[Federal Register Volume 77, Number 237 (Monday, December 10, 2012)]
[Proposed Rules]
[Pages 73369-73386]
[FR Doc No: 2012-29764]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R04-OAR-2010-0935, FRL-9760-5]

Approval and Promulgation of Air Quality Implementation Plans;
State of Florida; Regional Haze State Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to approve certain Best Available Retrofit
Technology (BART) and reasonable progress determinations included in a
regional haze state implementation plan (SIP) amendment submitted by
the State of Florida, through the Florida Department of Environmental
Protection (FDEP), on September 17, 2012. These BART and reasonable
progress determinations are for sources that are subject to the Clean
Air Interstate Rule (CAIR) and were initially included in a July 31,
2012, draft regional haze SIP amendment submitted by FDEP for parallel
processing and re-submitted in final form as part of the State's
September 17, 2012, regional haze SIP amendment. In this action, EPA
also proposes to find that Florida's September 17, 2012, amendment
corrects the deficiencies that led to the proposed May 25, 2012,
limited approval and proposed December 30, 2011, limited disapproval of
the State's entire regional haze SIP, and that Florida's SIP meets all
of the regional haze requirements of the Clean Air Act (CAA). EPA is
therefore withdrawing the previously proposed limited disapproval of
Florida's entire regional haze SIP and proposing full approval. This
proposed action supplements the May 25, 2012, proposed limited approval
action by superseding the proposed limited approval and replacing it
with a proposed full approval. EPA will take final action on

the May 25, 2012, proposal, as supplemented herein, in conjunction with
final action on today's proposal.

DATES: Comments must be received on or before January 9, 2013.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R04-
OAR-2010-0935, by one of the following methods:
    1. www.regulations.gov: Follow the on-line instructions for
submitting comments.
    2. Email<EMAIL_ADDRESS>    3. Fax:<PHONE_NUMBER>.
    4. Mail: EPA-R04-OAR-2010-0935, Regulatory Development Section, Air
Planning Branch, Air, Pesticides and Toxics Management Division, U.S.
Environmental Protection Agency, Region 4, 61 Forsyth Street SW.,
Atlanta, Georgia 30303-8960.
    5. Hand Delivery or Courier: Lynorae Benjamin, Chief, Regulatory
Development Section, Air Planning Branch, Air, Pesticides and Toxics
Management Division, U.S. Environmental Protection Agency, Region 4, 61
Forsyth Street SW., Atlanta, Georgia 30303-8960. Such deliveries are
only accepted during the Regional Office's normal hours of operation.
The Regional Office's official hours of business are Monday through
Friday, 8:30 to 4:30, excluding federal holidays.
    Instructions: Direct your comments to Docket ID No. ``EPA-R04-OAR-
2010-0935.'' EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit through
www.regulations.gov or email, information that you consider to be CBI
or otherwise protected. The www.regulations.gov Web site is an
``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an email comment directly to EPA without
going through www.regulations.gov, your email address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses. For additional information about EPA's public
docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
    Docket: All documents in the electronic docket are listed in the
www.regulations.gov index. Although listed in the index, some
information is not publicly available, i.e., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy form. Publicly available docket
materials are available either electronically in www.regulations.gov or
in hard copy at the Regulatory Development Section, Air Planning
Branch, Air, Pesticides and Toxics Management Division, U.S.
Environmental Protection Agency, Region 4, 61 Forsyth Street SW.,
Atlanta, Georgia 30303-8960. EPA requests that if at all possible, you
contact the person listed in the FOR FURTHER INFORMATION CONTACT
section to schedule your inspection. The Regional Office's official
hours of business are Monday through Friday, 8:30 to 4:30, excluding
federal holidays.

FOR FURTHER INFORMATION CONTACT: Michele Notarianni, Regulatory
Development Section, Air Planning Branch, Air, Pesticides and Toxics
Management Division, U.S. Environmental Protection Agency, Region 4, 61
Forsyth Street SW., Atlanta, Georgia 30303-8960. Michele Notarianni can
be reached at telephone number<PHONE_NUMBER> and by electronic mail at
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

I. What Action is EPA Proposing to Take?
II. Summary of Florida's September 17, 2012, Regional Haze SIP
Amendment
III. What is EPA's Analysis of Florida's September 17, 2012,
Regional Haze SIP Amendment?
IV. What Action is EPA Taking?
V. Statutory and Executive Order Reviews

I. What Action is EPA Proposing to Take?

    On March 19, 2010, FDEP submitted a regional haze SIP to address
regional haze in Class I areas impacted by emissions from Florida and
subsequently amended this SIP submittal on August 31, 2010. EPA
proposed a limited disapproval of the Florida regional haze SIP on
December 30, 2011, because of deficiencies in the regional haze SIP
arising from the State's reliance on CAIR to meet certain regional haze
requirements. See 76 FR 82219 (December 30, 2011). On May 25, 2012, EPA
published an action proposing a limited approval of Florida's regional
haze SIP to address the first implementation period. See 77 FR 31240.
EPA's May 25, 2012, proposed rulemaking covered Florida's March 19,
2010, regional haze SIP and August 31, 2010, regional haze SIP
amendment, as well as the State's April 13, 2012, draft regional haze
SIP amendment which was submitted for parallel processing. The regional
haze SIP, as amended on August 31, 2010, and April 13, 2012, addressed
many of the regional haze requirements for Florida under CAA sections
301(a) and 110(k)(3). EPA proposed a limited approval, rather than a
full approval, of Florida's regional haze SIP to the extent that it
relied on CAIR.
    On July 31, 2012, FDEP submitted an additional draft regional haze
SIP amendment to evaluate BART and reasonable progress provisions for
the remaining electric generating units (EGUs) not addressed in its
April 13, 2012, draft SIP amendment.\1\ On September 17, 2012, Florida
submitted a final SIP amendment that consolidated the proposed changes
in the April 13, 2012, and July 31, 2012, draft SIP amendments
originally submitted to EPA for parallel processing. This

submittal addressed BART and reasonable progress requirements for
certain EGUs where Florida had relied on CAIR to meet BART and
reasonable progress regulatory requirements for these units and made
changes to the text of its SIP to remove reliance on CAIR for Florida
sources. On November 29, 2012 (77 FR 71111), EPA took final action
fully approving the unit-specific BART determinations for all of the
sources addressed by EPA's May 25, 2012, proposal.
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    \1\ In the draft SIP amendment provided on July 31, 2012,
Florida addressed the 18 reasonable progress units and 11 facilities
with BART-eligible EGUs subject to CAIR (a total of 20 EGUs) that
were not covered by Florida's April 13, 2012, SIP amendment, and it
also amended the SIP to remove Florida's reliance on CAIR to satisfy
BART and reasonable progress requirements for the State's affected
EGUs. Florida proposed these determinations in the July 31, 2012,
proposed amendment and finalized them in the September 17, 2012,
final SIP amendment. The facilities addressed for reasonable
progress are: City of Gainesville Deerhaven unit 5; Florida Power &
Light (FPL) Manatee units 1, 2; FPL Turkey Point units 1, 2; Gulf
Power Company Crist unit 7; Lakeland Electric C.D. McIntosh unit 3;
JEA Northside/St. Johns River Power Park (SJRPP) units 3, 16, 17;
Progress Energy Florida (PEF) Anclote units 1, 2; PEF Crystal River
units 1, 2, 3, 4; and Seminole Electric Cooperative, Inc. (SECI)
units 1, 2. The facilities addressed for BART are: City of
Tallahassee--Arvah B.Hopkins Generating Station (unit 1); PEF
Anclote Power Plant (units 1, 2); PEF Crystal River Power Plant
(units 1, 2); FP&L Manatee Power Plant (units 1, 2); FPL Martin
Power Plant (units 1, 2); FPL Turkey Point Power Plant (units 1, 2);
Gulf Power Company Crist Electric Generating Plant (units 6, 7);
Gulf Power Company Lansing Smith Plant (units 1, 2); JEA Northside
SJRPP (unit 3); Lakeland Electric C.D. McIntosh, Jr. Power Plant
(units 1, 2); and Reliant Energy Indian River (units 2, 3).
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    EPA's December 30, 2011, proposed limited disapproval of Florida's
regional haze SIP was based on the State's initial reliance on CAIR to
satisfy both BART requirements and the requirement for a long-term
strategy (LTS) sufficient to achieve the state-adopted reasonable
progress goals (RPGs). See 76 FR 82221. As mentioned above, Florida's
September 17, 2012, SIP amendment replaced reliance on CAIR to satisfy
the BART and reasonable progress requirements for its affected EGUs
with case-by-case BART and reasonable progress control analyses. To the
extent that the SIP's underlying emissions inventories and projections
of emissions reductions from upwind states are affected by the
implementation of CAIR, the recent decision by the United States Court
of Appeals for the District of Columbia Circuit (D.C. Circuit) in EME
Homer Generation, L.P. v. EPA, No. 11-1302 (D.C. Cir., August 21, 2012)
(EME Homer) to vacate the Cross-State Air Pollution Control Rule
(Transport Rule) and keep CAIR in place ensures that any emissions
reductions associated with CAIR are sufficiently permanent and
enforceable for purposes of this action (see section III.C, below, for
further discussion).
    EPA is now proposing to take two related actions. First, EPA is
proposing to approve the remaining BART and reasonable progress
determinations in Florida's September 17, 2012, regional haze SIP
amendment not previously addressed in EPA's November 29, 2012, final
action.\2\ Second, EPA is proposing to find that Florida's September
17, 2012, SIP amendment corrects the deficiencies that led to the
December 30, 2011, proposed limited disapproval and the May 25, 2012,
limited approval of the State's regional haze SIP and that the regional
haze SIP as a whole now meets the regional haze requirements of the
CAA. EPA is therefore withdrawing the previously proposed limited
disapproval of Florida's entire regional haze SIP and proposing full
approval. This proposed action supplements the May 25, 2012, proposed
limited approval action by superseding the proposed limited approval
and replacing it with a proposed full approval. EPA will take final
action on the May 25, 2012, proposal, as supplemented herein, in
conjunction with final action on today's proposal.\3\
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    \2\ See footnote 1, above.
    \3\ Today's action does not affect the November 29, 2012, final
action fully approving the BART determinations for the sources
addressed by EPA's May 25, 2012, proposal.
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II. Summary of Florida's September 17, 2012, Regional Haze SIP
Amendment

    Florida's regional haze SIP identifies 31 EGUs subject to CAIR for
assessment for reasonable progress and 23 sources with BART-eligible
EGUs that initially relied on CAIR emissions limits for sulfur dioxide
(SO2) and nitrogen oxides (NOX) to satisfy their
obligation to comply with BART requirements. CAIR was promulgated by
EPA in 2005 to require significant reductions in emissions of
SO2 and NOX from EGUs and thus to limit the
interstate transport of these pollutants and the ozone and fine
particulate matter (PM) they form in the atmosphere. See 76 FR 70093.
The D.C. Circuit initially vacated CAIR, North Carolina v. EPA, 531
F.3d 896 (D.C. Cir. 2008), but ultimately remanded the rule to EPA
without vacatur to preserve the environmental benefits provided by
CAIR, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008).
Subsequent to the remand of CAIR, and in response to the court's
decision, EPA issued the Transport Rule to address interstate transport
of NOX and SO2 in the eastern United States. See
76 FR 48208 (August 8, 2011). On August 21, 2012, the D.C. Circuit
issued a decision to vacate the Transport Rule. In that decision, it
also ordered EPA to continue administering CAIR ``pending the
promulgation of a valid replacement.'' EME Homer Generation, L.P. v.
EPA, No. 11-1302 (D.C. Cir., August 21, 2012).\4\
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    \4\ That decision is not yet final as the mandate has not issued
and on October 5, 2012, EPA filed a petition asking for rehearing en
banc.
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    EPA has recognized that prior to the CAIR remand, the State's
reliance on CAIR to satisfy BART for NOX and SO2
for affected CAIR EGUs was fully approvable and in accordance with 40
CFR 51.308(e)(4). In addition, as explained above, CAIR remains in
place until EPA develops a suitable replacement. However, the Florida
facilities with EGUs that previously relied on CAIR to satisfy their
BART and reasonable progress obligations for SO2 and
NOX will eventually not be subject to CAIR. FDEP also
recognized that CAIR's replacement might not satisfy the regional haze
requirements for Florida. Accordingly, FDEP initiated an effort to
reassess BART and reasonable progress for all of the facilities that
had relied on CAIR to meet regional haze obligations. In its April 13,
2012, draft regional haze SIP amendment, FDEP addressed 13 of the 31
EGUs subject to reasonable progress analysis and 12 of the 23
facilities with BART-eligible EGUs. In its July 31, 2012, draft
amendment, Florida addressed the remaining 18 reasonable progress units
and the remaining 11 facilities with BART-eligible EGUs subject to CAIR
(a total of 20 EGUs). The State's September 17, 2012, amendment
finalized these BART and reasonable progress determinations addressed
in its April 13, 2012, and July 31, 2012, draft SIP amendments, and on
November 29, 2012, EPA finalized full approval of the BART
determinations addressed in the April 13, 2012, amendment. See 77 FR
71111. Table 1 lists the 18 facilities subject to reasonable progress
analysis that EPA is acting on in this notice and Table 2 lists the 11
BART-eligible EGUs that EPA is acting on in this notice.
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    \5\ Emissions unit numbers reflect the numbering system used by
FDEP, which may differ from the facilities' numbering methodology.

