units to burn natural gas as means of satisfying their BART obligations
under section 51.308(e). Switching to natural gas would be an
acceptable method of complying with the limits proposed in the FIP,
because natural gas combustion inherently results in much lower
SO2 emissions. We agree that natural gas may result in lower
emissions of other pollutants and offer other environmental advantages.
The owners of each subject unit may take these advantages, as well as
the availability and pricing information, into consideration as they
evaluate this option for complying with SO2 BART emission
limits.
    Comment: Eight commenters responded to our request for comments on
the compliance deadline for the six BART-subject units and whether it
would be appropriate to extend that deadline for those utilities that
elected to switch from coal to natural gas in order to comply with the
BART emission limits. Several of these commenters note that switching
to natural gas can be accomplished in less than three years if
utilities enter into long-term power purchase agreements with existing
natural gas-fired power generators but utilities that choose to
construct new gas-fired units or convert existing units will likely
require more time. They indicate that the requirements to engage in
competitive bidding, complete engineering designs, prepare budgets,
obtain necessary permits, and equipment installation will likely
require up to five years to complete. One of these commenters points
out that OG&E has already studied fuel-switching at the system and
plant levels and that the typical lead time of construction of new
natural gas-fired combined cycle combustion turbines is four years.
    Numerous commenters express their support for extending the
compliance deadline to five years for units that will be converted to,
or replaced with, natural gas-fired power generating units. These
commenters cite the broad collateral benefits and overall superiority
of switching to a cleaner fuel source over installing additional
controls on the existing units and continuing to burn coal.
    Multiple other commenters, however, expressed the opinion that the
utilities have had ample time already to transition away from coal to
cleaner or renewable power generation and that the affected utilities
should phase out the BART-subject coal-fired units as quickly as
possible. These commenters feel that the proposed compliance deadline
of three years is adequate.
    ODEQ submitted comments supporting a fourteen and one-half month
extension (to four years and two and one-half months total) on the
installation of scrubbers and a seven and one-half year extension (to
ten and one-half years total) for switching to natural gas.
    Response: We thank the commenters for their responses to our
request for comments on the proposed compliance deadline. As we have
discussed elsewhere in our response to comments we find that a
compliance deadline of five years is appropriate for the six OG&E and
AEP/PSO units to comply with our FIP SO2 emission limit.
After reviewing the information provided by the commenters, we find
that the same compliance deadline of five years is appropriate for any
of the six OG&E and AEP/PSO units that elect to comply with the FIP
SO2 emission limit by converting an existing unit to natural
gas or replacing it with a new, natural gas-fired unit.
    Comment: Several commenters provided information concerning
underutilized electrical generation capacity through natural gas
combustion in Oklahoma. One commenter further suggested that fuel
switching could be achieved by imposition of annual emissions caps on
the BART-subject, coal-fired units. According to the commenter, such a
scheme would provide the affected utilities with the flexibility to
shift power generation to existing gas-fired generating units or
purchase power from merchant generators. The commenter states that
there is an exception provision in the RH regulations at 40 CFR
51.308(e)(2) that allows for imposition of operating limits on BART-
eligible units in lieu of conventional BART reductions if the
regulating authority implements an emission trading program.

    Another commenter noted that switching to natural gas-fired
generation, either through conversion of existing units or replacement
with new units, would result in power plants better suited to integrate
with variable wind power generation.
    Response: Section 51.308(e)(2) allows Oklahoma to implement an
emissions trading program or other alternative measure in lieu of BART.
Among other requirements, such an alternative to BART must achieve
greater reasonable progress than would be achieved through the
installation and operation of BART. However, Oklahoma did not include
such a program as part of its RH SIP, and we cannot require Oklahoma to
establish an emission trading program that would support annual
emission caps or operational limits on the six BART-subject units. We
also note that as a practical matter, there is no longer adequate time
to develop and implement such an emissions trading program and meet our
consent decree deadline with WildEarth Guardians of December 13, 2011
if we attempted to develop and implement such an emission trading
program as part of our action.\26\ Whether or not existing natural gas-
fired power generation capacity in Oklahoma and other parts of the
Southwest Power Pool is underutilized has no direct bearing on our
SO2 BART determinations.
---------------------------------------------------------------------------

    \26\ See, WildEarth Guardians v. Jackson, Case No. 4:09-cv-
02453-CW (N. Dist. Cal.).
---------------------------------------------------------------------------

    Comment: We received multiple comments from numerous parties
concerning the economics of switching from coal-fired to natural gas-
fired power generation. These comments focused on a wide range of
economic issues, including cost-benefit analysis of one BART compliance
alternative over another, future risk to ratepayers due to future
maintenance and compliance costs, economic impact of increasing
reliance on renewable energy sources, and ancillary benefits to the
economy of switching from coal to natural gas or renewable energy
sources.
    Many of the comments we received pertain to the additional economic
burden of addressing coal combustion and scrubber waste that would
continue to be generated by the six BART-subject coal-fired units if
the utilities elect to comply with the BART requirements of the
proposed FIP by installing scrubber units, rather than fuel switching.
One commenter provided an economic analysis indicating that containment
of the coal ash and scrubber waste would cost $180 million in capital
investment and $2-$5 million annually for disposal of residuals if the
utilities can sell the fly ash, or up to $9 million annually if the fly
ash cannot be sold. The commenter further asserts that scrubbing all
six of the BART-subject coal-fired units could generate up to 600,000
tons per year of flue gas desulfurization waste byproducts, the
disposal of which could cost an additional $22 million annually. Two
commenters have asserted that the power generation capacity of the six
OG&E and AEP/PSO units can be replaced with the construction of new,
modern natural gas-fired combined cycle turbines for less money than
would be required to install scrubbers on the coal-fired units to meet
BART emission limits.
    Other comments focused on the likely imposition of future,
additional environmental regulatory compliance costs associated with
continued firing of coal, such as requirements for new baghouses to
control emissions of particulate matter and metals, construction of
improved and expanded containment of coal combustion residuals, and
carbon emission reductions or sequestration. These commenters noted
that attempting to further extend the lives of the six OG&E and AEP/PSO
units is a bad investment when such additional controls for other
pollutants are foreseeable, and that switching to natural gas power
generation would reduce the risk to ratepayers of the eventual cost
increases associated with these additional regulatory requirements.
    Several commenters noted that the six OG&E and AEP/PSO units are
approaching the end of their useful lives and that switching to natural
gas and renewable energy sources will decrease the risk to ratepayers
of increased maintenance costs due to the advanced age of the units.
    Other commenters, some of whom identified themselves as ratepayers
at the affected utilities, indicated that they would be willing to pay
an increase in power rates in exchange for power that was generated by
cleaner fuels or renewable energy sources. These commenters cited the
overall health and environmental benefits that would result from a
transition away from coal-fired power and expressed their belief that
such benefits would outweigh any potential increase in electricity
rates.
    Finally, two commenters suggested that switching to natural gas
and/or renewable energy sources would have collateral economic benefits
by creating new jobs and providing general economic stimulus in the
region.
    Response: We affirm that each of the sources subject to BART under
the FIP can acceptably meet the emission limits in the FIP by switching
to natural gas. As the companies evaluate how to satisfy their BART
obligations, we encourage them to consider switching from coal to
natural gas at the six affected units as this may offer numerous,
significant long-term financial and environmental benefits over the
option of continued use of coal with additional controls. As was stated
in our proposal, we do not wish to dissuade companies from exercising
this option. As we discuss elsewhere in our response to comments and
Supplemental RTC, we find that a compliance deadline of five years is
appropriate for any of the six OG&E and AEP/PSO units that elect to
comply with the FIP SO2 emission limit by converting an
existing unit to natural gas or replacing it with a new, natural gas-
fired unit.
    Comment: Several commenters expressed concern over the potential
rate increases that might result from a switch to natural gas or some
form of renewable energy sources and the impact of those rate increases
on households with low or fixed incomes.
    Response: The companies owning each of the sources subject to BART
are only required to satisfy the SO2 BART emission limits at
those sources. Our action only contemplates the reconfiguration of
existing units. We have determined that reconfiguration would be cost
effective with application of dry and wet scrubbing technology. Though
the SO2 BART emission limits may also be met with
reconfiguration of the units to burn natural gas, the companies
themselves are free to determine whether this option best responds to
future customer needs and preferences, including any potential impact
on rates. As we state elsewhere in this response to comments and the
Supplemental RTC, although we based our BART determination of the use
of SO2 dry scrubbers, the owners of the six units in
question are free to consider any technology to meet their
SO2 BART obligations, including switching to natural gas. We
acknowledge the potential benefits that the commenters suggest of
switching the units in question to burn natural gas. Renewable energy
technology is not a retrofit option for the sources subject to BART and
is accordingly outside the scope of our action.
    Comment: Several commenters have expressed the view that it does
not make good economic sense to invest heavily in new control equipment
in order to meet BART on units that are so close to retirement. Some of
these commenters point out that it makes more sense to invest in new
natural gas-fired units

