
[Federal Register Volume 77, Number 237 (Monday, December 10, 2012)]
[Proposed Rules]
[Pages 73369-73386]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[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

[[Page 73370]]

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: R4-RDS@epa.gov.
    3. Fax: 404-562-9019.
    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 (404) 562-9031 and by electronic mail at 
notarianni.michele@epa.gov.

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

[[Page 73371]]

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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[[Page 73372]]

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

[[Page 73373]]

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

[[Page 73374]]

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.

[[Page 73375]]

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.
---------------------------------------------------------------------------

    \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

[[Page 73376]]

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.

[[Page 73377]]

    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

[[Page 73378]]

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

[[Page 73379]]

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

[[Page 73380]]

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.

[[Page 73381]]

    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

[[Page 73382]]

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

[[Page 73383]]

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.
---------------------------------------------------------------------------

    \13\ EPA's RACT/BACT/LAER Clearinghouse is located at: http://cfpub.epa.gov/RBLC/index.cfm?action=Home.Home⟨=en.
---------------------------------------------------------------------------

    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,

[[Page 73384]]

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

[[Page 73385]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 73386]]

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 
enforceable measures in the LTS, RPGs are not directly enforceable. See 
64 FR 35733, 40 CFR 51.308(d)(1)(v). The data provided by Florida 
indicate that EPA can reasonably expect the projected SO2 
emissions reductions in 2018 to be sufficient to meet the projected 
RPGs. As noted in the May 25, 2012, proposal, EPA believes that the 
five-year progress report is the appropriate time to address any 
changes, if necessary, to the RPG demonstration and/or the LTS. EPA 
expects that this demonstration will address the impacts on the RPGs of 
any needed adjustments to the projected 2018 emissions due to updated 
information on the emissions for EGUs and other sources and source 
categories. If this assessment determines that an adjustment to the 
regional haze plan is necessary, EPA regulations require a SIP revision 
within a year of the five-year progress report. See 40 CFR 
51.308(h)(4).

IV. What action is EPA taking?

    EPA is proposing a full approval of the BART and reasonable 
progress determinations identified in Tables 1 and 2, above. In 
addition, EPA proposes to find that Florida's September 17, 2012, 
regional haze SIP 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 regional haze SIP now meets all of the applicable regional 
haze requirements as set forth in sections 169A and 169B of the CAA and 
in 40 CFR 51.300-308. EPA is therefore withdrawing the previously 
proposed limited disapproval of Florida's entire regional haze SIP and 
is now proposing full approval.

V. Statutory and Executive Order Reviews

    Under the CAA, the Administrator is required to approve a SIP 
submission that complies with the provisions of the Act and applicable 
federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in 
reviewing SIP submissions, EPA's role is to approve state choices, 
provided that they meet the criteria of the CAA. Accordingly, this 
proposed action merely approves state law as meeting federal 
requirements and does not impose additional requirements beyond those 
imposed by state law. For that reason, this proposed action:
     Is not a ``significant regulatory action'' subject to 
review by the Office of Management and Budget under Executive Order 
12866 (58 FR 51735, October 4, 1993);
     Does not impose an information collection burden under the 
provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq.);
     Is certified as not having a significant economic impact 
on a substantial number of small entities under the Regulatory 
Flexibility Act (5 U.S.C. 601 et seq.);
     Does not contain any unfunded mandate or significantly or 
uniquely affect small governments, as described in the Unfunded 
Mandates Reform Act of 1995 (Pub. L. 104-4);
     Does not have Federalism implications as specified in 
Executive Order 13132 (64 F43255, August 10, 1999);
     Is not an economically significant regulatory action based 
on health or safety risks subject to Executive Order 13045 (62 FR 
19885, April 23, 1997);
     Is not a significant regulatory action subject to 
Executive Order 13211 (66 FR 28355, May 22, 2001);
     Is not subject to requirements of Section 12(d) of the 
National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 
note) because application of those requirements would be inconsistent 
with the CAA; and
     Does not provide EPA with the discretionary authority to 
address, as appropriate, disproportionate human health or environmental 
effects, using practicable and legally permissible methods, under 
Executive Order 12898 (59 FR 7629, February 16, 1994).
    In addition, this proposed rule does not have tribal implications 
as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), 
because the SIP is not approved to apply in Indian country located in 
the state, and EPA notes that it will not impose substantial direct 
costs on tribal governments or preempt tribal law.

List of Subjects in 40 CFR Part 52

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

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

    Dated: November 30, 2012.
A. Stanley Meiburg,
Acting Regional Administrator, Region 4.
[FR Doc. 2012-29764 Filed 12-7-12; 8:45 am]
BILLING CODE 6560-50-P