Table 1--Facilities Subject to Reasonable Progress Analysis With Unit(s)
                        \5\ Also Subject to CAIR
               [Italicized units are also subject to BART]
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City of Gainesville--Gainesville Regional Utilities (GRU) Deerhaven
 (Unit 5).
FPL--Manatee (Units 1, 2).
FPL--Turkey Point (Units 1, 2).
Gulf Power Company--Crist (Unit 7).
Lakeland Electric--C.D. McIntosh (Unit 6).
JEA--Northside/SJRPP (Units 3, 16, 17).
PEF--Anclote (Units 1, 2).
PEF--Crystal River (Units 1, 2, 3, 4).
SECI--(Units 1, 2).
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     Table 2--BART-Eligible Facilities With Unit(s) Subject to CAIR
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City of Tallahassee--Arvah B. Hopkins Generating Station (Unit 1).
PEF--Anclote Power Plant (Units 1, 2).
PEF--Crystal River Power Plant (Units 1, 2).
FPL--Manatee Power Plant (Units 1, 2).
FPL--Martin Power Plant (Units 1, 2).
FPL--Turkey Point Power Plant (Units 1, 2).
Gulf Power Company--Crist Electric Generating Plant (Units 6, 7).
Gulf Power Company--Lansing Smith Plant (Units 1, 2).
JEA Northside--SJRPP (Unit 3).
Lakeland Electric--C.D. McIntosh (Units 1, 5).
Reliant Energy Indian River--Indian River Plant (Units 2, 3).
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III. What is EPA's analysis of Florida's September 17, 2012, regional
haze SIP amendment?

A. Facilities Subject to Reasonable Progress Analysis

    As discussed above, a portion of the State's September 17, 2012,
regional haze SIP amendment addresses 18 of the EGUs subject to CAIR
and a reasonable progress analysis. Ten of these emissions units are
also subject to BART review under the Regional Haze Rule (RHR): FPL--
Manatee Units 1, 2 ; FPL--Turkey Point Units 1, 2; Gulf Power Company--
Crist Unit 7; JEA Northside--SJRPP Unit 3; PEF--Anclote Power Plant
Units 1, 2; and PEF--Crystal River Power Plant Units 1, 2. As discussed
in the July 1, 2007, memorandum from William L. Wehrum, Acting
Assistant Administrator for Air and Radiation, to EPA Regional
Administrators, EPA Regions 1-10, entitled Guidance for Setting
Reasonable Progress Goals Under the Regional Haze Program (``EPA's
Reasonable Progress Guidance''), EPA believes that it is reasonable to
conclude that any control requirements imposed in the BART
determination also satisfy the reasonable progress-related requirements
for source review in the first implementation period since the BART
analysis is based, in part, on an assessment of many of the same
factors that must be addressed in making source-specific reasonable
progress determinations. Therefore, Florida conducted individual
reasonable progress control reviews only on the remaining eight EGUs at
five facilities: GRU Deerhaven (Unit 5); Lakeland Electric--C.D.
McIntosh (Unit 6); JEA--Northside/SJRPP (Units 16, 17); PEF--Crystal
River (Units 3, 4); and SEC (Units 1, 2).
    The CAA and RHR require that states consider the following factors
and demonstrate how these factors were taken into consideration in
making source-specific reasonable progress determinations: Costs of
compliance; time necessary for compliance; energy and non-air quality
environmental impacts of compliance; and remaining useful life of any
potentially-affected sources. CAA section 169A(g)(1); 40 CFR
51.308(d)(1)(i). The results of FDEP's reasonable progress analyses for
the eight remaining EGUs are summarized below by facility, followed by
EPA's assessment.
1. GRU Deerhaven
    GRU's Deerhaven Emissions Unit 5 is a nominal 251 megawatt (MW)
coal-fired EGU. SO2 emissions are currently controlled with
a dry flue gas desulfurization (FGD) system designed to achieve a
target outlet SO2 emissions rate of 0.12 pound per million
British Thermal Units (lb/MMBtu). This dry FGD came on-line in 2009,
providing reductions in SO2. Prior to the installation and
operation of the FGD, FDEP identified this unit for a reasonable
progress analysis because its reasonable progress source selection
metric of emissions (Q) divided by distance (d) from the Class I area
or ``Q/d'' (i.e., 2002 SO2 emissions in tons/distance in
kilometers (km)) \6\ ratio in 2002 was greater than 50 (6,969 tons/
112.2 km = 62.12), the Q/d value used by Florida to determine which
sources would be subject to a reasonable progress analysis. Due to the
addition of the dry FGD, FDEP has issued a federally enforceable permit
condition that limits SO2 emissions to 5,500 tons per year,
resulting in a maximum Q/d value of 49.0. Thus, no further analysis of
this source is required for this implementation period.
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    \6\ Florida's development and use of the Q/d metric is discussed
in EPA's May 25, 2012, proposal at 77 FR 31251.
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2. PEF--Crystal River
    Units 3 and 4 at PEF's Crystal River plant are fossil fuel-fired
EGUs, each rated at 760 MW. SO2 emissions are controlled
with wet FGD systems that came on line in 2009 (Unit 4) and 2010 (Unit
3) and are designed to reduce emissions by 97 percent. Wet FGD systems
are considered by FDEP to be the top-level SO2 emissions
control system for coal-fired boilers such as Units 3 and 4, and the
SO2 emissions from these units are limited to 0.27 lb/MMBtu,
based on a 30-day rolling average, through a federally enforceable
permit. The source considered the potential for additional
SO2 reductions through the use of lower sulfur western coal
but found that it would not be cost-effective, as discussed below.
    Cost of Compliance: The source is already incurring the cost of the
new wet FGD systems as they were installed in 2009 and 2010, before the
reasonable progress evaluation. While lower sulfur coal is potentially
available from the Powder River Basin (PRB), PRB coal is a sub-
bituminous coal with unique combustion characteristics that would
require additional operational modifications to ensure continued safe
and reliable unit performance. Moreover, the transportation of this
coal from Wyoming to Florida would be cost prohibitive and produce
secondary environmental impacts.
    Time Necessary for Compliance: Wet FGD is already installed and
operating; therefore, no additional time for compliance is necessary.
Installing additional add-on controls for PRB firing would take, at a
minimum, several years due to PEF's need to continue operating the
units as base-load to supply reliable electric power to its customers.
    Energy and Non-Air Quality Environmental Impacts of Compliance:
Since Florida considers wet FGD as the top-level control and it is
already installed, no additional energy or non-air quality
environmental impacts would occur. The impacts from the use of lower
sulfur PRB coal could potentially include: increased water usage,
additional solid waste, secondary emissions caused by fuel
transportation, and additional energy usage for control.
    Remaining Useful Life: The source anticipates that Emissions Units
3 and 4 will continue to operate for another 28 years.
    Conclusion: After considering the four reasonable progress factors
for PEF-Crystal River, FDEP determined that the existing wet FGD
systems at the current, permitted emissions limits satisfy the
reasonable progress requirements for this implementation period.
3. SECI
    SECI Units 1 and 2 are solid fuel, dry-bottom, wall-fired units
with a maximum heat input of 7,172 million British Thermal Units per
hour (MMBtu/hr) generating 736 MW each. Units 1 and 2 are currently
authorized to burn coal as the primary fuel but are also authorized to
burn a blend of coal and petroleum coke with up to a maximum of 30
percent by weight petroleum coke. The maximum sulfur content of the
petroleum coke may not exceed 7.0 percent by weight on a dry basis (2.3
times the coal sulfur content of 3.0 percent by weight). Units 1 and 2
are each equipped with a wet FGD to control SO2 emissions.
    Cost of Compliance: FDEP has determined that wet FGD technology
provides the highest SO2 removal efficiencies for coal-fired
boilers. As such, no lower level control option was reviewed. However,
certain upgrades are available to improve the FGD systems to achieve 95
percent removal efficiency, and while not quantified, the company has
agreed to incur the costs to achieve this removal efficiency. In
addition to the FGD controls for SO2, the facility is
equipped with electrostatic precipitators (ESPs) for control of PM; low
NOX burners and Selective Catalytic Reduction (SCR) for
NOX control; and an alkali injection system to control
emissions of sulfuric acid mist. The wet FGD controls were installed in
1984 and

upgraded in 2010 to comply with CAIR and other air regulatory programs
(e.g., the Utility Mercury Air Toxics Standards (MATS) rule). Following
these upgrades, the allowable SO2 emissions rate for Units 1
and 2 was reduced from 1.2 to 0.67 lb/MMBtu on a 30-day rolling average
basis. The FGD control systems on Units 1 and 2 currently achieve
approximately 92 percent SO2 removal, and SECI proposes to
make additional changes to Units 1 and 2 to achieve a minimum
SO2 removal efficiency of 95 percent or, alternatively, to
achieve an equivalent SO2 emissions rate of no more than
0.25 lb/MMBtu on a 30-day rolling average basis for both units.
    SECI is presently evaluating available options to achieve the
proposed 95 percent SO2 removal efficiency or the emissions
limit identified above including, but not limited to, further
modifications to the internal components of the FGD, increasing
limestone recirculation rates, and increased used of dibasic acid. SECI
will complete its evaluation and provide FDEP with the details of the
selected option by March 1, 2013. The amount of time required to
implement the selected option and achieve the proposed SO2
emissions limits will depend on the option's design and whether
construction is required. However, within one to three years following
option selection, but no later than March 1, 2016, SECI will achieve
either the proposed SO2 emissions limit or the removal
efficiency requirements. The applicable limits and final compliance
date are included in a federally enforceable permit.
    Time Necessary for Compliance: Compliance with the 95 percent
SO2 removal efficiency or the alternate emissions limit of
0.25 lb/MMBtu SO2 will be achieved by March 1, 2016.
    Energy and Non-Air Quality Environmental Impacts of Compliance:
There are no additional energy or non-air quality environmental impacts
since the FGD system is already installed and operating.
    Remaining Useful Life: These units are anticipated to operate
indefinitely.
    Conclusion: After considering the four reasonable progress factors
for SECI Units 1 and 2, FDEP has determined that the existing wet FGD
SO2 control systems with upgrades to achieve a minimum
SO2 removal efficiency of 95 percent or, alternatively, an
equivalent SO2 emissions rate of no more than 0.25 lb/MMBtu
on a 30-day rolling average basis for both units are adequate to
satisfy the reasonable progress requirements for this implementation
period. In addition, the State has removed the option to burn petroleum
coke from the facility's federally enforceable permit.
4. Lakeland Electric C.D. McIntosh
    Lakeland Electric C.D. McIntosh's Unit 6 is a nominal 364 MW fossil
fuel-fired EGU that fires coal and up to 20 percent petroleum coke, low
sulfur fuel oil (<0.5 percent sulfur by weight), high sulfur fuel oil
(>0.5 percent sulfur by weight), and natural gas or propane. Unit 6 is
subject to a federally enforceable permit condition that limits
SO2 emissions to: 0.80 lb/MMBtu for liquid fossil-fuel
firing (3-hour average, 40 CFR 60 subpart D); 1.20 lb/MMBtu for solid
fossil-fuel firing (3-hour average, 40 CFR 60 subpart D); 0.718 lb/
MMBtu for blends of petroleum coke and any other fuels (30-day rolling
average); and whenever coal or blends of coal and petroleum coke or
refuse are burned, SO2 gases discharged to the atmosphere
from the boiler shall not exceed 10 percent of the potential combustion
concentration (90 percent reduction), or 35 percent of the potential
combustion concentration (65 percent reduction), when emissions are
less than 0.75 lb/MMBtu heat input (30-day rolling average). For the
most recent five-year period, more than 95 percent of the total heat
content is due to bituminous coal firing.
    Unit 6 is currently equipped with a wet limestone FGD system to
control SO2 emissions and is subject to New Source
Performance Standard (NSPS) subpart D, which has no minimum
SO2 percent reduction requirements. However, the current
title V permit requires a 65 percent reduction in SO2 when
the emissions are less than 0.75 lb/MMBtu (30-day rolling average) and
a 90 percent reduction when emissions are greater than or equal to 0.75
lb/MMBtu (30-day rolling average). Based on the actual SO2
emissions reported in 2002, the FGD system reduces SO2
emissions by 81 percent.
    Cost of Compliance: The source considered several changes and
upgrades to the wet FGD system to further reduce SO2
emissions, including lower sulfur fuel, wet FGD modifications, and
complete replacement of the FGD system. Among the authorized fuels for
Unit 6, petroleum coke has the highest sulfur content (average of 3.9
percent sulfur by weight), and bituminous coal (average of 1.8 percent
sulfur by weight) is the fuel with next highest sulfur content.
Lakeland Electric is authorized to burn up to 20 percent petroleum coke
by weight with bituminous coal and, as a result, the average sulfur
content of the combined fuel (coal and petroleum coke) can be as high
as 2.2 percent (80 percent coal with 1.8 percent sulfur and 20 percent
petroleum coke with 3.9 percent sulfur) due to the higher sulfur
content of petroleum coke. Although coal is the most used fuel for Unit
6, petroleum coke can contribute significantly to the total
SO2 emissions from the unit, and Lakeland Electric believes
that curtailing petroleum coke firing is the most cost-effective
solution to reduce the sulfur content of fuel burned in Unit 6. The
State estimated that 17 pounds of SO2 would be reduced for
every ton of coal burned when compared to the combined use of coal and
petroleum coke (difference between 2.2 percent sulfur and 1.8 percent
sulfur in one ton of fuel). Lakeland Electric did not provide costs for
eliminating petroleum coke as an authorized fuel, and FDEP assumed that
these costs would be minimal.
    The existing FGD system is a 30-year old Babcock & Wilcox design
that is not designed to achieve 95 to 98 percent SO2 removal
without significant major upgrades in the existing equipment. Based on
a preliminary assessment, the removal efficiency of the FGD system
could be increased to a maximum of 95 percent with equipment
improvements to the existing wet FGD absorbers, slurry systems,
additive systems, reheat systems, and other auxiliary equipment that
are estimated to cost $25 million. Assuming that the existing wet FGD
provides 81 percent control, an additional 14 percent control would
reduce SO2 emissions by another 5,153 tons based on 2002
SO2 emissions from this unit of 6,994 tons. This would
result in a cost-effectiveness of approximately $4,852 per ton of
SO2 reduction. FDEP does not consider this a reasonable
cost-effectiveness value and therefore determined that upgrading the
existing FGD system is not necessary for achieving the RPGs for this
implementation period.
    An additional/replacement wet FGD system designed to achieve 98
percent SO2 removal would achieve the highest level of
SO2 control while Unit 6 remains operating and available to
provide electric power to its customers. In estimating the cost of a
replacement wet FGD system, FDEP used information developed for the
Transport Rule. The annualized cost was based on the amount of
historical operation in the baseline year of 2002 and is estimated to
be approximately $36.3 million. FDEP estimated a cost-effectiveness of
approximately $5,804 per ton of SO2 removed using a target
emissions rate of 0.063 lbs/MMBtu (equivalent to 98 percent
SO2 removal based on 2002 operations). FDEP did not consider
this