instead of converting the existing boilers to burn natural gas, given
the size of the investments being considered and the advanced age of
the existing coal-fired units.
    Several of the comments focused on the long-term economic benefits
of construction of new natural gas-fired units over conversion of the
existing boilers at the six coal-fired units to meet the BART emission
limits.
    Response The BART guidelines do allow for consideration of the
remaining useful life of facilities when considering the costs of
potential BART controls. Such a claim would have to be secured by an
enforceable requirement. Neither OG&E nor AEP/PSO claimed any such
restriction on the operation of these six units and Oklahoma did not
submit any enforceable document for action by us. Consequently, we
assumed a remaining useful life of 30 years in our BART analysis.
    If OG&E and/or AEP/PSO decide the units in question have a shorter
useful life such that installing scrubbers is no longer cost effective,
and are willing to accept an enforceable requirement to that effect, a
revised BART analysis could be submitted by the plant(s) in question
and our FIP could be re-analyzed accordingly. Similarly, we could also
review a revised SIP submitted by ODEQ.
    Comment: Numerous commenters expressed broad support for
transitioning away from coal and other fossil fuels to sources of
energy that are completely renewable, such as wind and solar-generated
power. These commenters recommend that the BART-subject units should be
replaced with wind-powered units where possible and that natural gas
should be used for power generation during periods of low wind yield.
One of the commenters notes that Oklahoma and other parts of the
Southwest Power Pool (SPP) have enormous potential for wind farm
development and that as of July 2010 the SPP transmission
interconnection queue had 111 wind generation projects totaling over
20,000 MW and an additional 7,470 MW of incremental wind development.
Comments received on this subject also noted that wind power can be
developed at relatively low costs and that the money the utilities
currently spend on the importation of coal and handling the byproducts
of its combustion would be better spent on construction of additional
wind generating capacity.
    Response: Renewable energy technology is not a retrofit option for
the sources subject to BART and is therefore outside the scope of our
SO2 BART determination. We do generally acknowledge that
many kinds of renewable energy do not produce haze-causing pollutants,
and transitioning to those sources of energy could lead to visibility
improvements.
    Comment: We received opinions and data from four commenters
expressing support for increased energy efficiency efforts as a
technique for lowering power demand and therefore reducing the
combustion of fossil fuels and its impact on the environment. One of
these commenters noted that the affected utilities have begun some
energy efficiency programs and that with increased effort they should
be able to realize the successes of other programs elsewhere in the
country that have seen cumulative reductions in annual power
consumption of 5-8 percent since 2004. The commenter notes that OG&E,
in particular, should be able to reduce power demand by up to 1,200
GWh/year and 2,100 GWh/year after five and ten years, respectively, at
an annual reduction goal of one percent, or as much as 1,800 GWh/year
and 3,100 GWh/year after five and ten years, respectively, at an annual
reduction goal of one and a half percent.
    Response: While not specifically within the scope by our
SO2 BART determination or our approval of other aspects of
the state's RH SIP, we acknowledge that efficiency programs that reduce
reliance on sources of haze-causing pollutants may promote visibility
improvements.
    Comment: OG&E states that if it is required to decide whether to
install scrubbers or retire and replace electric generating units with
natural gas on roughly the same time frame, the economic analysis
suggests that rate increases to customers will be lower with scrubbers.
Installation of scrubbers is projected to cost more than $1.5 billion.
OG&E is concerned that with this type of capital investment, it would
be locked economically into maximizing the use of its coal-fired units
for the foreseeable future. OG&E states the agreement outlined by ODEQ
in the SIP (and rejected by EPA) would reduce ``the cumulative
SO2 emissions from Sooner Units 1 and 2 and Muskogee Units 4
and 5 [to] approximately fifty-seven percent (57%) less than would be
achieved through the installation and operation of Dry FGD with SDA at
all four (4) units.'' OG&E states it should have the flexibility to
take advantage of evolving technologies and to utilize these local
clean energy sources at its plants in the future, while achieving the
same (or better) reduction in impact on visibility. OG&E states EPA's
failure to consider these issues in the proposal is short-sighted, and
arbitrary, capricious and contrary to applicable law.
    Response: We find the approximately $1.2 billion cost claimed by
OG&E in its BART analysis (referenced above as $1.5 billion) for the
installation of SO2 dry scrubbers is in error. As discussed
elsewhere in our response to comments and Supplemental RTC, based on
our Option 1 and Option 2 analyses, we find the total project costs to
range between $290,418,007 to $299,400,007 for Sooner Units 1 and 2,
and from $298,818,917 to 289,791,940 for Muskogee. Further, as we also
discuss in our proposal, although we based our SO2 BART
determination on the basis of dry SO2 scrubbers, OG&E is
free to employ other technologies to meet this limit, including
switching to natural gas, as long as that switch is completed in the
same BART timeframe. We discuss the BART compliance deadline in the
response to another comment.
    Comment: A commenter stated we failed to consider ``the costs of
compliance'' of converting the six coal-fired generating units to
natural gas. Without any explanation, contends OIEC, we proposed that
these generating units could be converted to natural gas ``as a means
of satisfying their BART obligations.* * *'' 76 FR 16168, at 16194. The
commenter states we failed to consider the costs of compliance of
conversion to natural gas, as required by the CAA section 169A(g)(2),
and the BART Guidelines, Part 51, Appendix. Y(IV)(D)(4)(a). The
commenter states the FIP should therefore be withdrawn.
    Response: The commenter's reference to our proposal \27\ is fully
reproduced as follows:
---------------------------------------------------------------------------

    \27\ 76 FR 16168, at 16194.

    Should OG&E and/or AEP/PSO elect to reconfigure the above units
to burn natural gas, as a means of satisfying their BART obligations
under section 51.308(e), that conversion should be completed by the
same timeframe. We invite comments as to, considering the
engineering and/or management challenges of such a fuel switch,
whether the full 5 years allowed under section 308(e)(1)(iv)
---------------------------------------------------------------------------
following the effective date of our final rule would be appropriate.

