Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 73369 

Signing Authority 

The Secretary of Veterans Affairs, or 

designee, approved this document and 

authorized the undersigned to sign and 

submit the document to the Office of the 

Federal Register for publication 

electronically as an official document of 

the Department of John R. Gingrich, 

Chief of Staff, Department of Veterans 

Affairs, approved this document on 

December 4, 2012, for publication. 

List of Subjects in 38 CFR Part 3 

Administrative practice and 

procedure, Claims, Disability benefits, 

Health care, Veterans, Vietnam. 

Dated: December 5, 2012. 

Robert C. McFetridge, 

Director, Regulation Policy and Management, 

Office of the General Counsel, Department 

of Veterans Affairs. 

For the reasons set out in the 

preamble, VA proposes to amend 38 

CFR part 3 as follows: 

PART 3—ADJUDICATION 

1. The authority citation for part 3, 

subpart A continues to read as follows: 

Authority: 38 U.S.C. 501(a), unless 

otherwise noted. 

2. Revise § 3.310 by adding paragraph 

(d), to read as follows: 

§ 3.310 Disabilities that are proximately 

due to, or aggravated by, service-connected 

disease or injury. 

* * * * * 

(d) Traumatic brain injury. (1) In a 

veteran who has a service-connected 

traumatic brain injury, the following 

shall be held to be the proximate result 

of the service-connected traumatic brain 

injury (TBI), in the absence of clear 

evidence to the contrary: 

(i) Parkinsonism following moderate 

or severe TBI; 

(ii) Unprovoked seizures following 

moderate or severe TBI; 

(iii) Dementias (presenile dementia of 

the Alzheimer type and post-traumatic 

dementia) if manifest within 15 years 

following moderate or severe TBI; 

(iv) Depression if manifest within 3 

years of moderate or severe TBI, or 

within 12 months of mild TBI; or 

(v) Diseases of hormone deficiency 

that result from hypothalamo-pituitary 

changes if manifest within 12 months of 

moderate or severe TBI. 

(2) Neither the severity levels nor the 

time limits in paragraph (d)(1) of this 

section preclude a finding of service 

connection for conditions shown by 

evidence to be proximately due to 

service-connected TBI. If a claim does 

not meet the requirements of paragraph 

(d)(1) with respect to the time of 

manifestation or the severity of the TBI, 

or both, VA will develop and decide the 

claim under generally applicable 

principles of service connection without 

regard to paragraph (d)(1). 

(3)(i) For purposes of this section VA 

will use the following table for 

determining the severity of a TBI: 

Mild Moderate Severe 

Normal structural imaging ...................................................... Normal or abnormal structural imaging Normal or abnormal structural imaging. 

LOC = 0–30 min ..................................................................... LOC >30 min and <24 hours ................. LOC >24 hrs. 

AOC = a moment up to 24 hrs .............................................. AOC >24 hours. Severity based on other criteria. 

PTA = 0–1 day ....................................................................... PTA >1 and <7 days .............................. PTA > 7 days. 

GCS = 13–15 ......................................................................... GCS = 9–12 ........................................... GCS = 3–8. 

Note: The factors considered are: 

Structural imaging of the brain. 

LOC—Loss of consciousness. 

AOC—Alteration of consciousness/mental state. 

PTA—Post-traumatic amnesia. 

GCS—Glasgow Coma Scale. (For purposes of injury stratification, the Glasgow Coma Scale is measured at or after 24 hours.) 

(ii) The determination of the severity 

level under this paragraph is based on 

the TBI symptoms at the time of injury 

or shortly thereafter, rather than the 

current level of functioning. VA will not 

require that the TBI meet all the criteria 

listed under a certain severity level in 

order to classify the TBI at that severity 

level. If a TBI meets the criteria relating 

to LOC, PTA, or GCS in more than one 

severity level, then VA will rank the TBI 

at the highest of those levels. 

(Authority: 38 U.S.C. 501, 1110 and 1131) 

[FR Doc. 2012–29709 Filed 12–7–12; 8:45 am] 

BILLING CODE 8320–01–P 

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. 

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 

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73370 Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 

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). 

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 

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Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 73371 

2See footnote 1, above. 

3Today’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. 

4That 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. 

5Emissions unit numbers reflect the numbering 

system used by FDEP, which may differ from the 

facilities’ numbering methodology. 

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. 

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

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

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. 

TABLE 1—FACILITIES SUBJECT TO

REASONABLE PROGRESS ANALYSIS

WITH UNIT(S) 5 ALSO SUBJECT TO

CAIR 

[Italicized units are also subject to BART] 

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). 

TABLE 2—BART-ELIGIBLE FACILITIES

WITH UNIT(S) SUBJECT TO CAIR 

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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6Florida’s development and use of the Q/d metric 

is discussed in EPA’s May 25, 2012, proposal at 77 

FR 31251. 

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) coalfired 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. 

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 costeffective, 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 nonair 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 PEFCrystal 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, drybottom, 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 

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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 nonair 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 fuelfired 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 

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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. Federallyenforceable 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 costeffectiveness 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. Costeffectiveness using the emissions from 

the latest full year, 2011, was also 

calculated to contrast the costeffectiveness from the 2002 baseline 

year and was estimated at $11,921 per 

ton of SO2 removed. FDEP does not 

consider these reasonable costeffectiveness 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. 

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7On November 29, 2012, EPA finalized full 

approval of the BART determinations addressed in 

the April 13, 2012, draft regional haze SIP 

amendment. 

8Florida 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. 

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). 

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. 

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 

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9EPA 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. 

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 gasfired 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 postcombustion 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 costeffectiveness 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. 

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 costeffectiveness 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. 

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Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 73377 

10EPA 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. 

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’’ gasfired 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 postcombustion 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 coalfired 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 costeffectiveness 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. 

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 costeffectiveness 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 costeffectiveness 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 

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73378 Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 

11EPA 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. 

and annual operating costs of 

approximately $6 million. FDEP 

concluded that SCR was not costeffective 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 BARTsubject 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

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 postcombustion 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 costeffectiveness 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 

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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 costeffective 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 nonair 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 costeffectiveness 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 

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73380 Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 

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 postcombustion 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 addon 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 addon 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 costeffectiveness 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 costeffectiveness 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 onspecification 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. 

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12Saint 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. 

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

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 costeffective 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 coalfired 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 lowsulfur 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 lowsulfur 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 

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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 costeffectiveness 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 multicyclone 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 multicyclones 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 

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Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 73383 

13EPA’s RACT/BACT/LAER Clearinghouse is 

located at: http://cfpub.epa.gov/RBLC/ 

index.cfm?action=Home.Home&lang=en. 

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 multicyclones 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. 

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, 

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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 costeffectiveness 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 costeffectiveness 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 costeffectiveness 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 

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Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 73385 

14The 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. 

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 costeffectiveness 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 costeffectiveness 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 costeffective 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. 

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 

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73386 Federal Register / Vol. 77, No. 237 / Monday, December 10, 2012 / Proposed Rules 

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 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R03–OAR–2010–0143; FRL–9759–5] 

Approval and Promulgation of Air 

Quality Implementation Plans; 

Maryland; the 2002 Base Year 

Inventory for the Baltimore, MD 

Nonattainment Area for the 1997 Fine 

Particulate Matter National Ambient Air 

Quality Standard 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

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