a reasonable cost-effectiveness value and therefore determined that an
additional/replacement FGD is not necessary for achieving the RPGs for
this implementation period.
    Time Necessary for Compliance: The wet FGD system is already
operating for this unit. The options for upgrading or replacing the
existing wet FGD would each take a minimum of three years to complete
whereas the option of reducing the potential fuel sulfur content could
be completed immediately.
    Energy and Non-Air Quality Environmental Impacts of Compliance: The
energy and non-air quality environmental impacts associated with an
additional/replacement wet FGD system include additional limestone
usage, disposal of wet FGD byproducts, increased water use, and
additional energy. FDEP estimated that wet FGD requires approximately
three percent of the unit's energy output for auxiliary power and
backpressure (approximately 1.09 MW per ton of SO2 removed).
For each ton of SO2 removed, approximately 2.34 tons of wet
FGD byproducts are produced, and for the estimated SO2
removal increase based on 2002 emissions, an additional 6,572 tons of
limestone would be required and 14,646 tons of byproducts generated.
Approximately 312,953 gallons of additional process water would be
required based on the SO2 removal increase from 2002
emissions and an estimated water usage increase of approximately 50
gallons per ton of SO2 removed.
    Remaining Useful Life: These units are anticipated to operate
indefinitely.
    Conclusion: After considering the four reasonable progress factors
for Lakeland Electric's McIntosh Unit 6, FDEP has determined that the
existing wet FGD system at the current, permitted emissions limits with
the elimination of petroleum coke as an authorized fuel meets the
reasonable progress requirements for this implementation period.
5. JEA SJRPP
    JEA's SJRPP Emissions Units 16 and 17 (commonly referred to as
Boilers 1 and 2) are fossil fuel-fired EGUs rated at 679 MW each with a
maximum heat input rate of 6,144 MMBtu/hr per boiler. The boilers are
fired with pulverized coal, a coal blend with a maximum of 30 percent
petroleum coke by weight, natural gas, new No. 2 distillate fuel oil
(startup and low-load operation), and ``on specification'' used oil.
The maximum coal or petroleum coke-coal blend sulfur content cannot
exceed 4.0 percent by weight, and the maximum sulfur content of the No.
2 fuel oil is 0.76 percent by weight. Federally-enforceable permit
conditions limit SO2 emissions when burning coal to 1.2 lb/
MMBtu on a maximum two-hour average and 0.76 lb/MMBtu on a 30-day
rolling average (90 percent reduction of the potential combustion
concentration).
    Units 16 and 17 are equipped with wet FGD systems capable of up to
90 percent reduction in SO2 emissions with a maximum
SO2 emissions rate of 0.76 lb/MMBtu (30-day average) using
the worst-case fuel.
    Cost of Compliance: The source considered several changes or
upgrades to the wet FGD system to further reduce SO2
emissions including lower sulfur fuel, wet FGD modifications, and
complete replacement of the wet FGD system. Increasing the removal
efficiency of the existing wet FGD system is possible with equipment
improvements to the wet FGD absorbers, slurry systems, additive
systems, reheat systems, and other auxiliary equipment. FDEP estimated
the capital costs for the potential improvements to be in the range of
$10 million to $30 million per boiler. In conjunction with the
equipment improvements, operating costs for increased SO2
removal would include fixed and variable operating costs from
approximately $3 million per year per boiler to over $4.5 million per
year per boiler. Depending upon the options selected, up to an
additional five percent SO2 removal is possible. An
engineering study has commenced that will include an evaluation of the
sulfur content for the various range of fuels authorized for SJRPP and
a refinement of these very preliminary cost estimates. Since the unit
is presently 90 percent controlled, FDEP has determined not to require
these improvements for reasonable progress during this first
implementation period.
    Achieving greater SO2 reductions than 90 percent would
require either add-on SO2 controls after the existing
equipment or a replacement of the current wet FGD system with systems
designed to achieve 95 to 98 percent or greater SO2 removal.
The existing wet FGD systems are not designed to achieve 95 to 98
percent SO2 removal without significant major upgrades in
the existing equipment. An additional/replacement FGD system designed
to achieve a total removal of 98 percent SO2 removal would
be required to achieve the highest level of SO2 control.
    Units 16 and 17 are identically designed units in close proximity
that have a similar influence on visibility in Class I areas. FDEP
calculated an estimated annualized cost for an additional/replacement
wet FGD system of $59.7 million based on an emissions rate of 0.053 lb/
MMBtu, equivalent to 98 percent SO2 removal, based on 2002
operations. FDEP estimated a cost-effectiveness of $6,383 per ton of
SO2 removed using a reduction from the 2002 baseline year
and an emissions rate of 0.053 lb/MMBtu. Cost-effectiveness using the
emissions from the latest full year, 2011, was also calculated to
contrast the cost-effectiveness from the 2002 baseline year and was
estimated at $11,921 per ton of SO2 removed. FDEP does not
consider these reasonable cost-effectiveness values for Units 16 and
17, and therefore determined that an additional/replacement wet FGD
system is not necessary for meeting the reasonable progress
requirements for this implementation period. Furthermore, it may not be
possible to install add-on SO2 equipment given spatial
constraints at the site.
    Time Necessary for Compliance: The existing wet FGD systems are
already operating for these boilers. The option for replacing the
existing FGD systems would take a minimum of three years to complete
whereas the option of making improvements to the existing FGD systems,
including reducing the potential fuel sulfur content, could be
implemented in a shorter time frame.
    Energy and Non-Air Quality Environmental Impacts of Compliance: The
energy and non-air quality impacts associated with an additional/
replacement wet FGD system include additional limestone usage, disposal
of wet FGD byproducts, increased water usage, and additional energy.
FDEP estimates that a wet FGD requires about three percent of the
unit's energy output for auxiliary power and backpressure
(approximately 1.09 megawatt-hour (MWh) per ton of SO2
removed), requiring 10,189 MWh of additional energy to achieve 98
percent SO2 removal from the 2002 baseline emissions. Based
on 2002 emissions, an additional 9,815 tons of limestone would be
required, 21,874 tons of byproducts would be generated, and
approximately 467,389 gallons of additional process water would be
required to achieve 98 percent removal.
    Remaining Useful Life: These units are anticipated to operate for
at least another 20 years.
    Conclusion: After considering the four reasonable progress factors
for JEA's SJRPP Emissions Units 16 and 17, FDEP has determined that the
existing FGD control systems at the current, permitted emissions limits
satisfy the reasonable progress requirement for the implementation
period.

6. Enforceability
    FDEP included the final determinations and, as appropriate, the
permit modifications to address reasonable progress as Exhibit 2 of the
September 17, 2012, amendment. FDEP added the required operational
restrictions limiting emissions, along with the associated monitoring
and recordkeeping provisions, to each affected facility's federally
enforceable permits.
7. EPA Assessment
    As noted in EPA's Reasonable Progress Guidance, states have wide
latitude to determine appropriate control requirements for ensuring
reasonable progress. States must consider the four statutory factors
(identified in section III.A. of this action), at a minimum, in
determining reasonable progress, but have flexibility in how to take
these factors into consideration. EPA proposes to find that Florida
fully evaluated all control technologies available at the time of its
analysis and applicable to: GRU Deerhaven Unit 5; PEF--Crystal River
Units 3 and 4; SECI Units 1 and 2; Lakeland Electric--C.D. McIntosh
Boiler Unit 6; and JEA SJRPP Units 16 and 17. EPA also proposes to find
that Florida consistently applied its criteria for reasonable
compliance costs and appropriately and adequately considered the
statutory factors in developing its reasonable progress determinations.
Accordingly, EPA is proposing to approve the reasonable progress
determinations for these eight units for the first implementation
period.

B. BART Analyses

    As discussed in section II and summarized in Table 2 of this
action, the State's September 17, 2012, amendment identified 20 BART-
eligible units at 11 facilities with EGUs that were subject to CAIR and
found subject to BART that were included in the State's July 31, 2012,
draft SIP amendment.\7\ Under the Guidelines for BART Determinations
Under the Regional Haze Rule contained in Appendix Y to 40 CFR Part 51
(BART Guidelines), a state may exempt sources from BART if they do not
cause or contribute to visibility impairment in any Class I area. FDEP
used a contribution threshold of 0.5 deciview to determine which
sources were subject to BART in accordance with the BART Guidelines
following a review by Florida that this threshold was appropriate for
sources in the State. EPA proposed approval of the use of this
contribution threshold in its May 25, 2012, proposed action on prior
revisions to Florida's regional haze SIP and approved several BART
determinations based on this threshold in its November 29, 2012, action
(77 FR 71111).
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    \7\ On November 29, 2012, EPA finalized full approval of the
BART determinations addressed in the April 13, 2012, draft regional
haze SIP amendment.
---------------------------------------------------------------------------

    Using a 0.5 deciview threshold, Florida determined that the City of
Tallahassee Arvah B. Hopkins Unit 1 was not subject to BART. In
addition, two of the remaining BART-eligible sources--Reliant Energy--
Indian River Units 2 and 3 and PEF--Anclote Units 1 and 2--made changes
to their operations in order to ensure that allowable emissions would
not cause visibility impacts to exceed the 0.5 deciview threshold. All
of these operational changes at Indian River Units 2 and 3 and Anclote
Units 1 and 2 have been incorporated into their respective permits and
are federally enforceable. EPA proposes to agree with Florida's
findings that these five units are not subject to further BART review.
    Florida determined that the remaining 15 BART-eligible units at
eight facilities were subject to BART. In accordance with the BART
Guidelines, to determine the level of control that represents BART for
each source, the State first reviewed existing controls on these units
to assess whether these constituted the best controls currently
available, then identified what other technically feasible controls are
available, and finally, evaluated the technically feasible controls
using the five BART statutory factors (costs of compliance; energy and
non-air quality environmental impacts of compliance; any existing
emissions control technology in use at the source; the remaining useful
life of the source; and the degree of improvement in visibility which
may reasonably be anticipated to result from the use of such
technology). CAA section 169A(g)(2). The State's evaluations and
conclusions are summarized below by facility, followed by EPA's
assessment.
1. Gulf Power Crist
    Gulf Power's Crist Electric Generating Plant is located in Escambia
County, Florida, and consists of four active fossil fuel fired EGUs
(Units 4, 5, 6, and 7), two of which are BART-eligible units (Units 6
and 7). The following Class I area is located within 300 km of the Gulf
Power Crist facility: Breton National Wilderness Area (NWA)--250 km.\8\
Pulverized coal is the primary fuel for Units 6 and 7, and natural gas,
fuel oil, and on-specification used oil are used as supplemental fuels
in all four of the units. The facility operates a wet FGD system to
control SO2 emissions from Units 4-7 by 95 percent; low
NOX burners (LNB) and SCR (designed to achieve no less than
an 85 percent reduction) to control NOX emissions from Units
6 and 7; and cold side ESPs to control PM emissions from Units 6 and 7.
Federally enforceable title V permit emission limits for
NOX, SO2, and PM are currently established. FDEP
determined that existing controls at Units 6 and 7 represent the most
stringent controls available, thus satisfying the BART requirements for
SO2, NOX, and PM, as discussed below.
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    \8\ Florida adopted the Visibility Improvement State and Tribal
Association of the Southeast (VISTAS) modeling protocol that limits
the CALPUFF modeling domain to a 300 km radius around the subject
source. See 77 FR 31240.
---------------------------------------------------------------------------

    SO2BART: The facility utilizes a wet FGD system that
began operating in 2009 to control SO2 emissions from Units
4-7. These units share a common stack under normal conditions with the
wet FGD system in operation. Since the wet FGD was installed on a
common stack for Units 4-7, SO2 emissions reductions occur
from the control of the non-BART Units 4 and 5 as well as the BART
Units 6 and 7. The system is designed to reduce SO2
emissions by 95 percent and consists of a single scrubber reactor
vessel and supporting subsystems for transporting and processing flue
gas exhaust, limestone, gypsum or other solids, and water. FDEP
determined that the wet FGD systems represent the most stringent
controls available and the current, permitted emissions limits
contained in FDEP's title V operating permit No. 0330045-031-AV are
SO2 BART for Units 6 and 7, and that no additional control
measures are necessary.
    NOX BART: NOX emissions from Units 6 and 7
are controlled by LNB and by SCRs designed to achieve no less than an
85 percent reduction in NOX emissions. The SCR came on line
in 2005 for Unit 7 and in 2012 for Unit 6. The current federally
enforceable permit limits NOX emissions from the combined
operation of Units 4-7 to 0.2 lb/MMBtu heat input based on a 30-day
rolling average except for periods when Unit 7 is shut down. FDEP
determined that the technology applied at this facility is the top-
level NOX control for Units 6 and 7 and that the SCRs at the
current, permitted emissions limits are NOX BART for these
EGUs.
    PM BART: PM emissions from Units 6 and 7 are controlled by cold
side ESPs