    Under the RHR,\28\ we cannot, and did not, evaluate the costs
associated with switching the six OG&E and AEP/PSO units over to
natural gas for BART. However, after conducting the BART analysis and
adopting of emissions limits, alternatives to installing control
technologies may achieve the same emission limits. We are open to
alternative mechanisms to achieve the BART emissions limits we adopted.
As

stated in our proposal, we merely afforded OG&E and/or AEP/PSO the
opportunity to switch to natural gas as a means of satisfying BART. We
also indicated we were willing to consider comments to extend the BART
compliance timeframe to the full amount of time allowed under the RHR
to accommodate that conversion. Although we based our BART
determination of the use of SO2 scrubbers, the six units in
question are free to consider any technology or alternative mechanism
to meet their SO2 BART obligations.
---------------------------------------------------------------------------

    \28\ 70 FR 39104, at 39164: ``note that it is not our intent to
direct States to switch fuel forms, e.g. from coal to gas.''
---------------------------------------------------------------------------

J. Comments Arguing Our Proposal Would Hurt the Economy and/or Raise
Electricity Rates

    Comment: Several commenters expressed concern about adverse effects
of electrical bill increases, stating that analyses prepared by the
state's utilities, business groups and the Oklahoma Corporation
Commission estimate our proposal could increase utility bills in
Oklahoma significantly, with some estimates as high as 30 percent. Some
commenters stated that the rate increase would result in decreased
business investment in Oklahoma; while others stated that it will hurt
existing businesses, local governments, and families already struggling
from the recession. Several commenters noted that the rate increase
will have a disproportionate adverse impact on senior citizens and the
disadvantaged, especially individuals living on fixed incomes.
Commenters urged us to consider the cost implications of our proposal
as we balance the goals of the CAA with the economic impact on
consumers, communities, and businesses. Specifically, one commenter
stated that installation of scrubber technologies on aging coal-fired
facilities may not be the most cost-effective or environmental
approach. Several commenters ask EPA to consider all of the
alternatives available, including switching to natural gas over a
longer timeframe. One commenter further stated that EPA's proposal is
not cost effective and does not significantly improve visibility.
Commenters urged EPA to adopt the Oklahoma State plan. A commenter that
supported the proposal stated that while the FIP could cause rates to
increase somewhat, Oklahoma has the eighth lowest average electricity
rates in the country, rates are higher in neighboring states, and the
difference in rates may result from the fact that other states have
emission controls on a higher percentage of their coal plants.
    Response: The federal regulations implementing the CAA's BART
provisions require that we evaluate (1) cost of compliance, (2) the
energy and non-air quality environmental impacts of compliance, (3) any
existing pollution control technology in use at the source, (4)
remaining useful life of source, and (5) degree of improvement in
visibility which may reasonably be anticipated to result from the use
of such technology. 40 CFR 51.308(e)(1)(ii)(A). After a careful cost
review, we have determined that benefits in visibility from
implementing our proposal outweigh the increase in costs for the
facilities. As discussed in our proposal, we disagree with OG&E's and
AEP/PSO's cost estimate for installing scrubbers on the six units
addressed by our FIP. After careful review of information provided
during the public comment period, we revised our calculation of the
total project cost for the four OG&E units from our proposed range of
approximately $312,423,000 to $605,685,000, to our final range of
approximately $589,237,000 to $607,461,000. We made no changes to the
cost basis for the two AEP/PSO units from our proposal. As such, the
associated cost investment for AEP/PSO is $274,100,000. In light of the
visibility benefits we predict will occur, we consider this to be cost
effective. We take our duty to estimate the cost of controls very
seriously, and make every attempt to make a thoughtful and well
informed determination. We note that our cost estimate, being about
half that of OG&E's will result in significantly less costs being
passed on to rate payers. We also note that our FIP allows for any of
the six units to switch to natural gas within five years of this final
action instead of installing the control technology.

K. Comments Arguing Our Proposal Would Help the Economy

    Comments: We also received comments that the proposed FIP would
help the economy in a variety of ways. One commenter stated that
environmental regulations like the RHR improve the economy and create
jobs; and industry always finds a way to manage the cost of
implementation. One commenter states that cleaner air will boost
Oklahoma's productivity and job creation.
    Response: Although, we did not consider the potential positive
benefits to local economics in making our decision today, we do
acknowledge that improved visibility may have a positive impact on
tourism. Also, installing the controls required by the BART
determination on the six units will take three years or longer to
complete. These projects will require well-paid, skilled labor that can
potentially be drawn from the local area, which would seem to benefit
the economy.
    Finally, as we have noted elsewhere in our response to comments,
although our action concerns visibility impairment, this action may
also result in significant improvements in human health. Improved human
health will reduce the healthcare costs and reduce the number of missed
school and work days in the community.

L. Comments on Health and Ecosystem Benefits and Other Pollutants

    Comments: Several commenters state that pollutants that cause
visibility impairment also harm public health. Specifically, commenters
assert the following:
    RH pollutants include NOX, SO2, PM,
ammonia, and sulfuric acid. NOX is a precursor to ground
level ozone, which is associated with respiratory diseases, asthma
attacks, and decreased lung function. NOX also reacts
with ammonia, moisture, and other compounds to form particulates
that can cause and worsen respiratory disease, aggravate heart
disease, and lead to premature death. Similarly, SO2
increases asthma symptoms, leads to increased hospital visits, and
can form particulates that aggravate respiratory and heart diseases
and cause premature death. Both NOX and SO2
cause acid rain. PM can penetrate into the lungs and cause health
problems, such as premature mortality, lung disease, aggravated
asthma, chronic bronchitis, and heart attacks.

    Commenters cite to EPA's estimates that in 2015, full
implementation of the RHR nationally will prevent 1,600 premature
deaths, 2,200 non-fatal heart attacks, 960 hospital admissions, and
over 1 million lost school and work days. The RHR will result in health
benefits valued at $8.4 to $9.8 billion annually. More than 100,000
children and 365,000 adults are diagnosed with asthma in Oklahoma, and
hospitalizations in Oklahoma due to asthma cost roughly $57.9 million
in 2007 alone. Commenters also cite to a Clean Air Task Force finding
that the six units at issue in the proposed rule annually cause
approximately 118 deaths, 181 heart attacks, 2,037 asthma attacks, 86
hospital admissions, 74 cases of chronic bronchitis, and 129 emergency
room visits.
    Some commenters also relay personal stories of the health impacts
on themselves and their families from the emissions at issue. One
commenter is disappointed that the air quality in Oklahoma is so poor
that the ODEQ often warns active adults to avoid prolonged outdoor
exposure. She notes that ozone action days prevent children from
playing outside in the summer. Several children have been hospitalized