with a federally enforceable PM emissions limit of 0.1 lb/MMBtu heat
input. FDEP determined that the technology applied at this facility is
the top-level PM control and that the current, permitted emissions
limits for Units 6 and 7 are PM BART for these EGUs.
    Summary of FDEP's BART Determination for Gulf Power Crist: FDEP
determined that the current, permitted emissions limits satisfy BART
for SO2, NOX, and PM. No new limits or changes to
existing limits were adopted for BART. The existing operating
conditions for units 4-7 are incorporated in the FDEP title V operating
permit No. 0330045-031-AV.
2. FPL Martin
    The Martin Power Plant is located in Martin County, Florida. The
following Class I areas are located within 300 km of the Martin Plant:
Chassahowitzka NWA-145 km and Everglades National Park (NP)-267 km. The
facility consists of two oil and natural gas-fired conventional fossil
fuel steam EGUs (Units 1 and 2), two oil and natural gas-fired combined
cycle units (Units 3 and 4), four oil and natural gas-fired combined-
cycle combustion turbines (Unit 8), and associated support equipment.
Only Units 1 and 2 are subject to BART. Units 1 and 2 each have a
maximum capacity of 863 MW and are equipped with LNB to reduce
NOX emissions and multi-cyclones with fly ash reinjection to
control PM emissions. Separate from the BART determination, FPL is
currently planning to install ESPs for the purpose of controlling PM
emissions from Units 1 and 2. The projected ESP installation date is
first quarter of 2014 for Unit 1 and the fourth quarter of 2014 for
Unit 2. The ESPs are expected to reduce PM emissions compared to the
currently permitted rates. FDEP has determined that existing controls
at the current, permitted emissions limits for the affected pollutants
SO2, NOX, and PM are BART for the Martin Plant,
as discussed below.
    SO2 BART: The options evaluated for SO2 control included
use of low sulfur fuel (0.3 percent and 0.7 percent) and FGD. These
units are currently subject to the NSPS subpart Da limit of 0.8 lb/
MMBtu when firing fuel oil. This plant fires blends of natural gas and/
or fuel oil as needed to comply with this SO2 limit. FDEP
determined that the current operating practice of using 0.7 percent
sulfur fuel oil burned alone, or co-fired with the requisite amount of
natural gas, in order to comply with the NSPS limit of 0.8 lb/MMBtu, is
SO2 BART for Units 1 and 2.
    FGD: The BART analysis submitted by FPL discussed various post-
combustion control technologies that rely on chemical reactions within
the control device to reduce the concentration of SO2 in the
flue gas. These included wet FGD and dry FGD. FDEP determined that wet
and dry FGD systems, typically used for coal-fired boilers, are not a
technically viable option for oil/gas-fired utility boilers such as
Units 1 and 2.
    Lower sulfur oil: CALPUFF air quality modeling indicates that the
baseline 98th percentile visibility impact using the current permit
limit of 0.8 lb/MMBtu (assured by firing fuel oil containing 0.7
percent sulfur) is 2.3 deciviews at the nearest Class I area
(Chassahowitzka NWA) and that the total modeled 98th percentile
visibility improvement using 0.3 percent sulfur fuel would be 1.07
deciviews, for a modeled improvement of 1.23 deciviews.\9\ The
resulting average visibility improvement cost-effectiveness is
approximately $155 million per deciview. In addition to the BART
analysis submitted by FPL, FDEP calculated that the cost-effectiveness
of reducing the sulfur content of the fuel oil from 0.7 percent to 0.3
percent is approximately $7,348 per ton based on FPL-supplied data on
fuel prices, energy content, and density. FDEP therefore concluded that
switching to 0.3 percent sulfur fuel is not SO2 BART as it
is not cost-effective.
---------------------------------------------------------------------------

    \9\ EPA assessed whether the visibility impacts of FPL Martin on
other nearby Class I areas would affect any of FDEP's BART
determinations for this facility. The FPL Martin Plant has
comparable but lesser impacts on a second Class I area (Everglades
NP), and EPA concluded that consideration of these impacts would not
change the determinations.
---------------------------------------------------------------------------

    NOX BART: Units 1 and 2 are currently equipped with flue gas
recirculation (FGR), overfire air systems, staged combustion, and LNB.
SCR was the only available additional control option identified in
FPL's BART analysis. FDEP concluded that SCR is not cost-effective for
Units 1 and 2 and that the existing NOX reduction practices
in use (FGR, overfire air systems, staged combustion, LNB, and good
combustion practices) are NOX BART for Units 1 and 2 for the
reasons discussed below.
    SCR: FPL performed a BART cost-effectiveness calculation using a
control efficiency of 90 percent and direct and indirect capital costs
and operation and maintenance costs for SCR from a study conducted in
2006 for Martin Units 1 and 2. FPL concluded that SCR would require a
direct capital investment of approximately $100 million per unit with a
cost-effectiveness of $5,323 per ton based on direct and indirect
capital costs as well as operation and maintenance costs totaling
approximately $31 million. CALPUFF modeling results indicate that only
six to seven percent of the total visibility impact at the nearest
Class I area is attributable to the NOX emissions from these
units and that the visibility improvement from SCR would be
approximately 0.15 deciview, resulting in a visibility cost-
effectiveness of approximately $203 million per deciview.
    PM BART: FPL evaluated ESPs as possible PM BART for Units 1 and 2.
ESPs are common particulate controls on utility boilers with a control
effectiveness of 99 percent. FPL concluded that control of PM emissions
from Units 1 and 2 will not provide a meaningful reduction in
visibility impacts. FDEP concluded that the addition of ESPs to these
units is not cost-effective and therefore not PM BART for these units
as discussed below. However, FPL plans to install ESPs on Units 1 and 2
in 2014 for the purpose of controlling PM.
    ESP: The capital cost for ESP on each BART-subject unit is
approximately $55.6 million. Records of actual reported annual
emissions reveal that PM emissions in 2010 were 311 tons from Unit 1
and 247 tons from Unit 2. Assuming an ESP control efficiency of 98
percent, these emissions could be reduced by a total of 547 tons
annually. Cost-effectiveness is therefore $9,595 per ton based on
estimated annualized capital costs of approximately $5.3 million per
year and assuming no additional maintenance and operating costs.
CALPUFF baseline visibility modeling showed that only four to six
percent of the total visibility degradation at the nearest Class I area
attributable to Units 1 and 2 at Martin is due to PM emissions,
translating into less than a 0.1 deciview impact at any Class I area.
FPL therefore concluded that control of PM emissions from Units 1 and 2
will not provide a meaningful reduction in visibility impacts. FDEP
concluded that the addition of ESPs to these units is not cost-
effective and therefore not PM BART.
    Summary of FDEP's BART Determination for the Martin Plant: FDEP
determined that existing controls already in place at the current,
permitted emissions limits for the affected pollutants SO2,
NOX, and PM are BART for the Martin Plant. Units 1 and 2
meet BART requirements by continuing to comply with the existing
operational and emissions limiting standards for each pollutant as
summarized below.

    SO2: 0.80 lb/MMBtu when firing liquid fossil fuel, met by firing
natural gas, co-firing natural gas with fuel oil containing less than
one percent sulfur, or firing fuel oil alone containing less than 0.7
percent sulfur.
    NOX: 0.2 lb/MMBtu when firing natural gas, 0.3 lb/MMBtu when firing
fuel oil, pro-rated based on heat input when co-firing gas and oil. The
limits are met through the use of FGR, overfire air systems, staged
combustion, and LNB.
    PM: 0.1 lb/MMBtu when firing fuel oil. The limit is met by firing
natural gas, co-firing natural gas with fuel oil containing less than
one percent sulfur, or firing fuel oil alone containing less than 0.7
percent sulfur, and through the use of multi-cyclones (mechanical dust
collectors) and fly ash reinjection.
3. FPL Manatee
    FPL's Manatee Plant is located in Manatee County, Florida. The
following Class I areas are located within 300 km of the Manatee Plant:
Chassahowitzka NWA-116 km and Everglades NP-212 km. This facility
consists of two oil and natural gas-fired 800 MW (900 MW gross
capacity) conventional steam EGUs (Units 1 and 2), a ``4 on 1'' gas-
fired combined cycle unit (Unit 3A-3D), and miscellaneous insignificant
emissions units. Only Units 1 and 2 are BART-eligible. Each of these
two units is equipped with ESPs for PM and a FGR system along with
reburn and staged combustion for NOX. In addition, FPL
recently submitted a permit application to FDEP seeking an increase in
the natural gas capacity of these units from 5,670 MMBtu/hr to 8,650
MMBtu/hr to displace the use of more residual fuel oil which will raise
the allowable natural gas capacity in the permit to equal the oil-
firing permit capacity. The proposed increased utilization of natural
gas is also expected to reduce SO2, PM, and NOX
emissions from Units 1 and 2. In addition, FDEP has determined that
SO2 emissions and visibility impacts can be reduced by
switching to low sulfur fuel oil containing a maximum of 0.7 percent
sulfur content or to a mixture of low sulfur fuel oil containing a
maximum of 1.0 percent sulfur and natural gas in a ratio not to exceed
the SO2 emissions limit of 0.80 lb/MMBtu heat input. FDEP
has also determined that the controls already in place, or soon to be
in place, at the current, permitted emissions limits for NOX
and PM are BART for Units 1 and 2, as discussed below.
    SO2 BART: FPL evaluated the use of low sulfur fuel (0.3 percent and
0.7 percent sulfur content) and FGD, for controlling SO2
emissions from Units 1 and 2. These units currently burn natural gas,
distillate, or residual fuel oil and are subject to the NSPS subpart D
limit of 0.80 lb/MMBtu when firing fuel oil. The facility's title V
permit limits the sulfur content of fuel oils burned to a maximum of
1.0 percent by weight, as received at the facility, and the blending of
natural gas is not allowed to demonstrate compliance with the
SO2 limit. FDEP determined that the switch from the current
1.0 percent sulfur fuel to 0.7 percent sulfur fuel oil burned alone, or
co-fired with the requisite amount of natural gas, in order to comply
with the NSPS limit of 0.80 lb/MMBtu, is SO2 BART for Units
1 and 2, as discussed below.
    FGD: The BART analysis submitted by FPL discussed various post-
combustion control technologies that rely on chemical reactions within
the control device to reduce the concentration of SO2 in the
flue gas. These included a wet FGD and dry FGD. FPL provided generic
cost information but cautioned that it was for illustrative purposes
and that detailed wet FGD cost estimates had not been developed. These
generic cost estimates are believed to underestimate the true cost
because they do not consider additional retrofit costs that would be
expected for adding FGD systems on Units 1 and 2 at Manatee. In
addition, FPL believes that it may not technically feasible to
construct wet FGD without major demolition efforts that would affect
the continued operation of these units. FDEP agrees with FPL that wet
or dry FGD systems are typically used for coal-fired boilers and not
for oil/gas-fired boilers. This fact, coupled with high capital costs
(ranging between $40 and $100 million), led FDEP to the conclusion that
FGD would be cost prohibitive. FDEP therefore reject this option in the
BART analysis.
    Low Sulfur Fuel: The refined oil products that are readily
available to FPL's Manatee Plant include 0.3 percent and 0.7 percent
sulfur grades. The total annual cost of switching Units 1 and 2 from
the fuel currently used to 0.7 percent or 0.3 percent sulfur fuel oil
would exceed $85 million and $240 million, respectively. However,
switching from 1.0 percent to 0.7 percent or 0.3 percent sulfur fuel
oil is a strategy to lower emissions of SO2 with no added
capital investment. FDEP calculated the cost-effectiveness of switching
to 0.7 percent and 0.3 percent sulfur fuel oil from the current
baseline of 1.0 percent oil to be $5,468/ton and $6,542/ton,
respectively, based on the information provided by FPL with an
estimated cost-effectiveness of $7,348/ton in lowering the sulfur level
in the fuel oil from 0.7 percent to 0.3 percent.
    CALPUFF air quality modeling indicates that the baseline visibility
impact using the current permit limit (firing fuel oil containing 1.0
percent sulfur) from Units 1 and 2 at Manatee is 4.07 deciviews at the
nearest Class I area (Chassahowitzka NWA) and that the total
improvement in visibility using 0.7 percent and 0.3 percent sulfur fuel
would be 0.87 deciview and 2.38 deciviews, respectively.\10\ The
resulting average visibility improvement cost-effectiveness is
calculated at approximately $100 million per deciview burning 0.7
percent sulfur fuel and $102 million per deciview burning 0.3 percent
sulfur fuel. Because the overall costs of improvement are high for
switching to the 0.3 and 0.7 percent sulfur fuels, FDEP concluded that
these options are not cost-effective. However, FDEP determined that
equivalent visibility improvements to those that could be achieved by
switching to 0.7 percent fuel oil could be achieved by removing the
current prohibition on blending and co-firing 1.0 percent oil with
natural gas and by lowering the allowable emissions limit to 0.8 lb/
MMBtu (12-month rolling average), consistent with the NSPS for this
source category. FDEP has determined that these changes constitute BART
for SO2 for Units 1 and 2.
---------------------------------------------------------------------------

    \10\ EPA assessed whether the visibility impacts of FPL Manatee
on other nearby Class I areas would affect any of FDEP's BART
determinations for this facility. The FPL Manatee Plant has
comparable but lesser impacts on a second Class I area (Everglades
NP), and EPA concluded that consideration of these impacts would not
change the determinations.
---------------------------------------------------------------------------

    NOX BART: Units 1 and 2 are currently equipped with FGR,
overfire air systems, staged combustion, LNB, and reburn. SCR was the
only available additional control option identified in FPL's analysis.
FPL calculated cost-effectiveness using direct and indirect capital
costs and the operation and maintenance costs for SCR from a study
conducted in 2006 for Units 1 and 2 and a control efficiency of 90
percent (reducing NOX emissions by 8,229 tons per year). FPL
calculated that the annualized cost to purchase and operate SCR on both
units would be approximately $31 million with a cost-effectiveness of
$3,776/ton of NOX reduced. Based on the CALPUFF modeling
results, NOX emissions from Units 1 and 2 contribute only
six to 17 percent of the total visibility impact on the nearest Class I
area. The resulting visibility cost-effectiveness is approximately $66
million per deciview using a capital expenditure of approximately $100
million per unit

and annual operating costs of approximately $6 million. FDEP concluded
that SCR was not cost-effective for Units 1 and 2 and that the existing
controls of LNB, reburn, overfire air system, staged combustion, and
FGR, along with good combustion practices, at the current, permitted
emissions limits is NOX BART for Units 1 and 2.
    PM BART: FDEP has issued federally enforceable permits limiting PM
emissions to 0.03 lb/MMBtu through the replacement of the existing
cyclones with ESPs. The in-service dates for the ESPs for Units 1 and 2
are the third quarter of 2012 and fourth quarter of 2013, respectively.
FDEP determined that ESPs are the most stringent controls available for
PM emissions from these EGUs, and therefore constitute PM BART. As a
result, FDEP did not consider additional retrofit technologies for PM
BART.
    Summary of FDEP's BART Determination for FPL's Manatee Plant: FDEP
has determined that existing controls achieving the current, permitted
emissions limits for NOX and new ESPs soon to be in place
for PM are BART for Units 1 and 2. FDEP has also determined that
switching to a lower sulfur fuel oil as specified in the permit for
Manatee is SO2 BART. The following operational and emissions
limits are BART for Units 1 and 2:
    SO2: Authorized fuels to be burned are low sulfur fuel oil
containing a maximum of 0.7 percent sulfur content, by weight; natural
gas; or a mixture of low sulfur fuel oil containing a maximum of 1.0
percent sulfur content (by weight) and natural gas in a ratio that
shall not exceed the SO2 emissions limit of 0.80 lb/MMBtu
heat input (12-month rolling average).
    NOX: Emissions shall not exceed 0.3 lb/MMBtu as demonstrated by
continuous emissions monitoring systems (CEMS). The limit is met
through the use of FGR, overfire air systems, reburn, staged
combustion, and LNB.
    PM: Emissions shall not exceed 0.03 lb/MMBtu during normal
operation. Compliance is demonstrated by stack testing.
4. Lakeland Electric C.D. McIntosh
    The Lakeland Electric C.D. McIntosh Jr. Power Plant is located in
Polk County, Florida, and has two BART-subject units. Unit 1 is a pre-
NSPS boiler with a nominal rating of 985 MMBtu/hr fired by natural gas
and fuel oil and no emissions controls. Emissions Unit 5 (commonly
referred to as Unit 2 or Boiler 2) is a NSPS subpart D boiler with a
nominal rating of 1,185 MMBtu/hr heat input equipped with FGR for
NOX control and no add-on PM or SO2 controls.
    The following Class I areas are located within 300 km of the C.D.
McIntosh facility: Chassahowitzka NWA-91 km, Everglades NP-249 km, and
Okefenokee NWA-277 kilometers. The visibility impact analysis was
performed only for the Chassahowitzka NWA, the nearest Class I area and
the only Class I area where the visibility impacts from this facility
are predicted to be higher than 0.5 deciview.\11\
---------------------------------------------------------------------------

    \11\ EPA assessed whether the visibility impacts of C.D.
McIntosh on other nearby Class I areas would affect any of FDEP's
BART determinations for this facility and concluded that
consideration of these impacts would not change the determinations.
---------------------------------------------------------------------------

    FDEP has determined that the use of 0.7 percent sulfur fuel oil and
existing controls achieving the current, permitted emissions limits for
the affected pollutants SO2, NOX, and PM are BART
for Units 1 and 2, as discussed below.
    SO2 BART: FDEP evaluated the use of low sulfur fuel and FGD, as
possible SO2 controls. Unit 2 is currently limited to 0.7
percent fuel oil, and FDEP considered the option of utilizing this low
sulfur fuel oil in Unit 1. Unit 1 is subject to Florida Rule 62-
296.405(1)(c)1.a that limits SO2 emissions to 2.75 lb/MMBtu
when firing fuel oil. FDEP expects that the Utility MATS rule will
result in this facility being operated as an oil-fired EGU subject to
the provisions for limited-use liquid oil-fired facilities and that it
will limit the unit's liquid fuel oil utilization to less than eight
percent of its maximum or nameplate heat input starting in 2015.
Lakeland Electric C.D. McIntosh has agreed to utilize the 0.7 percent
low sulfur fuel oil in Unit 1, consistent with the fuel used in Unit 2.
FDEP has determined that new shipments of fuel oil for Unit 1 will be
limited to 0.7 percent sulfur content, the same as in Unit 2, and that
this low sulfur fuel oil control option is SO2 BART for
these units for the reasons discussed below. A federally enforceable
permit condition assures this operating condition.
    FGD: The BART analysis submitted by FPL discussed various post-
combustion control technologies that rely on chemical reactions within
the control device to reduce the concentration of SO2 in the
flue gas. These included wet FGD and dry FGD. These control
alternatives allow the use of high sulfur fuel oil with an assumed 98
percent removal efficiency for the maximum annual SO2
emissions for Units 1 and 2 over the period 2001 through 2003. FDEP
calculated an annualized cost of $36.2 million with an average cost-
effectiveness of approximately $13,200 per ton of SO2
removed for wet FGD on both Units 1 and 2. These estimated costs are
not specific to the C.D. McIntosh Plant nor the layout of Units 1 and
2, and are believed to underestimate the true cost as they do not
consider any site-specific additional retrofit costs. FPL believes that
it may not be possible to install add-on SO2 controls given
the space constraints at the facility. For these reasons, FDEP
concluded that FGD is not considered appropriate technology for oil/
gas-fired boilers like C.D. McIntosh Units 1 and 2, and therefore
rejected this option in the BART analysis.
    Low Sulfur Fuel: Unit 1 currently burns natural gas and fuel oil
and Unit 2 burns only fuel oil. The facility's federally enforceable
title V permit limits the sulfur content of the fuel oil to a maximum
of 2.5 percent for Unit 1 and 0.7 percent for Unit 2. FPL evaluated the
use of 0.7 percent sulfur grade fuel oil in Unit 1, a control method
that can result in lower emissions of SO2 with no added
capital investment and reduce emissions by more than 50 percent
compared to the currently fired high sulfur fuel oil. FDEP determined
that the resulting cost-effectiveness is $2,231/ton. CALPUFF air
quality modeling indicates that the baseline 98th percentile visibility
impact at the nearest Class I area (Chassahowitzka NWA) using the
current permit limit of 2.75 lb/MMBtu for Unit 1 (based on firing fuel
oil containing 2.5 percent sulfur) and Unit 2 (0.7 percent sulfur fuel
oil) is 1.62 deciviews and that the total modeled 98th percentile
visibility improvement using 0.7 percent sulfur fuel for Unit 1 would
be 0.74 deciview.
    NOX BART: Unit 1 has no NOX emissions controls other
than best operating practices for good combustion. As mentioned
previously, Unit 2 has FGR controls for NOX and currently
meets a federally enforceable NOX permit limit of 0.2 lb/
MMBtu with compliance demonstrated by CEMS. Lakeland Electric evaluated
SCR as possible control for Units 1 and 2. FDEP concluded that
NOX BART is the current limit of 0.2 lb/MMBtu for Unit 2 and
no add-on NOX control for Unit 1.
    SCR: FDEP estimates that a control efficiency of 80 percent can be
achieved by SCR, on average, for these units. FDEP assumed that SCR is
the top-level add-on NOX control technology for Units 1 and
2 and calculated an annualized cost of $2.7 million with a cost-
effectiveness of $5,241 per ton of

NOX. The operation of SCR would result in a power
requirement of approximately 0.6 percent (2,800 MWh per year) of each
unit's power output due to the backpressure of the SCR catalyst and
auxiliaries, and there would be some non-air quality environmental
impacts associated with the storage and handling of ammonia. Based on
CALPUFF modeling results, approximately 19 percent of the total
visibility impact on the nearest Class I area is attributable to the
NOX emissions from Units 1 and 2. FDEP's analysis indicated
that SCR would result in a visibility improvement of 0.25 deciview at
Chassahowitzka NWA. For these reasons, FDEP concluded that SCR is not
cost-effective as NOX BART for these units.
    PM BART: Units 1 and 2 are not equipped with PM controls. The
existing PM emissions limits for Unit 1are 0.1 lb/MMBtu for normal
operation and 0.3 lb/MMBtu for soot-blowing operation. Unit 2 has a
limit of 0.1 lb/MMBtu at all times. Lakeland Electric evaluated add-on
PM controls including fabric filters, ESPs, and wet FGDs to control PM
emissions and identified fabric filters and wet FGDs as technically
infeasible options. Based on the costs and the limited use of fuel oil
for Unit 1 and 2, FDEP concluded that the addition of an ESP is not
cost-effective as PM BART for these units, as discussed below.
    Baghouse or venturi scrubber: The feasibility of a fabric filter
baghouse depends on site-specific exhaust characteristics such as
particulate loading, temperature, and moisture content. The use of a
fabric filter control device is uncommon for large oil-fired boilers
like Units 1 and 2. The proposed BART analysis in the SIP indicates
that PM from firing fuel oil can be sticky which can cause problems
with cleaning fabric filters and interfere with effective operation.
Likewise, venturi scrubbers are not commonly used for large oil-fired
units. In this case, FDEP also determined that venturi scrubbers are
undesirable for these units due to the non-air quality environmental
impacts associated with wastewater disposal. For these reasons, FDEP
concluded that the options of a baghouse or venturi scrubber are not
viable as PM BART for these units.
    ESP: FDEP determined that an ESP is the only feasible PM BART
control option for Units 1 and 2 and that an ESP is the most common and
technically feasible option for these types of units. FDEP also
concluded that ESPs have a control efficiency of greater than 99
percent and that other technologies have not demonstrated equivalent
levels of control for PM compared to an ESP in this application.
    FDEP calculated capital and annualized costs for an ESP for both
units of approximately $3 million with a cost-effectiveness of $65,865
per ton of PM removed. In addition, FDEP concluded that the
installation of ESP would result in a power usage of approximately 0.3
percent (1,400 MWh per year) of each unit's power output due to
electric field current usage and backpressure; there would be some non-
air quality environmental impacts associated with the disposal of ash
in a Class I landfill; and that the installation of an ESP would
require approximately two years for construction based on experience
from recent retrofit projects. CALPUFF modeling indicates that PM only
contributes approximately five percent of the total visibility impact
(approximately 0.07 deciview) from Units 1 and 2 at the nearest Class I
area. FDEP calculated visibility cost-effectiveness for an ESP at more
than $41.7 million per deciview based on the annual costs and estimated
visibility improvement identified above.
    Summary of FDEP's BART Determination for Lakeland Electric C.D.
McIntosh: As discussed above, FDEP has determined that the continued
use of 0.7 percent sulfur fuel oil at Unit 2 and the switch to 0.7
percent sulfur fuel oil at Unit 1 as specified in the permit for
Lakeland Electric McIntosh constitutes BART for SO2, and
that the controls already in place at the current, permitted emissions
limits for NOX and PM are BART for those pollutants. As
identified below, Units 1 and 2 meet BART requirements by complying
with the existing NOX and PM operational and emissions
limiting standards at both units, the existing SO2 standards
for Unit 2, and a new SO2 standard for Unit 1.
    SO2: 0.80 lb/MMBtu when firing fuel oil, met by any of the
following options: firing natural gas, co-firing natural gas with fuel
oil, or firing fuel oil alone containing not more than 0.7 percent
sulfur. Compliance is demonstrated by CEMS.
    NOX: 0.20 lb/MMBtu when firing natural gas or firing fuel oil for
Unit 2 by use of the existing FGR controls. Compliance is demonstrated
by CEMS. Unit 1 is uncontrolled for NOX.
    PM: 0.1 lb/MMBtu when firing fuel oil and 0.3 lb/MMBtu for soot
blowing for Unit 1 and 0.1 lb/MMBtu for Unit 2 at all times. These
limits can be met by any of the following options: firing natural gas,
co-firing natural gas with fuel oil, or firing fuel oil alone
containing less than 0.7 percent sulfur.
5. JEA Northside
    JEA's Northside Generating Station is located in Duval County,
Florida. The following Class I areas are located within 300 km of the
JEA Northside facility: Okefenokee NWA-63 km, Wolf Island NWA-100 km,
Chassahowitzka NWA-217 km, and Saint Marks NWA-240 km. Unit 3, the only
BART-eligible unit at Northside, is a pre-NSPS boiler with a nominal
rating of 564 MW that is fired by natural gas, landfill gas, residual
fuel oil, and used oil and is equipped with LNB. Units 1 and 2 are
repowered units that were converted to circulating fluidized bed
boilers firing mainly petroleum coke and coal (about 10 percent) fuel
blends. As part of the repowering of Units 1 and 2, JEA made a
commitment to reduce SO2, NOX, and PM emissions
to 10 percent below the 1994 and 1995 baseline years used in the
permitting of the repowering project. As a result, emissions caps for
each of these pollutants were incorporated into the federally
enforceable permit. Because the repowered units are more efficient and
better controlled, operation of Unit 3 was reduced when the new
repowered units became operational.
    Based on the operation of Unit 3 on oil, the emissions cap that
most limits operation is the NOX cap, which is limited by a
federally enforceable title V permit to 3,600 tons per year for Units
1, 2, and 3 over a 12-month rolling average. Based on the sulfur
content of the fuels used in Unit 3 in 2002, this annual NOX
limit restricts SO2 emissions from oil firing to about 9,000
tons per year if Units 1 and 2 are not operating, equivalent to a
capacity factor of about 21 percent at the authorized emissions rate.
If Units 1 and 2 are fully operational (the usual case), Unit 3 is
limited to a maximum of 3,506 tons of SO2 per year,
equivalent to a capacity factor of approximately eight percent at the
authorized emissions rate. FDEP has determined that the limited use of
fuel oil and the controls already in place at the current, permitted
emissions limits are BART for Unit 3. These conditions are included in
a federally-enforceable title V permit (No. 0310045-030-AV as condition
G.11.b.).
    SO2 BART: Unit 3 is subject to Florida Rule 62-296.405(1)(c)1.a
that limits emissions to 1.98 lb of SO2/MMBtu when firing
fuel oil. FDEP identified the use of low sulfur fuel (1.0 percent
sulfur grade fuel oil) and FGD, as potential SO2 control for
this unit. FDEP determined that the current operating practice of using
no more than 1.8 percent sulfur fuel oil burned alone, or higher sulfur
fuel oil co-fired with the requisite amount of natural gas, in order to