due to asthma and other illnesses that the commenters attribute to the
emissions at issue. One commenter contends that many people who are
impacted by this rulemaking are not aware of the rulemaking process, or
their rights under that process. Commenters further state that it is
EPA's responsibility to protect the air quality and prevent these
negative health effects.
    Several commenters also assert that NOX and
SO2 emissions from coal plants harms crops like pecans,
barley, and oats, which puts the livelihoods of local farmers at risk,
impacts the health of those who consume the contaminated food, and
increases the cost of food.
    Some commenters want this rulemaking to address health issues. One
commenter states that, while the RHR was designed to provide redress
for visibility impairment, the BART Guidelines expressly provide for
the consideration of non-air quality environmental impacts in step four
of the five-step BART process. This consideration includes the
environmental impact on human health.
    One commenter states that the power plants have had plenty of time
to change operations to comply, but they have failed to do so. Several
commenters assert that Oklahoma is unable to properly manage water and
air pollution because special interest groups trump science. Another
commenter states that coal pollution is devastating tourism and
wildlife in Oklahoma. One commenter states that cleaner air will
improve the health of its citizens. Some commenters assert that
customers are subsidizing the cost of electricity with their health,
lives, and livelihoods. One commenter stated that the increase in
electricity costs is offset by reducing the healthcare costs to the
community to treat illnesses and deaths caused by air pollution from
the plants. Another commenter points out that power plants are also
built near the most vulnerable and underserved populations in the
state, based on the argument that the plants will bring needed jobs.
One commenter concludes that it is unfair and unethical to hold
citizens hostage to the idea that they must choose between electricity
and good health. Several commenters feel that it is appropriate for
industry to bear the burden of the cost, rather than pass it on to
citizens of the state in the form of healthcare costs. These commenters
are amenable to paying higher electricity rates in exchange for
healthier air and water. Several commenters request that EPA impose the
strongest possible regulation of emissions and enforcement of the CAA.
    Another commenter notes that President Nixon created EPA to protect
the environment and the CAA was passed to protect air quality in our
national parks and wilderness areas. President Reagan's acid rain
program cost less than industry or EPA estimated; and hopefully,
installing scrubbers on these coal plants will also cost less than
estimated. Further, the CAA allows EPA to limit sulfur oxides, nitrogen
dioxides, organic compounds, and particulates to ensure the quality of
the air in the region. Several commenters state that coal pollutes
throughout the process during extraction, burning, and disposal. One
commenter states that the true cost of coal is the cost of its
transportation, remediation of coal pollution, and lost tourism and bad
public relations in states where coal production occurs through
mountaintop removal. Many commenters recommend that Oklahoma convert to
more efficient sources of energy such as natural gas, wind, and solar
power.
    One commenter asserts that he suffered from severe childhood asthma
caused by allergies before the coal-fired power plants were built. He
states that affordable electricity from the plants allows him to keep
his windows closed, thereby preventing allergens from entering his
home.
    Response: We appreciate the commenters' concerns regarding the
negative health impacts of emissions from the six units at issue. We
agree that the same NOX emissions that cause visibility
impairment also contribute to the formation of ground-level ozone,
which has been linked with respiratory problems, aggravated asthma, and
even permanent lung damage. We also agree that SO2 emissions
that cause visibility impairment also contribute to increased asthma
symptoms, lead to increased hospital visits, and can form particulates
that aggravate respiratory and heart diseases and cause premature
death; and that both NOX and SO2 cause acid rain.
We agree that the same PM emissions that cause visibility impairment
can be inhaled deep into lungs, which can cause respiratory problems,
decreased lung function, aggravated asthma, bronchitis, and premature
death. We agree that these pollutants can have negative impacts on
plants and ecosystems, damaging plants, trees, and other vegetation,
and reducing forest growth and crop yields, which could have a negative
effect on species diversity in ecosystems. Therefore, although our
action concerns visibility impairment, we note the potential for
significant improvements in human health and the ecosystem.
    The CAA states that the non-air quality environmental impacts of
compliance are a consideration in determining BART. See CAA Section
169A(g)(2). The BART Guidelines allow for the consideration of non-air
quality environmental impacts under 40 CFR 51, Appendix Y(IV)(D)(j).
See also, 70 FR 39104, at 39169. However, this BART factor generally is
considered in order to determine if a control option that is otherwise
technically feasible should be eliminated due to adverse environmental
impacts. Such impacts could include solid or hazardous waste generation
and discharges of polluted water as a result of the control device.
Although we may note potential health benefits from the reduction of
air pollutants due to the installation of a BART control, we do not
consider them as part of the BART determination. While we received many
comments concerning health impacts from the ongoing operations of BART-
eligible sources, we received no comments asserting that dry and wet
scrubbers should be differentiated or eliminated as compliance options
based on non-air quality environmental impacts.
    Although we appreciate the commenters' encouragement that we adopt
even stricter standards, after considering all the comments we
received, as we have stated elsewhere in this notice, we believe that
the standards proposed in our proposal establish BART and will prevent
visibility impairment from the six units.
    Issues that the commenters raise about the effect of EPA's action
on the cost of electricity are addressed elsewhere in this notice.
Additionally, comments that recommend that the six units switch to
natural gas or other sources of renewable energy are addressed
elsewhere in this notice.
    Comments: Several commenters note that coal-plant emissions contain
other toxins including mercury, lead, cadmium, chromium, dioxins,
formaldehyde, arsenic, radioactive isotopes, oxide, and radon gas.
Another commenter is concerned that the toxicity of the pollutants in
regional haze is higher in close proximity to the source of emissions.
    Specifically, several commenters state that poor reclamation of
coal ash from AEP's Shady Point power plant causes negative health
impacts in Bokoshe, Oklahoma. These commenters are concerned about the
health effects of fly ash because they state it contains arsenic,
mercury, lead, cadmium, and other toxins. They describe the project as
consisting of transporting coal ash from the plant to an abandoned lead
mine in Bokoshe. Commenters claim

that the result is a fifty foot wall of toxic coal ash at the
reclamation site in Bokoshe. Commenters state that pollution from the
reclamation project has damaged property and people's health. They
state that fugitive emissions from the trucks and the reclamation site
run off into the ground water, polluting drinking water supplies. One
commenter also states that fly ash has been used in Oklahoma as repair
material for county roads. Commenters state that sixteen to twenty
families living nearby have cancer, children have asthma, and calves in
the area are stillborn. One commenter states that EPA's proposal to put
scrubbers on the units at issue will help address asthma, but these
scrubbers will cause emissions of toxic fly ash.
    Several commenters are concerned that the mercury, chromium, and
arsenic from the coal-fired power plants are contaminating food,
primarily fish. One commenter contends that these chemicals are
carcinogenic and bioaccumulate. As a result, they state, some fish in
Oklahoma have high levels of toxic materials and cannot be consumed.
Commenters note that mercury contamination is so extreme that larger
fish species are unsafe for pregnant women to eat. One commenter states
that mercury is a neurotoxin that negatively affects a child's ability
to talk, walk, read, and learn. Several commenters point out that ODEQ
has issued advisories that prohibit eating fish from certain lakes
because the mercury content is dangerously high. One commenter further
states that sixteen out of fifty of the lakes in Oklahoma have elevated
levels of mercury.
    Response: Although we appreciate the commenters' concerns regarding
the potential negative health impacts from toxic emissions from the six
units at issue, we note that we are not quantifying any toxic emissions
that may be emitted, and such emissions are not considered to be
visibility impairing pollutants. Therefore, consideration of the toxic
emissions is outside the scope of this rulemaking under the RHR.
However, please note that other provisions of the CAA, as well as other
environmental statutes and regulations address toxic emissions, such as
the ones noted here. EPA implements such programs to protect human
health and the environment from the negative impacts of these
pollutants, and Oklahoma's SIP is required to include provisions
consistent with these Federal requirements to the extent that they are
applicable.
    Comment: One commenter mentions the impacts of the transport of
emissions from existing and planned coal plants in Texas, stating that
sixty percent of mercury pollution in Oklahoma comes from Texas. He
requests that EPA accelerates mercury testing in Oklahoma's land and
lakes.
    Response: While we understand the commenter's concern with the
impacts of transport emission from Texas on water bodies in Oklahoma,
mercury testing of water bodies is outside the scope of our action.
Mercury is not considered a visibility impairing pollutant; it is an
air toxic regulated under CAA requirements that are distinct from the
RHR and CAA section 110(a)(2)(D)(i)(II).
    Comments: Several commenters discuss the impact of coal power on
climate change. One commenter also notes that we should regulate
CO2 because ninety-seven percent of scientists agree that it
is causing climate change. He contends that coal fired power plants are
contributing to climate change, stating that the CO2 level
has risen from 280 ppm during the pre-industrial age to 380 ppm today.
He cites the IPCC and others who state that the CO2 level
should not exceed 350 ppm. He also discusses the increasing
temperatures and potential for sea level rise in the near future. The
commenter states that we need to address climate change now.
    Response: While we understand the commenters' concerns with respect
to climate change, consideration of climate change is outside the scope
of our action on the RHR. While CO2 is a greenhouse gas
(GHG), it is not considered a visibility impairing pollutant. However,
EPA implements regulations that address GHGs in order to protect the
public and the environment from the negative impacts of climate change.
Additionally, Oklahoma's SIP is required to include provisions
consistent with those Federal requirements.

M. Miscellaneous Comments

    Comment: OG&E states that we found a defect in Oklahoma's Long Term
Strategy (LTS) because CENRAP modeling assumed the presumptive
SO2 BART limit (0.15 lb/mmBtu) for OG&E's Sooner and
Muskogee facilities, which was not secured by Oklahoma in its SIP. OG&E
states we reasoned that the proposed FIP was necessary to cure these
defects. OG&E asserts we may not pre-determine the BART SO2
emissions limit based on assumptions made during regional modeling, but
the emissions limit should be determined based on the five statutory
factors as applied to an individual facility.
    Further, OG&E states our reasoning with respect to the Oklahoma LTS
is in error. When setting reasonable progress goals for their own Class
I areas, OG&E states, the states are authorized to consider the same
five statutory factors that are used in determining BART, including the
costs of additional controls. OG&E states that Oklahoma did not specify
additional SO2 controls for the Sooner and Muskogee units as
part of Oklahoma's LTS for the Wichita Mountains. OG&E notes that for
Class I areas in other states, a state must ensure that it has included
in its LTS all measures needed to achieve its apportionment of emission
reduction obligations agreed upon through the regional planning
process. 40 CFR 51.308(d)(2)(ii). OG&E states that ODEQ found that its
LTS required no further controls for Oklahoma sources because emissions
from Oklahoma were found (through the regional planning process) to
impair visibility at all relevant Class I areas other than Wichita
Mountains only insignificantly. Thus, OG&E reasons, the Oklahoma LTS is
consistent with the agreements reached during regional planning. OG&E
states we failed to justify, or explain, our basis for assuming that
the regional planning process would have come to a different conclusion
concerning Oklahoma's impact on other states' Class I areas if a
different SO2 emission rate had been assumed for the Sooner
and Muskogee units in question.
    Response: We disagree with OG&E's assertion that Oklahoma's
decision not to require controls for the six OG&E and AEP/PSO units is
consistent with the RH requirements for the LTS, section
51.308(d)(3)(ii), which requires:

    Where other States cause or contribute to impairment in a
mandatory Class I Federal area, the State must demonstrate that it
has included in its implementation plan all measures necessary to
obtain its share of the emission reductions needed to meet the
progress goal for the area. If the State has participated in a
regional planning process, the State must ensure it has included all
measures needed to achieve its apportionment of emission reduction
obligations agreed upon through that process.

    Oklahoma did engage in a regional planning process. This regional
planning process included a forum in which state representatives built
emission inventories that assumed that specific pollution sources would
be controlled to specific levels. This included assumptions that the
six OG&E and AEP/PSO units would be controlled to presumptive BART
emission levels for SO2. Visibility modeling projections
subsequently assumed those emission reductions. However, Oklahoma, in
its

subsequent RH SIP, did not include these promised reductions on which
the other states are presently relying.
    We note the CENRAP RPO process was open and representatives from
industry occasionally attended CENRAP meetings and had an opportunity
to engage in this process. ODEQ engaged in consultations under
51.308(d)(3)(i), which requires that where the State has emissions that
are reasonably anticipated to contribute to visibility impairment in
any mandatory Class I Federal area located in another State or States,
the State must consult with the other State(s) in order to develop
coordinated emission management strategies. The State must consult with
any other State having emissions that are reasonably anticipated to
contribute to visibility impairment in any mandatory Class I Federal
area within the State.
    All states that engaged in these consultations were involved in the
discussions leading up to, and the actual construction of the emission
inventories and the modeling strategy. These LTS consultations
therefore assumed OG&E's Sooner and Muskogee sources would be
controlled to the presumptive limit levels and made decisions regarding
whether additional controls to address LTS were needed on that basis.
Thus, we are disapproving Oklahoma's LTS.
    Furthermore, and notwithstanding the above LTS discussion, we
disagree with OG&E's assertion that our BART analysis of the six OG&E
and AEP/PSO units is due to the CENRAP modeling. As we discussed in our
proposal, we arrived at our proposed BART determination for the six
units in question after performing the BART analysis required under the
RHR.
    Comment: AEP/PSO commented that we should clarify that new
monitoring systems proposed under section 52.1923(e) do not need to be
installed for both Unit 3 and Unit 4 of the Northeastern plant if the
same fuel is used for both units. Instead, they reason, stack emissions
should be apportioned to the units based on unit to stack load ratios.
AEP/PSO claims the equipment necessary to report emissions for each
unit individually will add approximately $250,000 to the cost to
comply, and provides no better data on emissions to the atmosphere.
    Response: We are affirming that we are in fact requiring that the
monitoring described in section 52.1923(e) must be installed separately
for each of Units 3 and 4 of the AEP/PSO Northeastern plant even though
the same fuel is used for both units. We do not find that it is proper
to calculate the emissions of each unit based on its load ratio, as
individual SO2 scrubbers will likely have slightly different
performance characteristics and we need to ensure that both units'
scrubbers are working properly by monitoring the emissions unit by
unit.
    Comment: AEP/PSO believes there is a conflict between the language
in section 52.1923(d) and (e). Section 52.1923(d) states that if a
valid SO2 pounds per hour or heat input is not available for
any hour for a unit, that heat input and SO2 pounds per hour
shall not be used in the calculation of the 30-day rolling average for
SO2.
    Section 52.1923(e) states that when valid SO2 pounds per
hour, or SO2 pounds per million Btu emission data are not
obtained because of continuous monitoring system breakdowns, repairs,
calibration checks, or zero and span adjustments, emission data must be
obtained by using other monitoring systems approved by the EPA to
provide emission data for a minimum of 18 hours in each 24 hour period
and at least 22 out of 30 successive boiler operating days.
    Response: We do not see a conflict between the language in sections
52.1923(d) and (e). Paragraph (d) refers to short term, discrete data
acquisition problems and paragraph (e) refers to more serious problems
that may arise due to fundamental underlying problems with the
monitoring system.
    Comment: One commenter called for an integrated and comprehensive
strategy for EGUs to meet CAA requirements, noting that EGU emissions
are subject to the RHR, the PM2.5 NAAQS, and the National
Emissions Standards for Hazardous Air Pollutants. The commenter stated
that to effectively address impacts to human health and RH caused by
EGU emissions, the FIP or SIP should require (1) SCR to control
NOX, (2) wet scrubbers to control SO2, and (3)
wet electrostatic precipitators to control condensable particulate
matter and acid mists. The commenter also asked us to reconsider our
proposal to accept ODEQ's NOX BART determination, because
(1) according to our proposal additional NOX reductions
would achieve significant improvement in visibility over baseline, (2)
Nitrate particulates from EGUs are primarily responsible for the
majority of visibility impairment during winter days, and (3) the full
benefit of wet scrubber controls may not be achieved unless BART
controls on NOX is also required. Concerning SO2,
the commenter expressed concern that the proposal would ``approve'' a
dry scrubber system, along with an older electrostatic precipitator at
the OG&E Sooner facility that would achieve poor control of
PM2.5 emissions. The commenter added that the proposed rule
does not provided adequate information to allow the public to
understand and compare control measures or to comprehend the extent of
underperformance of PM2.5 controls.
    Another commenter requested additional controls and monitoring for
ammonia and sulfuric acid. Specifically the commenter (1) requested
that we set emission limits for ammonia and sulfuric acid mist, similar
to those proposed for the San Juan Generating Station in New Mexico (76
FR 491), (2) stated their support for requiring continuous emissions
monitors to monitor ammonia, and (3) urged us to require stack testing
for sulfuric acid on a more frequent basis than annual monitoring.
    Response: The purpose of our plan is to address the CAA BART
requirements. Our evaluation found that:
     The NOX controls adopted by the state meet the
CAA BART requirements;
     The SO2 BART controls we proposed in our FIP,
in addition to the state adopted NOX controls, would lead to
significant improvement in visibility and meet the CAA BART
requirements;
     Additional NOX controls would not be cost
effective; and
     Additional pollutant controls are not needed to meet the
CAA BART requirements.
    Regarding the request for ammonia and sulfuric acid mist emission
limits and monitoring, we did propose ammonia and sulfuric acid limits
and monitoring, as part of our New Mexico RH FIP for the San Juan
Generating Station. 76 FR 491. We did this because we were concerned
about the potential for ammonia slip, as a result of the operation of
Selective Catalytic Reduction (SCR), and the potential for the growth
in sulfuric acid emissions if they were not limited in an enforceable
manner. As explained in our response to comments in that action, we
ultimately determined that neither an ammonia limit, nor ammonia
monitoring was warranted.\29\ We did, however, limit sulfuric acid
emissions, verified by annual stack testing due to the potential for
visibility impairment from increased sulfuric acid emissions associated
with operation of SCR. These issues are not applicable here, as our
BART FIP is concerned with the reduction of SO2, which is
not controlled by SCR, and our visibility modeling does not indicate
the