comply with the 1.98 lb/MMBtu emissions limit discussed above, is
SO2 BART for Unit 3.
    FGD: JEA's BART analysis discussed various post-combustion control
technologies that rely on chemical reactions within the control device
to reduce the concentration of SO2 in the flue gas. These
included wet and dry FGD . The analysis states that post-combustion
controls are typically applied to coal-fired boilers and not to oil-
fired units due to chemical reaction technology considerations and
efficiencies, and FDEP agrees that add-on controls such as FGD are not
a feasible option for Unit 3 which has a limited capacity factor
(effectively eight percent) for fuel oil. JEA listed the comparable
best available control technology (BACT) determinations for
SO2 controls on oil and gas-fired boilers and stated that
none of the comparable oil and gas-fired boilers employed add-on sulfur
controls for BACT, but rather utilized low sulfur fuel oil as a means
of reducing emissions. According to JEA, it may not be technically
feasible to construct wet and dry FGD at Northside without major
demolition efforts that would affect the continued operation of this
unit.
    Lower Sulfur Oil: Switching from 1.8 percent sulfur fuel oil to 1.0
percent sulfur fuel oil is a control method that can result in lower
emissions of SO2 with no added capital investment. FDEP
calculated that the cost-effectiveness of converting to 1.0 percent
fuel oil from 1.8 percent fuel oil would be $7,184/ton. CALPUFF air
quality modeling indicates that the baseline visibility impact using
the current permit limit of 1.98 lb/MMBtu (assured by firing fuel oil
containing 1.8 percent sulfur) is 3.61 deciviews at the nearest Class I
area (Okefenokee NWA) and that the total visibility improvement using
one percent sulfur fuel would be 1.08 deciviews. FDEP calculated a
resulting average visibility improvement cost-effectiveness of $31.1
million per deciview.
    NOX BART: Unit 3 is currently equipped with LNB, and JEA evaluated
SCR and Selective Non-Catalytic Reduction (SNCR) as possible control
methods. JEA conducted a feasibility study on this unit and found that
the temperature window for the conversion reaction of SNCR was not
available on Unit 3, and therefore, that SNCR is not feasible. For its
SCR evaluation, FDEP estimated a NOX control effectiveness
of 80 percent corresponding to an emissions reduction of approximately
1,137 tons annually from Unit 3. This value is based on the base load
operation of Units 1 and 2 since the three units are subject to a total
emissions cap of 3,600 tons per year of NOX. JEA estimated
the capital and annualized costs of SCR to be $30 million and $5.2
million, respectively, with a cost-effectiveness in excess of $4,500/
ton. CALPUFF modeling indicates that SCR on Unit 3 would improve
visibility by approximately 0.26 deciview at the Okefenokee NWA,
resulting in a visibility cost-effectiveness exceeding $20 million per
deciview. The analysis adjusted the visibility evaluation to account
for the impact of the NOX cap on the number of days the unit
can operate. For the reasons discussed above, FDEP concluded that
existing controls are NOX BART for Unit 3.
    PM BART: JEA evaluated add-on controls including fabric filters
(e.g., baghouses), ESPs, and venturi scrubbers to control PM emissions
and determined that fabric filters and PM scrubbers are technically
infeasible for Unit 3. JEA stated that fabric filters are not common
for large oil-fired boilers like Unit 3 and that the PM from firing
fuel oil can be sticky which can cause problems with cleaning fabric
filters and adversely affect control efficiency. Likewise, JEA stated
that wet PM scrubbers like venturi scrubbers are not commonly used for
large oil-fired units such as Unit 3 and that it would not further
consider these controls as BART because of lower control efficiencies
(60-90 percent), relatively high operating and maintenance costs, and
wastewater disposal issues. Although FDEP considers ESP to be the most
common and technically feasible option for Unit 3, it determined that
no PM control was appropriate for BART for the reasons discussed below.
    ESP: JEA estimated the total capital cost of an ESP at
approximately $60 million with a potential reduction in PM emissions of
approximately 449 tons per year and an estimated annualized cost of
approximately $8.1 million. Using this estimated annualized cost, JEA
calculated a cost-effectiveness of $18,083 per ton of PM removed;
however, considering the limited use of fuel oil under the federally
enforceable limit/cap on emissions, JEA calculated a cost-effectiveness
of approximately $29,000 per ton of PM removed. CALPUFF modeling
indicates that PM emissions from Unit 3 account for a 0.18 deciview
impact at the nearest Class I area (five percent of the maximum 8th
highest 24-hour average visibility impact) and that the estimated
improvement from the installation of an ESP is 0.10 deciview. Using
this estimated visibility improvement and the annualized cost of $8.1
million, the resulting visibility cost-effectiveness is more than $78
million per deciview. JEA also evaluated the other statutory BART
factors, including operating costs and remaining useful life, and
determined that the installation of ESP will result in a power usage of
approximately 0.3 percent (3,600 MWh per year) due to electric field
current usage and backpressure and that there would be some non-air
quality environmental impacts associated with the disposal of 63 to 148
tons of fly ash annually at a Class I landfill.
    Summary of FDEP's BART Determination for JEA Northside: FDEP has
determined that the limited use of fuel oil and the controls already in
place at the current, permitted emissions limits are BART for Unit 3 at
the JEA Northside Plant. This unit will meet the BART requirements by
continuing to comply with the following operational and emissions
limiting standards:
    SO2: 1.98 lb/MMBtu when firing fuel oil, met by firing natural gas,
co-firing natural gas with fuel oil, or firing fuel oil alone
containing not more than 1.8 percent sulfur.
    NOX: 0.30 lb/MMBtu when firing natural gas or firing fuel oil.
Limits are met through the use of best operating practices for good
combustion. Compliance is demonstrated by CEMS.
    PM: 0.1 lb/MMBtu when firing fuel oil and 0.3 lb/MMBtu for soot
blowing. These limits are met by firing natural gas, co-firing natural
gas with fuel oil, or firing fuel oil alone containing less than 1.8
percent sulfur.
6. Gulf Power Lansing Smith
    Gulf Power's Lansing Smith Plant is located in Bay County, Florida.
The following Class I area is located within 300 km of the Lansing
Smith Plant: Saint Marks NWA-149 km. The facility consists of two coal-
fired EGUs (Units 1 and 2), two simple cycle peaking units, two
combined cycle combustion turbines, and miscellaneous insignificant
emissions units. Units 1 and 2 are subject to BART and burn coal,
distillate fuel oil, or on-specification used fuel oil. Distillate fuel
oil is only used during start-up and flame stabilization, and
combustion of on-specification used oil is limited to no more than
50,000 gallons per calendar year per boiler. Unit 1 has a maximum
authorized heat input rate of 1,944.8 MMBtu/hr and Unit 2 has a maximum
authorized heat input rate of 2,246.2 MMBtu/hr. Units 1 and 2 are both
are equipped with hot and cold side ESPs and SNCR. Unit 1 is also
equipped with LNB with high momentum injection ports, and Unit 2 has
LNB with an overfire air control system.

    FDEP has determined that the controls already in place at the
current, permitted emissions limits for NOX and PM are BART
for Units 1 and 2. FDEP has also determined that SO2
emissions and visibility impacts can be further reduced by switching
Units 1 and 2 to lower sulfur coal and installing dry sorbent injection
(DSI) using trona as a reagent and that these control measures are BART
for SO2 as discussed below. The use of wet FGD, instead of
DSI plus low-sulfur coal option, results in an incremental improvement
in visibility of only 0.19 deciview for Unit 1 and 0.22 deciview for
Unit 2 for the maximum 8th highest day and 0.07 deciview for Unit 1 and
0.09 deciview for Unit 2 for the 22nd highest day over three years at
Saint Marks NWA (the nearest Class I area to the facility).\12\
---------------------------------------------------------------------------

    \12\ Saint Marks NWA is the only mandatory Class I federal area
within the surrounding 300 km CALPUFF modeling domain used by FDEP
to assess visibility impacts. The visibility impacts in the Class I
areas just outside of this domain resulting from Lansing Smith
emissions are expected to be lower than those predicted at Saint
Marks, and EPA has determined that consideration of these impacts
would not change the BART determinations.
---------------------------------------------------------------------------

    SO2 BART: FDEP evaluated the following options for SO2
control: (1) Switch to lower sulfur coal, (2) DSI with use of lower
sulfur coal, (3) dry FGD lime spray dryer absorber (SDA), and (4) wet
FGD. All of these SO2 control technologies are considered
technically feasible for Units 1 and 2. FDEP's SO2 BART
determination for Units 1 and 2 is a SO2 emissions rate of
0.74 lb/MMBtu on a 30-day rolling average which can be achieved with
the use of DSI with trona as the alkaline reagent. FDEP concluded that
FGD is not cost-effective when considering the estimated costs and
associated visibility improvement, as discussed below.
    Low Sulfur Coal: Gulf Power states that the use of lower sulfur
Columbian coal can result in lower SO2 with no added capital
investment and that switching Units 1 and 2 to lower sulfur coal would
reduce SO2 emissions by approximately 25 percent. The fuel
switch to lower sulfur coal was assumed to have no additional costs;
therefore, Gulf Power did not conduct any further economic analyses for
this control option.
    DSI with Low Sulfur Coal: DSI is a dry technology that uses an
alkaline reagent to absorb SO2. DSI control technology
injects reagent (e.g., trona) directly into the boiler flue gas in the
ductwork between the air heater and the particulate collection device.
The sulfite/sulfate salts reaction products are then removed by a
downstream PM control device. Since a gas/sorbent contacting vessel is
not required, the DSI capital costs are lower, less physical space is
required, and exhaust duct modifications are simpler compared to a dry
FGD lime SDA system. However, reagent costs are higher and
SO2 control efficiencies are lower than those for dry FGD.
Gulf Power noted that lime was considered as a component of the MATS
rule compliance approach, but that using trona instead of lime would
achieve further reductions in SO2 emissions. Gulf Power
estimated that the use of DSI with trona injection combined with lower
sulfur coal would have a SO2 removal efficiency of 48
percent corresponding to a SO2 emissions rate of 0.74lb/
MMBtu on a 30-day rolling average. Gulf Power assumed that the capital
cost of DSI and the operation and maintenance costs associated with
lime injection will be incurred as a MATS rule compliance plan.
However, FEDP determined that the baseline should be existing
conditions and conducted an independent evaluation of the cost of DSI.
FDEP calculated annualized costs of approximately $2 million for Units
1 and 2, individually. Using these values and SO2 emissions
reductions of 4,175 tons for Unit 1 and 4,451 tons for Unit 2, FDEP
calculated a cost-effectiveness of $477 and $435 per ton of
SO2 removed, respectively. The energy impacts associated
with the DSI technology are minimal.
    Dry FGD Lime SDA: The types of dry FGD systems typically installed
on coal-fired boilers are those utilizing either SDA or a circulating
dry scrubber (CDS). Gulf Power considered both types of control
equipment and concluded that SDA and CDS present similar issues with
respect to inadequate available space upstream of the existing PM
control device for the installation of new equipment and the need for a
larger capacity PM control device. Gulf Power considers a dry FGD lime
SDA system as an inferior technology compared to wet FGD and did not
further evaluate this type of dry FGD based on its conclusions that:
(1) Wet FGD will achieve higher SO2 removal, (2) dry FGD
lime SDA technology is difficult to apply as a retrofit to existing
boilers due to space considerations, (3) with the increased PM loading,
a new PM control device will need to be installed, and (4) with the
inclusion of the cost of a baghouse for the dry FGD lime SDA option,
wet FGD will achieve greater emissions reductions at a lower cost
compared to the dry FGD lime SDA system.
    Wet FGD: Gulf Power estimated that the control effectiveness of wet
FGD is 95 percent SO2 removal for Units 1 and 2 and that the
capital and annualized costs are approximately $112 million and $14.5
million, respectively, for Unit 1 and $133 million and $16.6 million,
respectively, for Unit 2. Based on a removal efficiency of 95 percent,
SO2 emissions reductions would be 7,794 tons for Unit 1 and
8,256 tons for Unit 2 for a cost-effectiveness of $1,862 and $2,009 per
ton, respectively. Incremental cost-effectiveness from DSI with lower
sulfur coal was estimated to be $3,451 and $3,850, respectively. Gulf
Power expects that wet FGD would impose an energy penalty of four MW
per unit due to the increased fan power required to compensate for the
higher pressure drop of the absorber vessel and that wet FGD would
require substantial amounts of water and generate a wastewater stream
that will require treatment.
    To evaluate visibility impacts for each unit at the Saint Marks
Class I area, Gulf Power conducted CALUFF modeling for each
SO2 control technology evaluated. For Unit 1, the model
predicted improvements in visibility ranging from 0.37 deciview for the
switch to low-sulfur coal to 0.67 deciview for wet FGD for the maximum
8th highest day for the highest year of the three years modeled, and
from 0.34 deciview to 0.51 deciview, respectively, for the 22nd highest
day over the three years compared to the ``existing controls'' baseline
levels. Modeled visibility improvements for Unit 2 range from 0.27
deciview for the switch to low-sulfur coal to 0.61 deciview for wet FGD
for the maximum 8th highest day for the highest year each of the three
years modeled and from 0.24 deciview and 0.45 deciview, respectively,
for the 22nd highest day over the three years modeled compared to
``existing controls'' baseline levels. The use of wet FGD instead of
DSI plus low-sulfur coal results in a predicted incremental improvement
in visibility of 0.19 deciview for Unit 1 and 0.22 deciview for Unit 2
for the maximum 8th highest day for the highest year of the three years
modeled, and 0.07 deciview for Unit 1 and 0.09 deciview for Unit 2 for
the 22nd highest day over three years. Using these modeling results and
the costs identified above, the cost per deciview improvement for wet
FGD is approximately $21.7 million/deciview for Unit 1 and $27.2
million/deciview for Unit 2. The incremental cost per deciview
improvement for wet FGD (compared to DSI) is $178.9 million for Unit 1
and $162.8 million for Unit 2.
    NOX BART: Units 1 and 2 are equipped with LNB with high momentum
injection ports, and Unit 2 uses LNBs with an overfire air control