need to control or monitor sulfuric acid or ammonia emissions.
---------------------------------------------------------------------------

    \29\ 76 FR 52388, at 52407.
---------------------------------------------------------------------------

    Comment: One commenter stated that by mandating scrubbers on coal
plants that we are trying to phase out does not make sense. Another
commenter asked why switching to low sulfur coal is not considered a
viable alternative instead of mandating installation of expensive wet
gas scrubbers. A third commenter stated that the EPA continues to bog
down electricity producers with burdensome paperwork and legal
uncertainty and that the EPA RHR is a perfect example of the EPA's lack
of economic reality.
    Response: We are not attempting to phase out the Oklahoma coal
plants that are subject to our FIP. The purpose of our FIP is to
control SO2 emissions from six Oklahoma EGUs that contribute
to RH in order to meet the CAA BART requirements. To that end we are
setting emissions limits for SO2. We are not requiring
certain control technologies or fuel sources. As discussed earlier, we
used the CAA's BART evaluation criteria for our plan and found that it
is reasonable and realistic. The paperwork required will ensure
compliance with the BART FIP.
    Comment: One commenter expressed his view that citizens should ask
EPA to set and enforce regulations for haze because the state
regulations were inadequate. Another commenter stated that we should
reject lower standards suggested by others.
    Response: We agree with the commenter that Oklahoma's RH SIP was
inadequate in its control of SO2 from the six OG&E and AEP/
PSO units. We find that our FIP will require the proper amount of
SO2 control in order to comply with the RHR.
    Comment: A request was submitted that we hold a public hearing on
our proposal in Tulsa, Oklahoma.
    Response: Originally we scheduled one public hearing in Oklahoma
City. In response to the request we added a second hearing in Tulsa on
April 14, 2011. The transcripts of both public hearings are available
in the docket.
    Comment: One commenter asked us to work with ODEQ and the
electrical power providers to develop a cost effective plan.
    Response: We find that the SO2 controls required by our
FIP are, for the reasons discussed elsewhere in our response to
comments and Supplemental RTC, cost effective. We are, however, willing
to work with ODEQ and others to develop a SIP that could replace our
FIP. Such a SIP will need to meet the CAA and EPA's RH regulations and
be consistent with EPA's guidance.
    Comment: One commenter supported our proposal's (1) determination
that Oklahoma's SO2 BART limits do not meet the RH
regulations, (2) analysis of the visibility improvement resulting from
BART controls, (3) determination that low NOX burners are
appropriate as BART, and (4) determination that existing electrostatic
precipitators and a 0.1 lbs/MMBtu emissions limit is appropriate as
BART for particulate matter.
    Response: We appreciate the comments.
    Comment: Comments were received expressing concern over other
sources of air pollution, such as landfills, coal-fired power plants,
the Tar Creek superfund site and sources in Texas.
    Response: While we understand the commenter's concern with the
impacts of other sources of pollution, the scope of this action is
limited to assessing whether certain elements of the Oklahoma RH SIP
meet the RH requirements of the CAA, including BART, and addressing any
deficiencies identified. We note also that other state and federal
statutes and regulations address other sources of air pollution, such
as those referenced by the commenters, to protect human health and the
environment from the negative impacts of these pollutants.
    Comment: Two commenters provided questions at the Oklahoma City
public hearing. Several questions relate to Class 1 areas, such as:
designation of Class 1 areas; location of Class 1 areas in relation to
the six units and other coal-fired units; frequency, degree, and season
of visibility impact in Class 1 areas; and tourism at the Class 1
areas. Other questions concern cost of compliance by the six units,
such as: annual and total cost; cost and benefit analysis of comparing
the cost of compliance to ``visitor impact days''; economic impacts to
the region; and EPA's authority to implement the FIP. Finally, some
questions concern the Wichita Wildlife Refuge specifically and
contemplate sources of haze impacting that Class 1 area, other than the
six units.
    Response: In general, answers to these questions are: (1) Found in
our proposal or in supporting documents for our proposal, (2) furnished
in response to other comments, or (3) not a necessary or relevant
consideration for our action. For responses to these comments, please
see the ``Addendum Responding to Questions Received'' available in the
electronic docket for this rulemaking.
    Comment: We received comments not related to the proposal. These
included comments on:
     Enforcement by EPA and ODEQ;
     A RH educational plan;
     Emissions from the LaFarge cement company; and
     Eliminating coal as a source of energy.
    Response: While these and other comments may be important topics
for discussion, we are not addressing these topics as they are outside
the scope of our rulemaking.

IV. Statutory and Executive Order Reviews

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

    This action finalizes a source-specific FIP for six units at coal-
fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E
Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3
and 4). This type of action is exempt from Executive Orders 12866 (58
FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Burden is defined at 5 CFR 1320.3(b). Under the Paperwork Reduction
Act, a ``collection of information'' is defined as a requirement for
``answers to * * * identical reporting or recordkeeping requirements
imposed on ten or more persons * * * .'' 44 U.S.C. 3502(3)(A). Because
the FIP only applies to six units at three power plants (OG&E Sooner
Plant, OG&E Muskogee Plant, and AEP/PSO Northeastern Plant) the
Paperwork Reduction Act does not apply. See 5 CFR 1320(c).

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a

city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this action on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The FIP for
the OG&E Sooner Plant, the Muskogee Plant, and the AEP/PSO Northeastern
Plant being finalized today does not impose any new requirements on
small entities. See Mid-Tex Electric Cooperative, Inc. v. FERC, 773
F.2d 327 (D.C. Cir. 1985).

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires Federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments and the private sector. This rule
does not contain a Federal mandate that may result in expenditures of
$100 million or more, adjusted for inflation, for state, local, and
tribal governments, in the aggregate, or the private sector in any one
year. Our cost estimate indicates that the total annual cost of
compliance with this rule is below this threshold. Thus, this rule is
not subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. This rule contains
regulatory requirements that apply only to six units at coal-fired
power plants in Oklahoma (OG&E Sooner Plant Units 1 and 2, OG&E
Muskogee Plant Units 4 and 5, and AEP/PSO Northeastern Plant Units 3
and 4).

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action merely prescribes EPA's
action to address the state not fully meeting its obligation to
prohibit emissions from interfering with other states measures to
protect visibility. Thus, Executive Order 13132 does not apply to this
action. In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and state and local
governments, EPA specifically solicited comment on the proposed rule
from state and local officials.

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

    This final action does not have tribal implications, as specified
in Executive Order 13175 (65 FR 67249, November 6, 2000), because the
action EPA is taking neither imposes substantial direct compliance
costs on tribal governments, nor preempts tribal law. Therefore, the
requirements of section 5(b) and 5(c) of the Executive Order do not
apply to this rule. Consistent with EPA policy, EPA nonetheless
provided outreach to Oklahoma Tribes on several occasions in March and
April 2011, and offered consultation regarding this action. EPA did not
receive any requests for consultation on this rule.

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

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it implements specific standards established by Congress
in statutes.

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

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

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards. This rule would
require the affected units at the OG&E Sooner Plant, the Muskogee
Plant, and the AEP/PSO Northeastern Plant to meet the applicable
monitoring requirements of 40 CFR part 75. Part 75 already incorporates
a number of voluntary consensus standards. Consistent with the Agency's
Performance Based Measurement System (PBMS), Part 75 sets forth
performance criteria that allow the use of alternative methods to the
ones set forth in Part 75. The PBMS approach is intended to be more
flexible and cost effective for the regulated community; it is also
intended to encourage innovation in analytical technology and improved
data quality. At this time, EPA is not recommending any revisions to
Part 75; however, EPA periodically revises the test procedures set
forth in Part 75. When EPA revises the test procedures set forth in
Part 75 in the future, EPA will address the use of any new voluntary
consensus standards that are equivalent. Currently, even if a test
procedure is not set forth in Part 75, EPA is not precluding the use of
any method, whether it constitutes a voluntary consensus standard or
not, as long as it meets the performance criteria specified; however,
any alternative methods must be approved through the petition process
under 40 CFR 75.66 before they are used.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it increases the level of environmental
protection for all affected populations without having any
disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. Our FIP limits emissions of SO2 from six units
at coal-fired power plants in Oklahoma (OG&E Sooner Plant Units 1 and
2, OG&E Muskogee Plant Units 4

and 5, and AEP/PSO Northeastern Plant Units 3 and 4). In addition to
our FIP, we also approve SIP elements that also limit the emission of
other pollutants, including PM and NOX.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on January 27, 2012.

L. Judicial Review

    Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by February 27, 2012. Pursuant to CAA section
307(d)(1)(B), this action is subject to the requirements of CAA section
307(d) as it promulgates a FIP under CAA section 110(c). Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. See CAA section 307(b)(2).

List of Subjects in 40 CFR Part 52

    Air pollution control, Environmental protection, Best available
retrofit technology, Incorporation by reference, Intergovernmental
relations, Interstate transport of pollution, Nitrogen dioxide, Ozone,
Particulate matter, Regional haze, Reporting and recordkeeping
requirements, Sulfur dioxide, Visibility.

    Dated: December 13, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons set out in the preamble, title 40, chapter I, of
the Code of Federal Regulations is amended as follows:

PART 52--[AMENDED]

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

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

Subpart LL--[Amended]

0
2. Section 52.1920 is amended as follows:
0
a. The table in paragraph (c) is amended by adding in sequential order
under ``Subchapter 8. Permits for Part 70 Sources'' a new heading for
part 11 and a new entry for ``(252:100:8-70 to 252:100:8-77)''.
0
b. The first table in paragraph (e) is amended by adding at the end a
new entry for ``Interstate transport for the 1997 ozone and
PM2.5 NAAQS (Noninterference with measures required to
prevent significant deterioration of air quality or to protect
visibility in any other State)'', immediately followed by an entry for
``Regional haze SIP''. ``
0
c. The second table in paragraph (e) entitled ``EPA Approved Statutes
in the Oklahoma SIP'' is amended by removing the entry for ``Interstate
transport for the 1997 ozone and PM2.5 NAAQS.''
    The amendments read as follows:

Sec.  52.1920  Identification of plan.

* * * * *
    (c) * * *

                                        EPA Approved Oklahoma Regulations
----------------------------------------------------------------------------------------------------------------
                                                       State effective
         State citation              Title/subject           date        EPA approval date       Explanation
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
                                    PART 11. Visibility Protection Standards
----------------------------------------------------------------------------------------------------------------
(252:100:8-70 to 252:100:8-77)..  Visibility                6/15/2007   12/28/11 [Insert FR  ...................
                                   Protection                            page number where
                                   Standards.                            document begins]
----------------------------------------------------------------------------------------------------------------

     (e) * * *

            EPA Approved Non-Regulatory Provisions and Quasi-Regulatory Measures in the Oklahoma SIP
----------------------------------------------------------------------------------------------------------------
                                       Applicable
      Name of SIP provision          geographic or     State submittal/  EPA approval date       Explanation
                                   nonattainment area   effective date
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
Interstate transport for the      Statewide..........        5/1/2007   11/26/2010, 75 FR    Noninterference
 1997 ozone and PM2.5 NAAQS                                              72701 12/28/11       with measures
 (Noninterference with measures                                          [Insert citation     required to
 required to prevent significant                                         of publication].     prevent
 deterioration of air quality or                                                              significant
 to protect visibility in any                                                                 deterioration of
 other State).                                                                                air quality in any
                                                                                other State
                                                                                approved 11/26/
                                                                                2010.
                                                                                Noninterference
                                                                                with measures
                                                                                required to
                                                                                protect visibility
                                                                                in any other State
                                                                                partially approved
                                                                                12/28/11.

Regional haze SIP:..............  Statewide..........       2/17/2010   12/28/11 [Insert     Core requirements
(a) Determination of baseline                                            citation of          of 40 CFR 51.308
 and natural visibility                                                  publication].
 conditions.
(b) Coordinating regional haze
 and reasonably attributable
 visibility impairment.
(c) Monitoring strategy and
 other implementation
 requirements.
(d) Coordination with States and
 Federal Land Managers.
(e) BART determinations except
 for the following SO2 BART
 determinations: Units 4 and 5
 of the Oklahoma Gas and
 Electric (OG&E) Muskogee plant;
 Units 1 and 2 of the OG&E
 Sooner plant; and Units 3 and 4
 of the American Electric Power/
 Public Service Company of
 Oklahoma (AEP/PSO) Northeastern
 plant.
----------------------------------------------------------------------------------------------------------------

0
3. Section 52.1923 is added to read as follows:

Sec.  52.1923  Best Available Retrofit Requirements (BART) for
SO2 and Interstate pollutant transport provisions; What are
the FIP requirements for Units 4 and 5 of the Oklahoma Gas and Electric
Muskogee plant; Units 1 and 2 of the Oklahoma Gas and Electric Sooner
plant; and Units 3 and 4 of the American Electric Power/Public Service
Company of Oklahoma Northeastern plant affecting visibility?