system. In addition to LNB, both units use SNCR for additional
NOX control. Gulf Power evaluated the installation of SCR,
and FDEP determined that the existing controls (LNB, overfire air
system, and SNCR), along with good combustion practices, are
NOX BART for Units 1 and 2. FDEP did not select SCR as BART
due to a cost-effectiveness of $5,000 per ton for Unit 1 and $7,000 per
ton for Unit 2 with limited predicted visibility improvement.
    SCR: As discussed above, the baseline NOX control
technology for Units 1 and 2 includes current combustion controls plus
SNCR. Gulf Power estimated that the capital and annualized costs
associated with SCR are approximately $66 million and $7.9 million,
respectively, for Unit 1 and $74.9 million and $8.9 million,
respectively, for Unit 2. FDEP assumed a control efficiency of 90
percent for SCR, resulting in NOX emissions reductions of
1,619 tons for Unit 1 and 1,279 tons for Unit 2 for a cost-
effectiveness of $4,907 and $6,957 per ton, respectively. Gulf Power
provided CALPUFF modeling indicating that the installation of SCR at
Unit 1 would result in a maximum visibility improvement of 0.01
deciview for the maximum 8th highest day at the St. Marks Class I area
for each of the three years modeled and that there is no improvement
for the 22nd highest day over the three years modeled compared to
``existing controls'' baseline levels. Furthermore, FDEP notes that
baseline visibility impacts due to NOX emissions are only
3.9 percent of the total baseline impact at the nearest Class I area.
FDEP estimated that the energy impacts associated with SCR are one MW
for each unit to run pumps and to overcome the high pressure drop in
the systems.
    PM BART: Units 1 and 2 are equipped with hot and cold side ESPs
that achieve PM emissions rates of 0.014 and 0.015 lb/MMBtu. Therefore,
Gulf Power conducted the PM BART analysis for only a fabric filter
technology such as a baghouse. FDEP determined that the existing ESPs
on Units 1 and 2 are PM BART and that no additional add-on control
technologies are required for the reasons discussed below.
    Fabric Filters: The collection efficiencies for fabric filter
technology are approximately 99 percent for PM smaller than 2.5
microns, resulting in projected PM emissions reductions of 44 tons for
Unit 1 and 37 tons for Unit 2. Gulf Power estimated that the capital
and annualized costs of fabric filters are approximately $35.8 million
and $4.8 million, respectively, for Unit 1 and $42.6 million and $5.6
million, respectively, for Unit 2 for a cost-effectiveness of $108,566
and $153,268 per ton of PM removed for Units 1 and 2, respectively.
Gulf Power concluded that there were no modeled improvements in
visibility at the nearest Class I area for both the maximum 8th highest
day for each of the three years modeled and 22nd highest day over the
three years modeled compared to the existing control baseline levels
(i.e., visibility levels from existing ESP controls) due to the use of
fabric filter technology and that the baseline visibility impacts due
to PM emissions are only 1.3 percent of the total baseline impact at
the nearest Class I area. Gulf Power estimated that the energy impacts
associated with the fabric filter system are one MW for each unit due
to the need for extra fan horsepower to overcome the increased pressure
drop in the boiler exhaust system and that the higher PM removal
efficiency would increase the amount of solid waste that will need to
be disposed of in an onsite or offsite landfill.
    Summary of FDEP's BART Determination for Gulf Power Lansing Smith:
    As discussed above, FDEP has determined that the controls already
in place at the current, permitted emissions limits for NOX
and PM are BART for Gulf Power's Lansing Smith Plant Units 1 and 2, and
that these units will meet the SO2 BART requirements by
installing a DSI/trona system and switching to lower sulfur coal. The
BART operational and emissions limiting standards for Lansing Smith
Units 1 and 2 are specified in the facility's title V permit and are
summarized below:
    SO2: 0.74 lb/MMBtu for Unit 1 and 0.74 lb/MMBtu for Unit 2.
    NOX: The combined NOX emissions from Units 1 and 2 shall
not exceed 4,700 tons during any consecutive 12-month rolling total as
determined by CEMS data reported to the EPA Acid Rain database.
    PM: Emissions shall not exceed 0.1 lb/MMBtu. Compliance is
demonstrated by annual stack test.
7. FPL Turkey Point
    FPL's Turkey Point facility is located in Miami-Dade County,
Florida. The following Class I area is located within 300 km of the
Turkey Point facility: Everglades NP-35 km. The facility consists of
two residual fuel oil and natural gas-fired 440 MW fossil fuel steam
EGUs (Units 1 and 2); five fuel oil-fired black start 2.75 MW diesel
peaking generators supporting Units 1 and 2; a natural gas-fueled 1,150
MW combined cycle unit (Unit 5); and associated equipment. Units 1 and
2 are subject to BART and are each equipped with LNB and multi-cyclones
with ash reinjection. The multi-cyclones consist of two tubular
mechanical dust collector modules with 695 tubes per collector.
    In 2009, FDEP issued a PM-only BART determination for Units 1 and 2
that imposed a 20 percent visible emissions limit, a 0.7 percent sulfur
fuel oil restriction, and upgrades to the multi-cyclones to achieve a
0.07 lb/MMBtu PM emissions rate. FDEP assumed this would require
installation of a $3.7 million ESP on each unit. In addition, the
determination required FPL to conduct a PM control device additive
study to determine if a 0.05 lb/MMBtu emissions rate could be achieved.
FPL completed the study in 2010 showing that the lower limit was not
achievable using a calcium-based additive. On September 9, 2011, FPL
submitted a revised PM BART proposal to eliminate the requirement to
upgrade the multi-cyclones on Unit 1 and to continue to use the
existing multi-cyclone to meet a limit of 0.07 lb/MMBtu as BART for
this unit based on the limited use of oil in Unit 1 and FPL's
conclusions that the visibility impacts from PM are negligible and that
there is little incremental visibility benefit of a new dust collector.
Subsequent to the request to change the PM BART limitations, FPL
submitted a new proposed BART determination to FDEP that addresses
SO2 and NOX.
    FDEP determined that Unit 1 will meet SO2 BART by
restricting the use of fuel oil to 8,760,000 MMBtu/year heat input
(equivalent to a capacity factor of 25 percent) and by reducing the
sulfur content of the fuel fired in Unit 1 to 0.7 percent by weight as
soon as practicable but no later than December 31, 2013. These
provisions have been added to state permit No. 0250003-018-AC, which is
federally enforceable. This permit also requires the permanent shutdown
of Unit 2 as soon as practicable but no later than December 31, 2013.
FDEP also determined that the controls already in place at the current,
permitted emissions limits for NOX and PM are consistent
with the original BART determination for Unit 1 made by FDEP in 2009
that required the multi-cyclones to meet a 0.07 lb/MMBtu limit for PM.
    PM BART: Based on information submitted by FPL, FDEP determined
that new ESPs could meet an emissions limit of 0.03 lb/MMBtu and reduce
emissions from both units by a total of 1,257 tons at an estimated
annualized cost of approximately $6.7 million for each ESP for a cost-
effectiveness of $10,623/ton of PM removed (excluding any costs
associated with any changes

in construction due to the close proximity of the Turkey Point nuclear
units 3 and 4). According to FPL, ESP construction for Units 1 and 2
would increase security requirements and potentially require approval
from the United States Nuclear Regulatory Commission due to the
proximity of Units 1 and 2 to the facility's nuclear units. FPL
estimated that the energy required to operate two ESPs would be
approximately 4,370 MWh per year for both units (0.13 percent of gross
generation from units 1 and 2) and that 1,257 tons of ash would be
generated from the ESPs requiring about 50 truck trips per year to
remove it from the site for recycling or landfill disposal.
    In evaluating whether to change the 2009 PM BART determination,
FDEP considered the limited use of oil at Units 1 and 2 after
compliance with SO2 BART. FDEP has established a federally
enforceable permit condition requiring the permanent shut down of Unit
2. FDEP is also restricting oil firing on Unit 1 to 8,760,000 MMBtu/
year heat input (equivalent to a capacity factor of 25 percent).
Therefore, FDEP determined that the emissions reductions from a new ESP
on Unit 1 are further diminished, resulting in an even higher cost per
ton of PM removed than those estimated above. As an alternative PM
emissions reduction strategy, FDEP has approved the use of low sulfur
residual fuel oil (0.7 percent versus the one percent sulfur oil used
during the baseline period) and a reduction in the PM limit from the
current allowable emissions rate of 0.1 lb/MMBtu to 0.07 lb/MMBtu,
which is achievable with the existing multi-cyclones controls and the
lower sulfur fuel oil. At a comparative cost of less than $3,600/ton of
PM removed, FDEP considered this option cost-effective given the
source's proximity to the nearest Class I area (Everglades NP) and
estimated a visibility improvement of 0.6 deciview (i.e., 29 percent
reduction in visibility impacts from the base case).
    SO2 BART: FPL evaluated wet and dry FGD and lower sulfur fuel oil
(at 0.7 percent and 0.3 percent sulfur content) as possible
SO2 BART controls. Although technically feasible to install,
FPL cites capital cost estimates of between $40 and $100 million for
FGD on Units 1 and 2 and the lack of comparable units that fire gas and
fuel oil with wet or dry FGD installations. FPL found no determinations
for oil and gas-fired units employing FGD in EPA's RACT/BACT/LAER
Clearinghouse,\13\ and all of the determinations identified by FPL used
lower sulfur fuel oil to reduce SO2 emissions. FPL does not
believe that a dry FGD combined with a baghouse is feasible for Units 1
and 2 since tests conducted by FPL at its Sanford power plant found
that particles generated from the combustion of oil-based fuels caused
considerable plugging of bags in pilot scale tests. Compared to firing
natural gas, fuel oil has a significantly higher sulfur content, and
FDEP has determined that limiting fuel oil firing on Unit 1 to no more
than a 25 percent capacity factor and limiting the sulfur content to
0.7 percent is SO2 BART for Unit 1.
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    \13\ EPA's RACT/BACT/LAER Clearinghouse is located at: http://cfpub.epa.gov/RBLC/index.cfm?action=Home.Home⟨=en.
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    NOX BART: FPL evaluated SCR and SNCR as potential NOX
controls for Unit 1. FDEP determined that the limited capacity factor
for fuel oil (the higher NOX producing fuel) makes the use
of add on NOX controls economically infeasible. Unit 1 is
currently required to meet an emissions limit of 0.40 lb/MMBtu on gas
and 0.53 lb/MMBtu on fuel oil based on a 30-day rolling average and
CEMS to satisfy Florida Rule 62-296.570 for NOX reasonably
available control technology (RACT). Since Unit 2 is required to
permanently shut down, FPL did not perform a control evaluation for
Unit 2. Further, the baseline modeling showed that nitrates contributed
less than three percent of the visibility degradation associated with
the emissions from this facility.
    Summary of FDEP's BART Determination for FPL Turkey Point: Permit
No. 0250003-018-AC requires FPL to permanently shut down Unit 2 as soon
as practicable but no later than December 31, 2013. This permit is
federally enforceable. For Unit 1, FDEP has determined that
NOX BART are the controls already in place at the current,
permitted emissions limits and for PM and SO2, BART is the
restricted use of fuel oil to 8,760,000 MMBtu/year heat input
(equivalent to a capacity factor of 25 percent). The BART operational
and emissions limiting standards for FPL Turkey Point Unit 1 are
summarized below:
    SO2: As soon as practicable, but not later than December 31, 2013,
the sulfur content of the fuel fired in Unit 1 shall not exceed 0.7
percent, by weight and SO2 emissions from Unit 1 shall not
exceed 0.77 lb/MMBtu on a three-hour rolling average. Compliance shall
be demonstrated through the use of the existing CEMS.
    NOX: NOX emissions from Unit 1 shall not exceed the
following limits based on a 30-day rolling average: 0.40 lb/MMBtu and
1,610 lb/hour when burning gas and 0.53 lb/MMBtu and 2,041 lb/hour when
burning oil.
    PM: Emissions of PM are limited to 0.07 lb/MMBtu when firing fuel
oil. Limits will be met by firing natural gas, co-firing natural gas
with fuel oil containing less than 0.7 percent sulfur, and through the
use of multi-cyclones (mechanical dust collectors) and fly ash
reinjection. Compliance will be demonstrated by stack tests when fuel
oil is fired for more than 400 hours annually.
8. PEF Crystal River
    PEF's Crystal River Power Plant is located in Citrus County,
Florida. The following Class I areas are located within 300 km of the
Crystal River Plant: Saints Marks NWA-174 km, Chassahowitzka NWA-21 km,
Wolf Island NWA-293 km, and Okefenokee NWA-178 km. The facility
consists of four coal-fired EGUs and associated equipment. Units 1 and
2 are subject to BART and NSPS subpart Da. These units are
tangentially-fired, dry-bottom boilers with a nominal generation
capacity of 440.5 and 523.8 MW, respectively, that may burn bituminous
coal or a bituminous coal and bituminous coal briquette mixture.
Distillate fuel oil may be burned as a startup fuel. Each unit has an
ESP to control PM and LNB to control NOX and is equipped
with CEMS to measure and record NOX and SO2
emissions and a continuous opacity monitoring system to measure and
record the opacity of the exhaust gases.
    PEF has proposed to satisfy SO2 and NOX BART
requirements through an approach that would allow the company to select
one of two compliance options. The first option would require the
installation of a dry FGD and SCR to these units by 2018 and would
extend the life of these units. The second option would shut down these
units by December 31, 2020, with no new controls being installed. PEF
has requested that it have until January 1, 2015, to state which option
it will pursue because it is in the process of ownership change and
decisions on how these units will be addressed in response to other
federal regulations are uncertain. FDEP believes that either of the two
options meet the BART requirements, and FDEP has allowed PEF until
January 1, 2015, to choose an option. These options and the option
selection date are included in a federally enforceable permit.
    FDEP concluded that additional control strategies for
SO2 and NOX are not cost-effective if the units
shutdown by December 31, 2020. Should PEF choose not to shut down Units
1 and 2,