    (a) Applicability. The provisions of this section shall apply to
each owner or operator, or successive owners or operators, of the coal
burning equipment designated as: Units 4 or 5 of the Oklahoma Gas and
Electric Muskogee plant; Units 1 or 2 of the Oklahoma Gas and Electric
Sooner plant; and Units 3 or 4 of the American Electric Power/Public
Service Company of Oklahoma Northeastern plant.
    (b) Compliance Dates. Compliance with the requirements of this
section is required within five years of the effective date of this
rule unless otherwise indicated by compliance dates contained in
specific provisions.
    (c) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the CAA and in parts 51 and 60 of
this title. For the purposes of this section:
    24-hour period means the period of time between 12:01 a.m. and 12
midnight.
    Air pollution control equipment includes selective catalytic
control units, baghouses, particulate or gaseous scrubbers, and any
other apparatus utilized to control emissions of regulated air
contaminants that would be emitted to the atmosphere.
    Boiler-operating-day means any 24-hour period between 12:00
midnight and the following midnight during which any fuel is combusted
at any time at the steam generating unit.
    Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
    Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
    Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the coal burning equipment designated
as:

Unit 4 of the Oklahoma Gas and Electric Muskogee plant; or
Unit 5 of the Oklahoma Gas and Electric Muskogee plant; or
Unit 1 of the Oklahoma Gas and Electric Sooner plant; or
Unit 2 of the Oklahoma Gas and Electric Sooner plant; or
Unit 3 of the American Electric Power/Public Service Company of
Oklahoma Northeastern plant; or
Unit 4 of the American Electric Power/Public Service Company of
Oklahoma Northeastern plant.

    Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
    Unit means one of the coal fired boilers covered under Paragraph
(a), above.
    (d) Emissions Limitations.
    SO2 emission limit. The individual sulfur dioxide
emission limit for a unit shall be 0.06 pounds per million British
thermal units (lb/MMBtu) as averaged over a rolling 30 boiler-
operating-day period. For each unit, SO2 emissions for each
calendar day shall be determined by summing the hourly emissions
measured in pounds of SO2. For each unit, heat input for
each boiler-operating-day shall be determined by adding together all
hourly heat inputs, in millions of BTU. Each boiler-operating-day the
thirty-day rolling average for a unit shall be determined by adding
together the pounds of SO2 from that day and the preceding
29 boiler-operating-days and dividing the total pounds of
SO2 by the sum of the heat input during the same 30 boiler-
operating-day period. The result shall be the 30 boiler-operating-day
rolling average in terms of lb/MMBtu emissions of SO2. If a
valid SO2 pounds per hour or heat input is not available for
any hour for a unit, that heat input and SO2 pounds per hour
shall not be used in the calculation of the 30 boiler-operating-day
rolling average for SO2.
    (e) Testing and monitoring.
    (1) No later than the compliance date of this regulation, the owner
or operator shall install, calibrate, maintain and operate Continuous
Emissions Monitoring Systems (CEMS) for SO2 on Units 4 and 5
of the Oklahoma Gas and Electric Muskogee plant; Units 1 and 2 of the
Oklahoma Gas and Electric Sooner plant; and Units 3 and 4 of the
American Electric Power/Public Service Company of Oklahoma Northeastern
plant in accordance with 40 CFR 60.8 and 60.13(e), (f), and (h), and
Appendix B of Part 60. The owner or operator shall comply with the
quality assurance procedures for CEMS found in 40 CFR part 75.
Compliance with the emission

limits for SO2 shall be determined by using data from a
CEMS.
    (2) Continuous emissions monitoring shall apply during all periods
of operation of the coal burning equipment, including periods of
startup, shutdown, and malfunction, except for CEMS breakdowns,
repairs, calibration checks, and zero and span adjustments. Continuous
monitoring systems for measuring SO2 and diluent gas shall
complete a minimum of one cycle of operation (sampling, analyzing, and
data recording) for each successive 15-minute period. Hourly averages
shall be computed using at least one data point in each fifteen minute
quadrant of an hour. Notwithstanding this requirement, an hourly
average may be computed from at least two data points separated by a
minimum of 15 minutes (where the unit operates for more than one
quadrant in an hour) if data are unavailable as a result of performance
of calibration, quality assurance, preventive maintenance activities,
or backups of data from data acquisition and handling system, and
recertification events. When valid SO2 pounds per hour, or
SO2 pounds per million Btu emission data are not obtained
because of continuous monitoring system breakdowns, repairs,
calibration checks, or zero and span adjustments, emission data must be
obtained by using other monitoring systems approved by the EPA to
provide emission data for a minimum of 18 hours in each 24 hour period
and at least 22 out of 30 successive boiler operating days.
    (f) Reporting and Recordkeeping Requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required by this section
shall be submitted, unless instructed otherwise, to the Director,
Multimedia Planning and Permitting Division, U.S. Environmental
Protection Agency, Region 6, to the attention of Mail Code: 6PD, at
1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733. For each unit
subject to the emissions limitation in this section and upon completion
of the installation of CEMS as required in this section, the owner or
operator shall comply with the following requirements:
    (1) For each emissions limit in this section, comply with the
notification, reporting, and recordkeeping requirements for CEMS
compliance monitoring in 40 CFR 60.7(c) and (d).
    (2) For each day, provide the total SO2 emitted that day
by each emission unit. For any hours on any unit where data for hourly
pounds or heat input is missing, identify the unit number and
monitoring device that did not produce valid data that caused the
missing hour.
    (g) Equipment Operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
    (h) Enforcement.
    (1) Notwithstanding any other provision in this implementation
plan, any credible evidence or information relevant as to whether the
unit would have been in compliance with applicable requirements if the
appropriate performance or compliance test had been performed, can be
used to establish whether or not the owner or operator has violated or
is in violation of any standard or applicable emission limit in the
plan.
    (2) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
0
4. Section 52.1928 is added to read as follows:

Sec.  52.1928  Visibility protection.

    (a) The following portions of the Oklahoma Regional Haze (RH) State
Implementation Plan submitted on February 19, 2010 are disapproved:
    (1) The SO2 BART determinations for Units 4 and 5 of the
Oklahoma Gas and Electric (OG&E) Muskogee plant; Units 1 and 2 of the
OG&E Sooner plant; and Units 3 and 4 of the American Electric Power/
Public Service Company of Oklahoma (AEP/PSO) Northeastern plant;
    (2) The long-term strategy for regional haze;
    (3) ``Greater Reasonable Progress Alternative Determination''
(section VI.E), and
    (4) Separate executed agreements between ODEQ and OG&E, and ODEQ
and AEP/PSO entitled ``OG&E Regional Haze Agreement, Case No. 10-024,
and ``PSO Regional Haze Agreement, Case No. 10-025,'' housed within
Appendix 6-5 of the RH SIP.
    (b) The portion of the State Implementation Plan pertaining to
adequate provisions to prohibit emissions from interfering with
measures required in another state to protect visibility, submitted on
May 10, 2007 and supplemented on December 10, 2007 is disapproved.
    (c) The SO2 BART requirements for Units 4 and 5 of the
Oklahoma Gas and Electric (OG&E) Muskogee plant; Units 1 and 2 of the
OG&E Sooner plant; and Units 3 and 4 of the American Electric Power/
Public Service Company of Oklahoma (AEP/PSO) Northeastern plant, the
deficiencies in the long-term strategy for regional haze, and the
requirement for a plan to contain adequate provisions to prohibit
emissions from interfering with measures required in another state to
protect visibility are satisfied by Sec.  52.1923.

[FR Doc. 2011-32572 Filed 12-27-11; 8:45 am]
BILLING CODE 6560-50-P