Option 2 of the permit requires PEF to install dry FGD to meet an
emissions limit of 0.15 lb/MMBtu on a 30-day rolling average, or 95
percent control efficiency, and SCR to achieve 90 percent removal
efficiency by January 1, 2018.
    For PM BART, FDEP determined that a PM limitation of 0.04 lb/MMBtu
for the combined units is PM BART. A federally enforceable PM BART
permit was issued for Units 1 and 2 on February 25, 2009 (Permit No.
0170004-017-AC), which imposed this revised allowable PM emissions
limit. In this earlier BART determination, PEF proposed to upgrade the
existing ESP for Unit 2 to reduce the allowable PM limit from 0.1 lb/
MMBtu to 0.04 lb/MMBtu (average for both units), and to permanently
cease operating the units as coal-fired boilers by the end of the year
2020. FDEP determined that additional PM control, beyond 0.04 lb/MMBtu,
is not necessary for BART given the control costs associated with the
limited visibility improvement resulting from a more stringent limit.
In the latest issued permit for SO2 and NOX BART,
FDEP recognized that under the option to continue operation, the
installation of a dry FGD system will necessitate additional PM control
to avoid significant emissions increases. Therefore, FDEP will limit PM
emissions to 0.015 lb/MMBtu at both units should PEF select the
SO2 control technology option to satisfy SO2
BART.
    SO2 BART: The facility currently burns 1.02 percent sulfur coal and
has a baseline emissions rate of 38,250 tons per year of
SO2. PEF evaluated three options for SO2 control:
(1) Switch to lower sulfur coal, (2) dry FGD lime SDA, and (3) wet FGD.
All of these available retrofit SO2 control technologies are
technically feasible for Units 1 and 2. However, FDEP determined that
switching to a lower sulfur fuel or installing an FGD system is not
cost-effective if PEF retires the units by December 31, 2020. Without
this retirement date, FDEP determined that a SO2 emissions
rate of 0.15 lb/MMBtu on a 30-day rolling average, or 95 percent
control efficiency, is SO2 BART and can be achieved through
the use of controls such as dry FGD.
    Low Sulfur Coal: Units 1 and 2 currently burn bituminous coal, a
bituminous coal and bituminous coal briquette mixture, distillate fuel
oil, or on-specification used fuel oil. Distillate fuel oil is only
used during start-up and flame stabilization. PEF evaluated the use of
lower sulfur coal in Units 1 and 2 and indicated that bituminous coal
with a sulfur content of 0.68 percent and sub-bituminous coal with a
sulfur content of 0.35 percent from the PRB are commercially available.
For the low sulfur coal control options, PEF assumed that an ESP
upgrade would be necessary to accommodate the 0.68 percent sulfur coal,
and a replacement of the ESPs with baghouses and modification of other
equipment would be required to fire the 0.35 percent PRB coal. For this
analysis, PEF assumed that ESP upgrades or ESP replacement and other
equipment modifications would not be complete until 2018. PEF estimated
costs at approximately $155 million in capital expenditures to switch
the units to 0.68 percent sulfur fuel based on an ESP upgrade with
annualized costs of $97.5 million assuming closure in 2020. PEF
estimated capital costs of approximately $516 million and annualized
costs of $297 million for the 0.35 percent sulfur fuel considering cost
factors including performance, coal handling performance, and safety
for 0.35 percent coal and the replacement of an ESP with a baghouse.
The estimated annual SO2 reductions are 12,250 and 20,250
tons per year, respectively, resulting in cost-effectiveness estimates
of $8,665 and $14,652 per ton of SO2 removed, respectively.
PEF states that energy impacts (derating of the power generating
capability of the units) would likely be associated with the use of PRB
coal due to the lower heating values compared to the current coal used
in Units 1 and 2. The heating values of the coal currently used are
approximately 12,000 British thermal units per pound (Btu/lb) compared
to the heating value of 8,500 Btu/lb for PRB coal.
    Wet FGD or Dry FGD Lime SDA: PEF evaluated the potential use of wet
and dry FGD on Units 1 and 2 to reduce SO2 emissions,
assuming a control efficiency of 95 percent. PEF discusses SDA control
equipment but states that the installation of the technology is a
concern due to inadequate available space and the conditions of the
units and that the installation of dry FGDs would also necessitate
additional PM control to prevent significant emissions increases. The
PEF analysis states that the control efficiency of a wet FGD system is
between 56 and 98 percent and the control efficiency of a dry FGD is
between 70 and 96 percent.
    FDEP estimated that the capital costs for installation of dry FGD
systems are approximately $445 million for Units 1 and 2, combined,
with a total annualized cost for installation and operation of the dry
FGD systems of $364 million for a cost-effectiveness of over $10,000
per ton of SO2 removed. These annualized costs represent the
annualized capital cost as well as recurring annual operating costs for
each unit assuming the facility shuts down in 2020. PEF determined that
the operation of dry FGD imposes an energy penalty due to the increased
fan power required to compensate for the higher pressure drop of the
absorber vessel and that it would have non-air quality environmental
impacts due to the generation of additional solids. For a wet FGD, non-
air quality environmental impacts would include increased energy use,
increased water use, and the generation of additional solid wastes.
    NOX BART: PEF identified SCR and SNCR as technically feasible
options for Units 1 and 2 and noted that although there are examples
where SNCR is installed on coal-fired boilers, this technology is more
common for smaller boilers in the 100 MW size range. For large
pulverized coal fired boilers, PEF regards SCR as a demonstrated
technology and SNCR as not demonstrated. FDEP concluded that the
existing combustion process, LNBs, and use of good combustion practices
are NOX BART for Units 1 and 2 under the option to shut down
these units by December 31, 2020. Should PEF choose not to shut down
these units, the permit establishes a NOX emissions limit of
0.09 lb/MMBtu on a 30-boiler operating day rolling average basis. The
emissions standard will be achieved by the installation and operation
of NOX control systems including SCR before January 1, 2018,
or within five years of EPA's final approval of Florida's final
regional haze SIP, whichever is later.
    SCR: PEF states that the control effectiveness of SCR technology
can be up to 90 percent. Assuming that the facility shuts down in 2020,
FDEP estimated annualized costs of approximately $92.6 million and a
cost-effectiveness of $8,244 per ton of NOX removed using
the methodology in EPA's Air Pollution Control Cost Manual (http://www.epa.gov/ttncatc1/products.html#cccinfo). The cost-effectiveness was
estimated based on 90 percent control of baseline emissions of 12,480
tons (i.e., 11,232 tons of reduction of NOX), which was
determined from the maximum annual actual emissions for Units 1 and 2
combined from the period 2001-2003. Annual costs were developed based
on a capital cost of $193/kilowatt (kW) and a fixed operation and
maintenance cost of $0.7/kW. CALPUFF modeling indicates that SCR would
improve visibility by 1.71 deciviews at the nearest Class I area
(Chassahowitzka NWA) for the maximum 8th high day (2003) for a
visibility cost-effectiveness of $54.2 million/deciview. PEF estimates
that the installation of SCR

will result in a power requirement of approximately 0.6 percent (50,700
MWh per year) due to the backpressure of the SCR catalyst and auxiliary
equipment, and that there would be some non-air quality environmental
impacts associated with the storage and handling of ammonia. PEF
indicated that ammonia slip is an issue with both SCR and SNCR
operation due to odor and ammonium salt formation. If urea is used with
these control technologies, water treatment would be required.
    SNCR: PEF evaluated SNCR for Units 1 and 2 using a control
effectiveness of approximately 25 percent and a capital cost of $19/kW
and fixed operation and maintenance cost of $0.2/kW. FPL conservatively
estimated an annualized cost of $8.4 million for a cost-effectiveness
of $2,687 per ton of NOX removed. CALPUFF modeling predicts
a visibility improvement of 0.47 deciview at the Chassahowitzka NWA for
the maximum 8th high day (2003) from SNCR on both units for a
visibility cost-effectiveness of approximately $17.7 million/deciview.
If SNCR is installed, PEF states that additional electrical power will
be required to operate the reagent handling system and that a water
treatment system will be required if urea is used as a reagent, which
will also need additional power. PEF also indicated that ammonia slip
is an issue with SNCR operation, as discussed above.
    PM BART: CALPUFF modeling indicates that replacing the existing
ESPs with new control devices (i.e., new ESP or baghouse) designed to
meet an emissions limit of 0.015 lb/MMBtu would improve visibility by a
maximum of 0.15 deciview (based on the maximum 8th highest 24-hour
average of each of the three years modeled) at the nearest Class I
area. PEF also estimated that the capital cost of upgrading the
existing PM controls or replacing them with new control devices would
range from $71 million to $144 million. Considering the age of the
units and the cost of replacing the ESPs, PEF proposed to upgrade the
existing ESP for Unit 2, reduce the allowable PM limit from 0.1 lb/
MMBtu to 0.04 lb/MMBtu (average for both units), and to permanently
cease operating the units as coal-fired boilers by December 31, 2020.
FDEP determined that meeting an emissions standard of 0.015 lb/MMBtu
can be achieved by all proposed options. However, FDEP concluded that
it is not reasonable to require the capital expenditure needed to bring
emissions down to levels achievable by new units and control devices
given the limited remaining useful life. Therefore, FDEP determined
that reducing PM emissions from the current allowable emissions limit
of 0.1 lb/MMBtu to levels near what has been reported in stack tests
over the past five years (0.04 lb/MMBtu) with a commitment to cease
operating these units as coal-fired boilers by December 31, 2020, is
BART. Should PEF choose not to shut down Units 1 and 2, it must install
SO2 control technology. The SO2 BART
determination (Permit No. 0170004-036-AC) includes a requirement that
no later than January 1, 2018, or within five years of the effective
date of EPA's approval of this specific requirement in the Florida
regional haze SIP, whichever is later, PM emissions shall not exceed
0.015 lb/MMBtu, as determined by EPA Method 5.
    Summary of FDEP's BART Determination for PEF Crystal River: As
discussed above, FDEP has determined that if these units are shutdown
by December 31, 2020, additional control strategies for SO2
and NOX are not cost-effective and a PM limitation of 0.04
lb/MMBtu for the combined two units is deemed to be BART. Should PEF
choose not to shutdown Units 1 and 2, PEF must install SO2
and NOX control technology to meet the limits as specified
in the permit and summarized below, by January 1, 2018. However, the
permit authorizing PEF to construct the SO2 control, should
that option be selected, assumes that this control will be a dry FGD
and limits PM to 0.015 lb/MMBtu at both units. FDEP has allowed PEF
until January 1, 2015, to choose the BART option that it wishes to
follow. Under the option to shutdown by December 31, 2020, BART is
compliance with the following operational and emissions limiting
standards:
    SO2: Existing controls for Units 1 and 2. (Permit No. 0170004-017-
AC.)
    NOX: Existing controls for Units 1 and 2. (Permit No. 0170004-017-
AC.)
    PM: 0.04 lb/MMBtu for combined emissions from Units 1 and 2.
Compliance demonstrated by stack test.
    Under the option to continue operation of Units 1 and 2, BART is
compliance with the following operational and emissions limiting
standards:
    SO2: 0.15 lb/MMBtu or 95 percent reduction for Units 1 and 2
    NOX: 0.09 lb/MMBtu for Units 1 and 2
    PM: 0.015 lb/MMBtu for combined emissions from Units 1 and 2.
Compliance demonstration by a stack test.
9. EPA Assessment of BART Determinations
    EPA proposes to approve Florida's BART analyses and determinations
for the units identified above because the analyses were conducted in a
manner that is consistent with EPA's BART Guidelines and EPA's Air
Pollution Control Cost Manual and because Florida's conclusions reflect
a reasonable application of EPA's guidance to these sources.

C. Reliance on CAIR

    Although Florida no longer relies on CAIR to satisfy regional haze
requirements for any sources within the State, the underlying emissions
inventories and projections of reductions from upwind states continue
to include assumptions based on the implementation of CAIR. Given the
requirement in 40 CFR 51.308(d)(1)(vi) that states must take into
account the visibility improvement that is expected to result from the
implementation of other CAA requirements, Florida based its RPGs, in
part, on the emissions reductions expected to be achieved by CAIR and
other measures being implemented across the southeast region as modeled
for Florida by the Visibility Improvement State and Tribal Association
of the Southeast (VISTAS).\14\ As CAIR has been remanded by the DC
Circuit, some of the assumptions underlying the development of this
element of the RPGs may change. EPA is proposing to determine that this
reliance on CAIR in upwind states in the underlying analysis does not
require EPA to withhold full approval of Florida's regional haze SIP.
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    \14\ The VISTAS Regional Planning Organization (RPO) is a
collaborative effort of state governments, tribal governments, and
various federal agencies established to initiate and coordinate
activities associated with the management of regional haze,
visibility and other air quality issues in the southeastern United
States. Member state and tribal governments include: Alabama,
Florida, Georgia, Kentucky, Mississippi, North Carolina, South
Carolina, Tennessee, Virginia, West Virginia, and the Eastern Band
of the Cherokee Indians.
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    As explained above, the 2008 remand of CAIR was followed by a 2012
decision in EME Homer Generation, L.P. v. EPA, No. 11-1302 (DC Cir.,
August 21, 2012), to vacate the Transport Rule and keep CAIR in place
pending the promulgation of a valid replacement rule. In this unique
circumstance, EPA believes that full approval of the SIP submission is
appropriate. To the extent that Florida is relying on emissions
reductions associated with the implementation of CAIR in other states
in its regional haze SIP, the recent

directive from the DC Circuit in EME Homer ensures that the reductions
associated with CAIR will be sufficiently permanent and enforceable for
the necessary time period. EPA has been ordered by the court to develop
a new rule and the opinion makes clear that after promulgating that new
rule, EPA must provide states an opportunity to draft and submit SIPs
to implement that rule. Thus, CAIR cannot be replaced until EPA has
promulgated a final rule through a notice-and-comment rulemaking
process, states have had an opportunity to draft and submit regional
haze SIPs, EPA has reviewed the SIPs to determine if they can be
approved, and EPA has taken action on the SIPs, including promulgating
a federal implementation plan if appropriate. These steps alone will
take many years, even with EPA and the states acting expeditiously. The
court's clear instruction to EPA that it must continue to administer
CAIR until a ``valid replacement'' exists provides an additional
backstop; by definition, any rule that replaces CAIR and meets the
court's direction would require upwind states to eliminate significant
downwind contributions.
    Further, in vacating the Transport Rule and requiring EPA to
continue administering CAIR, the DC Circuit emphasized that the
consequences of vacating CAIR ``might be more severe now in light of
the reliance interests accumulated over the intervening four years.''
EME Homer, slip op. at 60. The accumulated reliance interests include
the interests of states who reasonably assumed they could rely on
reductions associated with CAIR to meet certain regional haze
requirements. For these reasons also, EPA believes it is appropriate to
allow Florida to rely on reductions associated with CAIR in other
states as sufficiently permanent and enforceable pending a valid
replacement rule for purposes such as evaluating RPGs in the regional
haze program. Following promulgation of the replacement rule, EPA will
review regional haze SIPs as appropriate to identify whether there are
any issues that need to be addressed.
    Finally, unlike the enforceable emissions limitations and other